[Federal Register Volume 77, Number 159 (Thursday, August 16, 2012)]
[Rules and Regulations]
[Pages 49489-49600]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 2012-16806]



[[Page 49489]]

Vol. 77

Thursday,

No. 159

August 16, 2012

Part II





Environmental Protection Agency





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40 CFR Parts 60 and 63





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

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

[[Page 49490]]


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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Parts 60 and 63

[EPA-HQ-OAR-2010-0505; FRL-9665-1]
RIN 2060-AP76


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

AGENCY: Environmental Protection Agency (EPA).

ACTION: Final rule.

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

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

ADDRESSES: The EPA has established a docket for this action under 
Docket ID. No. EPA-HQ-OAR-2010-0505. All documents in the docket are 
listed on the http://www.regulations.gov Web site. Although listed in 
the index, some information is not publicly available, e.g., 
confidential business information or other information whose disclosure 
is restricted by statute. Certain other material, such as copyrighted 
material, is not placed on the Internet and will be publicly available 
only in hard copy form. Publicly available docket materials are 
available either electronically through http://www.regulations.gov or 
in hard copy at the EPA's Docket Center, Public Reading Room, EPA West 
Building, Room Number 3334, 1301 Constitution Avenue NW., Washington, 
DC 20004. This Docket Facility is open from 8:30 a.m. to 4:30 p.m. 
Eastern Standard Time, Monday through Friday, excluding legal holidays. 
The telephone number for the Public Reading Room is (202) 566-1744, and 
the telephone number for the Air Docket is (202) 566-1742.

FOR FURTHER INFORMATION CONTACT: For further information about this 
final action, contact Mr. Bruce Moore, Sector Policies and Programs 
Division (E143-05), Office of Air Quality and Standards, Environmental 
Protection Agency, Research Triangle Park, North Carolina 27711, 
telephone number: (919) 541-5460; facsimile number: (919) 685-3200; 
email address: moore.bruce@epa.gov. For additional contact information, 
see the following SUPPLEMENTARY INFORMATION section.

SUPPLEMENTARY INFORMATION: For specific information regarding risk 
assessment and exposure modeling methodology, contact Mr. Mark Morris, 
Health and Environmental Impacts Division (C504-06), Office of Air 
Quality Planning and Standards, U.S. Environmental Protection Agency, 
Research Triangle Park, NC 27711; telephone number (919) 541-5416; fax 
number: (919) 541-0840; and email address: morris.mark@epa.gov.
    Organization of This Document. The information presented in this 
preamble is organized as follows:

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

[[Page 49491]]

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

I. Preamble Acronyms and Abbreviations

    Several acronyms and terms used to describe industrial processes, 
data inventories and risk modeling are included in this preamble. While 
this may not be an exhaustive list, to ease the reading of this 
preamble and for reference purposes, the following terms and acronyms 
are defined here:

API American Petroleum Institute
BACT Best Available Control Technology
BDT Best Demonstrated Technology
bpd Barrels Per Day
BMP Best Management Practice
BSER Best System of Emission Reduction
BTEX Benzene, Ethylbenzene, Toluene and Xylene
CAA Clean Air Act
CBM Coal Bed Methane
CDX Central Data Exchange
CEDRI Compliance and Emissions Data Reporting Interface
CFR Code of Federal Regulations
CO Carbon Monoxide
CO2 Carbon Dioxide
CO2e Carbon Dioxide Equivalent
DOE United States Department of Energy
e-GGRT Electronic Greenhouse Gas Reporting Tool
EPA Environmental Protection Agency
ERPG Emergency Response Planning Guidelines
ERT Electronic Reporting Tool
GCG Gas Condensate Glycol
GHG Greenhouse Gas
GOR Gas to Oil Ratio
GWP Global Warming Potential
HAP Hazardous Air Pollutants
HEM-3 Human Exposure Model, version 3
HI Hazard Index
HP Horsepower
HQ Hazard Quotient
H2S Hydrogen Sulfide
ICR Information Collection Request
IPCC Intergovernmental Panel on Climate Change
IRIS Integrated Risk Information System
km Kilometer
kW Kilowatts
LAER Lowest Achievable Emission Rate
lb Pounds
LDAR Leak Detection and Repair
MACT Maximum Achievable Control Technology
MACT Code NEI code used to identify processes included in a source 
category
Mcf Thousand Cubic Feet
Mg/yr Megagrams per year
MIR Maximum Individual Risk
MIRR Monitoring, Inspection, Recordkeeping and Reporting
MMtCO2e Million Metric Tons of Carbon Dioxide Equivalents
NAAQS National Ambient Air Quality Standards
NAC/AEGL National Advisory Committee for Acute Exposure Guideline 
Levels for Hazardous Substances
NAICS North American Industry Classification System
NAS National Academy of Sciences
NATA National Air Toxics Assessment
NEI National Emissions Inventory
NEMS National Energy Modeling System
NESHAP National Emissions Standards for Hazardous Air Pollutants
NGL Natural Gas Liquids
NIOSH National Institutes for Occupational Safety and Health
NOX Oxides of Nitrogen
NRC National Research Council
NSPS New Source Performance Standards
NSR New Source Review
NTTAA National Technology Transfer and Advancement Act
OAQPS Office of Air Quality Planning and Standards
OMB Office of Management and Budget
PB-HAP Hazardous air pollutants known to be persistent and bio-
accumulative in the environment
PFE Potential for Flash Emissions
PM Particulate Matter
PM2.5 Particulate Matter (2.5 microns and less)
POM Polycyclic Organic Matter
ppm Parts per Million
ppmv Parts per Million by Volume
PSIG Pounds per Square Inch Gauge
PSIA Pounds per Square Inch Absolute
PTE Potential to Emit
QA Quality Assurance
RACT Reasonably Available Control Technology
RBLC RACT/BACT/LAER Clearinghouse
REC Reduced Emissions Completions
REL California EPA Reference Exposure Level
RFA Regulatory Flexibility Act
RfC Reference Concentration
RfD Reference Dose
RIA Regulatory Impact Analysis
RICE Reciprocating Internal Combustion Engines
RTR Residual Risk and Technology Review
SAB Science Advisory Board
SBREFA Small Business Regulatory Enforcement Fairness Act
SCC Source Classification Codes
scfh Standard Cubic Feet Per Hour
scfm Standard Cubic Feet Per Minute
scm Standard Cubic Meters
scmd Standard Cubic Meters per Day
SCOT Shell Claus Offgas Treatment
SIP State Implementation Plan
SISNOSE Significant Economic Impact on a Substantial Number of Small 
Entities
S/L/T State and Local and Tribal Agencies
SO2 Sulfur Dioxide
SSM Startup, Shutdown and Malfunction
STEL Short-term Exposure Limit
TLV Threshold Limit Value
TOSHI Target Organ-Specific Hazard Index
tpy Tons per Year
TRIM Total Risk Integrated Modeling System
TRIM.FaTE A spatially explicit, compartmental mass balance model 
that describes the movement and transformation of pollutants over 
time, through a user-defined, bounded system that includes both 
biotic and abiotic compartments
TSD Technical Support Document
UF Uncertainty Factor
UMRA Unfunded Mandates Reform Act
URE Unit Risk Estimate
VCS Voluntary Consensus Standards
VOC Volatile Organic Compounds
VRU Vapor Recovery Unit

II. General Information

A. Executive Summary

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

[[Page 49492]]

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

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

[[Page 49493]]

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

B. Does this action apply to me?

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

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

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

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

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

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

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

E. Judicial Review

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

[[Page 49494]]

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

III. Background Information on the NSPS and NESHAP

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

1. What is the statutory authority for the NSPS?
    Section 111 of the CAA requires the EPA Administrator to list 
categories of stationary sources, if such sources cause or contribute 
significantly to air pollution, which may reasonably be anticipated to 
endanger public health or welfare. The EPA must then issue performance 
standards for such source categories. Whereas CAA section 112 standards 
are issued for new and existing stationary sources, standards of 
performance are issued for new and modified stationary sources. These 
standards are referred to as NSPS. The EPA has the authority to define 
the source categories, determine the pollutants for which standards 
should be developed, identify the facilities within each source 
category to be covered and set the emission level of the standards.
    CAA section 111(b)(1)(B) requires the EPA to ``at least every 8 
years review and, if appropriate, revise'' performance standards. 
However, the Administrator need not review any such standard if the 
``Administrator determines that such review is not appropriate in light 
of readily available information on the efficacy'' of the standard. 
When conducting a review of an existing performance standard, the EPA 
has authority to revise that standard to add emission limits for 
pollutants or emission sources not currently regulated for that source 
category.
    In setting or revising a performance standard, CAA section 
111(a)(1) provides that performance standards are to ``reflect the 
degree of emission limitation achievable through the application of the 
BSER which (taking into account the cost of achieving such reduction 
and any nonair quality health and environmental impact and energy 
requirements) the Administrator determines has been adequately 
demonstrated.'' In this notice, we refer to this level of control as 
the BSER. In determining BSER, we typically conduct a technology review 
that identifies what emission reduction systems exist and how much they 
reduce air pollution, in practice. Next, for each control system 
identified, we evaluate its costs, secondary air benefits (or 
disbenefits) resulting from energy requirements and nonair quality 
impacts such as solid waste generation. Based on our evaluation, we 
would determine BSER. The resultant standard is usually a numerical 
emissions limit, expressed as a performance level (i.e., a rate-based 
standard or percent control), that reflects the BSER. Although such 
standards are based on the BSER, the EPA may not prescribe a particular 
technology that must be used to comply with a performance standard, 
except in instances where the Administrator determines it is not 
feasible to prescribe or enforce a standard of performance. Typically, 
sources remain free to select any control measures that will meet the 
emission limits. Upon promulgation, an NSPS becomes a national standard 
to which all new sources must comply.
2. What is the statutory authority for the NESHAP?
    Section 112 of the CAA establishes a two-stage regulatory process 
to address emissions of HAP from stationary sources. In the first 
stage, after the EPA has identified categories of sources emitting one 
or more of the HAP listed in section 112(b) of the CAA, section 112(d) 
of the CAA calls for us to promulgate NESHAP for those sources. ``Major 
sources'' are those that emit or have the potential to emit (PTE) 10 
tpy or more of a single HAP or 25 tpy or more of any combination of 
HAP. For major sources, the technology-based emission standards must 
reflect the maximum degree of emission reductions of HAP achievable 
(after considering cost, energy requirements and nonair quality health 
and environmental impacts) and are commonly referred to as MACT 
standards.
    MACT standards are set to reflect application of measures, 
processes, methods, systems or techniques, including, but not limited 
to, measures which, (1) reduce the volume of or eliminate pollutants 
through process changes, substitution of materials or other 
modifications, (2) enclose systems or processes to eliminate emissions, 
(3) capture or treat pollutants when released from a process, stack, 
storage or fugitive emissions point, (4) are design, equipment, work 
practice or operational standards (including requirements for operator 
training or certification) or (5) are a combination of the above. CAA 
sections 112(d)(2)(A)-(E). A MACT standard may take the form of a 
design, equipment, work practice or operational standard where the EPA 
first determines either that, (1) a pollutant cannot be emitted through 
a conveyance designed and constructed to emit or capture the pollutant 
or that any requirement for or use of such a conveyance would be 
inconsistent with law or (2) the application of measurement methodology 
to a particular class of sources is not practicable due to 
technological and economic limitations. CAA sections 112(h)(1),(2).
    The MACT ``floor'' is the minimum control level allowed for MACT 
standards promulgated under CAA section 112(d)(3) and may not be based 
on cost considerations. For new sources, the MACT floor cannot be less 
stringent than the emission control that is achieved in practice by the 
best-controlled similar source. The MACT floors for existing sources 
can be less stringent than floors for new sources, but cannot be less 
stringent than the average emission limitation achieved by the best-
performing 12 percent of existing sources in the category or 
subcategory (or the best-performing five sources for categories or 
subcategories with fewer than 30 sources). In developing MACT 
standards, we must also consider control options that are more 
stringent than the floor. We may establish standards more stringent 
than the floor based on the consideration of the cost of achieving the 
emissions reductions, any nonair quality health and environmental 
impacts and energy requirements.
    The EPA is then required to review these technology-based standards 
and to revise them ``as necessary (taking into account developments in 
practices, processes, and control technologies)'' no less frequently 
than every 8 years, under CAA section 112(d)(6). In conducting this 
review, the EPA is not obliged to completely recalculate the prior MACT 
determination. NRDC v. EPA, 529 F.3d 1077, 1084 (D.C. Cir. 2008).

[[Page 49495]]

    The second stage in standard-setting focuses on reducing any 
remaining ``residual'' risk according to CAA section 112(f). This 
provision requires, first, that the EPA prepare a Report to Congress 
discussing (among other things) methods of calculating risk posed (or 
potentially posed) by sources after implementation of the MACT 
standards, the public health significance of those risks and the EPA's 
recommendations as to legislation regarding such remaining risk. The 
EPA prepared and submitted this report (Residual Risk Report to 
Congress, EPA-453/R-99-001) in March 1999. Congress did not act in 
response to the report, thereby triggering the EPA's obligation under 
CAA section 112(f)(2) to analyze and address residual risk.
    CAA section 112(f)(2) requires us to determine for source 
categories subject to MACT standards, whether the emissions standards 
provide an ample margin of safety to protect public health. CAA section 
112(f)(2) expressly preserves our use of a two-step process for 
developing standards to address any residual risk and our 
interpretation of ``ample margin of safety'' developed in the National 
Emission Standards for Hazardous Air Pollutants: Benzene Emissions from 
Maleic Anhydride Plants, Ethylbenzene/Styrene Plants, Benzene Storage 
Vessels, Benzene Equipment Leaks, and Coke By-Product Recovery Plants 
(Benzene NESHAP) (54 FR 38044, September 14, 1989). The first step in 
this process is the determination of acceptable risk. The second step 
provides for an ample margin of safety to protect public health, which 
is the level at which the standards must be set (unless a more 
stringent standard is required to prevent an adverse environmental 
effect, taking into consideration costs, energy, safety and other 
relevant factors).
    If the MACT standards for HAP that are ``classified as a known, 
probable, or possible human carcinogen do not reduce lifetime excess 
cancer risks to the individual most exposed to emissions from a source 
in the category or subcategory to less than 1-in-1 million,'' the EPA 
must promulgate residual risk standards for the source category (or 
subcategory), as necessary, to provide an ample margin of safety to 
protect public health. In doing so, the EPA may adopt standards equal 
to existing MACT standards if the EPA determines that the existing 
standards are sufficiently protective. NRDC v. EPA, 529 F.3d 1077, 1083 
(D.C. Cir. 2008) (``If EPA determines that the existing technology-
based standards provide an `ample margin of safety,' then the Agency is 
free to readopt those standards during the residual risk 
rulemaking.''). As mentioned, the EPA must also adopt more stringent 
standards, if necessary, to prevent an adverse environmental effect,\1\ 
but must consider cost, energy, safety and other relevant factors in 
doing so.
---------------------------------------------------------------------------

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

    The terms ``individual most exposed,'' ``acceptable level,'' and 
``ample margin of safety'' are not specifically defined in the CAA. 
However, CAA section 112(f)(2)(B) preserves the interpretation set out 
in the Benzene NESHAP, and the United States Court of Appeals for the 
District of Columbia Circuit has concluded that the EPA's 
interpretation of CAA section 112(f)(2) is a reasonable one. See NRDC 
v. EPA, 529 F.3d at 1083 (``[S]ubsection 112(f)(2)(B) expressly 
incorporates the EPA's interpretation of the Clean Air Act from the 
Benzene standard, complete with a citation to the Federal Register''). 
See, also, A Legislative History of the Clean Air Act Amendments of 
1990, volume 1, p. 877 (Senate debate on Conference Report). We 
notified Congress in the Residual Risk Report to Congress that we 
intended to use the Benzene NESHAP approach in making CAA section 
112(f) residual risk determinations (EPA-453/R-99-001, p. ES-11).

    In the Benzene NESHAP, we stated as an overall objective:
    * * * in protecting public health with an ample margin of 
safety, we strive to provide maximum feasible protection against 
risks to health from hazardous air pollutants by, (1) protecting the 
greatest number of persons possible to an individual lifetime risk 
level no higher than approximately 1-in-1 million; and (2) limiting 
to no higher than approximately 1-in-10 thousand [i.e., 100-in-1 
million] the estimated risk that a person living near a facility 
would have if he or she were exposed to the maximum pollutant 
concentrations for 70 years.

The agency also stated in the Residual Risk Report to Congress that 
``The EPA also considers incidence (the number of persons estimated to 
suffer cancer or other serious health effects as a result of exposure 
to a pollutant) to be an important measure of the health risk to the 
exposed population. Incidence measures the extent of health risk to the 
exposed population as a whole, by providing an estimate of the 
occurrence of cancer or other serious health effects in the exposed 
population.'' The agency went on to conclude that ``estimated incidence 
would be weighed along with other health risk information in judging 
acceptability.'' As explained more fully in our Residual Risk Report to 
Congress, the EPA does not define ``rigid line[s] of acceptability,'' 
but considers rather broad objectives to be weighed with a series of 
other health measures and factors (EPA-453/R-99-001, p. ES-11). The 
determination of what represents an ``acceptable'' risk is based on a 
judgment of ``what risks are acceptable in the world in which we live'' 
(Residual Risk Report to Congress, p. 178, quoting the Vinyl Chloride 
decision at 824 F.2d 1165) recognizing that our world is not risk-free.
    In the Benzene NESHAP, we stated that ``EPA will generally presume 
that if the risk to [the maximum exposed] individual is no higher than 
approximately 1-in-10 thousand, that risk level is considered 
acceptable.'' 54 FR 38045. We discussed the maximum individual lifetime 
cancer risk (or maximum individual risk (MIR)) as being ``the estimated 
risk that a person living near a plant would have if he or she were 
exposed to the maximum pollutant concentrations for 70 years.'' Id. We 
explained that this measure of risk ``is an estimate of the upper bound 
of risk based on conservative assumptions, such as continuous exposure 
for 24 hours per day for 70 years.'' Id. We acknowledge that maximum 
individual lifetime cancer risk ``does not necessarily reflect the true 
risk, but displays a conservative risk level which is an upper-bound 
that is unlikely to be exceeded.'' Id. Understanding that there are 
both benefits and limitations to using maximum individual lifetime 
cancer risk as a metric for determining acceptability, we acknowledged 
in the 1989 Benzene NESHAP that ``consideration of maximum individual 
risk * * * must take into account the strengths and weaknesses of this 
measure of risk.'' Id. Consequently, the presumptive risk level of 100-
in-1 million (1-in-10 thousand) provides a benchmark for judging the 
acceptability of maximum individual lifetime cancer risk, but does not 
constitute a rigid line for making that determination.
    The agency also explained in the 1989 Benzene NESHAP the following: 
``In establishing a presumption for MIR, rather than a rigid line for 
acceptability, the Agency intends to weigh it with a series of other 
health measures and factors. These include the overall incidence of 
cancer or other serious health effects within the exposed population, 
the numbers of persons exposed within each individual lifetime risk 
range and associated incidence within, typically, a 50-kilometer (km)

[[Page 49496]]

exposure radius around facilities, the science policy assumptions and 
estimation uncertainties associated with the risk measures, weight of 
the scientific evidence for human health effects, other quantified or 
unquantified health effects, effects due to co-location of facilities 
and co-emission of pollutants.'' Id.
    In some cases, these health measures and factors taken together may 
provide a more realistic description of the magnitude of risk in the 
exposed population than that provided by maximum individual lifetime 
cancer risk alone. As explained in the Benzene NESHAP, ``[e]ven though 
the risks judged `acceptable' by the EPA in the first step of the Vinyl 
Chloride inquiry are already low, the second step of the inquiry, 
determining an `ample margin of safety,' again includes consideration 
of all of the health factors, and whether to reduce the risks even 
further.'' In the ample margin of safety decision process, the agency 
again considers all of the health risks and other health information 
considered in the first step. Beyond that information, additional 
factors relating to the appropriate level are considered, including 
costs and economic impacts of controls, technological feasibility, 
uncertainties and any other relevant factors. Considering all of these 
factors, the agency will establish the standard at a level that 
provides an ample margin of safety to protect the public health, as 
required by CAA section 112(f). See 54 FR 38046.

B. What is the litigation history?

    On January 14, 2009, pursuant to section 304(a)(2) of the CAA, 
WildEarth Guardians and the San Juan Citizens Alliance filed a 
complaint in the United States District Court for the District of 
Columbia and alleged that the EPA failed to meet its obligations under 
CAA sections 111(b)(1)(B), 112(d)(6) and 112(f)(2) to take actions 
relative to the review/revision of the NSPS and the NESHAP with respect 
to the Oil and Natural Gas Production source category. On February 5, 
2010, the Court entered a consent decree that, as successively 
modified, required the EPA to sign by July 28, 2011,\2\ proposed 
standards and/or determinations not to issue standards pursuant to CAA 
sections 111(b)(1)(B), 112(d)(6) and 112(f)(2) and to take final action 
by April 3, 2012. On April 2, 2012, the consent decree was modified to 
change the date for final action to no later than April 17, 2012.
---------------------------------------------------------------------------

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

C. What is the sector-based approach?

    Sector-based approaches are based on integrated assessments of 
industrial operations that consider multiple pollutants in a 
comprehensive and coordinated manner to manage emissions and CAA 
requirements. One of the many ways we can address sector-based 
approaches is by reviewing multiple regulatory programs together 
whenever possible, for example the NSPS and NESHAP, consistent with all 
applicable legal requirements. This approach essentially expands the 
technical analyses on costs and benefits of particular technologies, to 
consider the interactions of rules that regulate sources. The benefit 
of multi-pollutant and sector-based analyses and approaches includes 
the ability to identify optimum strategies, considering feasibility, 
cost impacts and benefits across the different pollutant types while 
streamlining administrative and compliance complexities and reducing 
conflicting and redundant requirements, resulting in added certainty 
and easier implementation of control strategies for the sector under 
consideration. In order to benefit from a sector-based approach for the 
oil and gas industry, the EPA analyzed how the NSPS and NESHAP under 
consideration relate to each other and other regulatory requirements 
currently under review for oil and gas facilities. In this analysis, we 
looked at how the different control requirements that result from these 
requirements interact, including the different regulatory deadlines and 
control equipment requirements that result, the different reporting and 
recordkeeping requirements and opportunities for states to account for 
reductions resulting from this rulemaking in their State Implementation 
Plans (SIP). The requirements analyzed affect criteria pollutants, HAP 
and methane emissions from oil and natural gas processes and cover the 
NSPS and NESHAP reviews.
    As a result of the sector-based approach, this rulemaking will 
reduce conflicting and redundant requirements. Also, the sector-based 
approach streamlines the monitoring, recordkeeping and reporting 
requirements, thus, reducing administrative and compliance complexities 
associated with complying with multiple regulations. In addition, the 
sector-based approach in this rule promotes a comprehensive control 
strategy that maximizes the co-control of multiple regulated pollutants 
while obtaining emission reductions as co-benefits.

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

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

IV. Summary of the Final NSPS Rule

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

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

[[Page 49497]]

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

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

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

[[Page 49498]]

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

[[Page 49499]]

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

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

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

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

A. Gas Well Affected Facilities

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

B. Centrifugal and Reciprocating Compressor Affected Facilities

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

[[Page 49500]]

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

C. Pneumatic Controller Affected Facilities

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

D. Storage Vessel Affected Facilities

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

[[Page 49501]]

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

F. Changes to Notification, Recordkeeping and Reporting Requirements

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

VI. Summary of the Final NESHAP Rules

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

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

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

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

[[Page 49502]]

shutdown and malfunction. Lastly, the final rule revises and adds 
certain testing and monitoring and related notification, recordkeeping 
and reporting requirements and makes certain other minor technical 
revisions to the NESHAP.
1. Standards for Small Glycol Dehydration Units
    In this final rule, we have established MACT standards under CAA 
sections 112(d)(2) and (3) for small glycol dehydration units, which 
were left unregulated in the initial NESHAP. This subcategory consists 
of glycol dehydrators with an actual annual average natural gas 
flowrate less than 85,000 standard cubic meters per day (scmd) or 
actual average benzene emissions less than 0.9 megagrams per year (Mg/
yr). The final MACT standards for small dehydrators at oil and gas 
production facilities require that existing affected sources at a major 
source meet a unit-specific BTEX limit of 3.28 x 10-4 grams 
BTEX/standard cubic meters (scm)-parts per million by volume (ppmv) and 
that new affected sources meet a BTEX limit of 4.66 x 10-6 
grams BTEX/scm-ppmv.
2. Standards for Equipment Leaks
    In the final rule, as a result of our technology review under CAA 
section 112(d)(6), we are revising the leak definition for valves to 
500 ppm, thus requiring the application of the LDAR requirement at this 
lower detection level. This leak definition applies only to valves at 
natural gas processing plants, and not other components.
3. Notification, Recordkeeping and Reporting Requirements
    The final rule revises certain recordkeeping requirements of 40 CFR 
part 63, subpart HH. Specifically, facilities using carbon adsorbers as 
a control device are required to keep records of their carbon 
replacement schedule and records for each carbon replacement. In 
addition, owners and operators are required to keep records of the 
occurrence and duration of each malfunction of operation (i.e., process 
equipment) or the air pollution control equipment and monitoring 
equipment.
    In conjunction with the new MACT standards for small existing 
glycol dehydration units, owners and operators of such affected units 
are required to submit an initial notification within 1 year after they 
become subject to the provisions of this subpart or by October 15, 
2013, whichever is later.
    The final amendments to the NESHAP also include additional 
requirements for the contents of the periodic reports. The periodic 
reports are required to include periodic test results and information 
regarding any carbon replacement events that occurred during the 
reporting period. Additionally, periodic reports are required to 
include the number, duration, and a brief description for each type of 
malfunction which occurred during the reporting period and which caused 
or may have caused any applicable emission limitation to be exceeded. 
The periodic report is also required to include a description of 
actions taken by an owner or operator during a malfunction of an 
affected source to minimize emissions, including actions taken to 
correct a malfunction.

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

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

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

     Pursuant to CAA section 112(d)(2) and (3), we have established 
MACT standards for small glycol dehydrators that were not regulated in 
the initial NESHAP. We have also amended 40 CFR part 63, subpart HHH to 
apply the standards at all times, and made other revisions relative to 
periods of startup, shutdown and malfunction. Lastly, the final rule 
revises and adds certain testing and monitoring and related 
notification, recordkeeping and reporting requirements, as well as 
makes other minor technical revisions to the NESHAP.
    With regard to our CAA section 112(d)(6) review, we conclude that 
there have been no developments in practices processes or control 
technologies for large glycol dehydrators. We also found that the MACT 
standards in 40 CFR part 63, subpart HHH (coupled with the new MACT 
standard for small glycol dehydrators) provide an ample margin of 
safety to protect public health and prevent adverse environmental 
effects. Accordingly, we are re-adopting those standards to satisfy the 
requirements of CAA section 112(f). Thus, our reviews under CAA 
sections 112(d)(6) and 112(f)(2) did not result in any revisions to the 
standards.
1. Standards for Glycol Dehydration Units
    In this final rule, we have established MACT standards for small 
glycol dehydration units in the Natural Gas Transmission and Storage 
source category. This subcategory consists of glycol dehydrators with 
an actual annual average natural gas flowrate less than 283,000 scmd or 
actual average benzene emissions less than 0.9 Mg/yr. The final MACT 
standard for this subcategory of small dehydrators requires existing 
affected sources to meet a unit-specific BTEX emission limit of 3.01 x 
10-4 grams BTEX/scm-ppmv and new affected sources are 
required to meet a BTEX limit of 5.44 x 10-5 grams BTEX/scm-
ppmv.
2. Notification, Recordkeeping and Reporting Requirements
    The final rule revises certain recordkeeping requirements of 40 CFR 
part 63, subpart HHH. Specifically, facilities using carbon adsorbers 
as a control device are required to keep records of their carbon 
replacement schedule and records for each carbon replacement. In 
addition, owners and operators are required to keep records of the 
occurrence and duration of each malfunction of operation (i.e., process 
equipment) or the air pollution control equipment and monitoring 
equipment.
    In conjunction with the promulgation of the MACT standards for 
small glycol dehydration units, the final rule requires that owners and 
operators of such affected units submit an initial notification within 
1 year after the unit becomes subject to the provisions of this

[[Page 49503]]

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

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

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

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

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

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

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

[[Page 49504]]

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

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

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

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

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

[[Page 49505]]

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

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

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

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

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

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

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

[[Page 49506]]

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

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

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

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

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

[[Page 49507]]

deciding whether standards are necessary to reduce risks further. 
Considering all of this information, we conclude that the costs of the 
options analyzed are not reasonable considering the emissions 
reductions and risk reductions potentially achievable with the control 
measures. Thus, we conclude that the MACT standards in 40 CFR part 63, 
subpart HHH (coupled with the new MACT standard for small glycol 
dehydrators) provide an ample margin of safety to protect public health 
and prevent adverse environmental effects. Accordingly, we are re-
adopting those standards to satisfy the requirements of CAA section 
112(f)(2).
3. Changes Made to Amendments Proposed Under the Authority of CAA 
Section 112(d)(6)
    As discussed in detail in the preamble for the proposed rule (76 FR 
52784), we conducted a technology review for glycol dehydration units 
under the authority of CAA section 112(d)(6). We did not identify 
developments in practices, processes and control technologies for large 
glycol dehydration units. As a result of this assessment, we did not 
propose amendments to 40 CFR part 63, subpart HHH. We have not made any 
changes since proposal under the authority of CAA section 112(d)(6).\9\ 
Further discussion on our technology review analysis can be found in 
section X.C of this preamble, and in the Response to Comments document.
---------------------------------------------------------------------------

    \9\ See footnote 6.
---------------------------------------------------------------------------

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

VIII. Compliance Related Issues Common to the NSPS and NESHAP

A. How do the rules address startup, shutdown and malfunction?

    The United States Court of Appeals for the District of Columbia 
Circuit vacated portions of two provisions in the EPA's CAA section 112 
regulations governing the emissions of HAP during periods of SSM. 
Sierra Club v. EPA, 551 F.3d 1019 (D.C. Cir. 2008), cert. denied, 130 
S. Ct. 1735 (U.S. 2010). Specifically, the Court vacated the SSM 
exemption contained in 40 CFR 63.6(f)(1) and 40 CFR 63.6(h)(1), that 
are part of a regulation, commonly referred to as the ``General 
Provisions Rule,'' that the EPA promulgated under section 112 of the 
CAA. When incorporated into CAA section 112(d) regulations for specific 
source categories, these two provisions exempt sources from the 
requirement to comply with the otherwise applicable CAA section 112(d) 
emission standard during periods of SSM.
    As proposed in the NESHAP, we have eliminated the SSM exemption in 
this rule. Consistent with Sierra Club v. EPA, the EPA has established 
standards in both rules that apply at all times. We have also revised 
Table 3 (the NESHAP General Provisions table) in several respects. For 
example, we have eliminated the incorporation of the NESHAP General 
Provisions' requirement that the source develop an SSM plan. We have 
also eliminated or revised certain NESHAP recordkeeping and reporting 
that related to the SSM exemption. The EPA has attempted to ensure that 
we have not included in the regulatory language, for the NSPS and 
NESHAP, any provisions that are inappropriate, unnecessary or redundant 
in the absence of the SSM exemption.
    In establishing the standards in both rules, the EPA has taken into 
account startup and shutdown periods and, for the reasons explained in 
section IX of this preamble for the NSPS and in section X of this 
preamble for the NESHAP, did not establish different standards for 
those periods. Based on the information available in the record about 
actual operations during startups and shutdowns, we believe that 
operations and emissions do not differ from normal operations during 
these periods such that it warrants a separate standard. Therefore, we 
have not proposed different standards for these periods.
    Periods of startup, normal operations and shutdown are all 
predictable and routine aspects of a source's operations. However, by 
contrast, malfunction is defined as a ``sudden, infrequent, and not 
reasonably preventable failure of air pollution control and monitoring 
equipment, process equipment, or a process to operate in a normal or 
usual manner * * * '' (40 CFR 63.2) and as ``any sudden, infrequent, 
and not reasonably preventable failure of air pollution control 
equipment, process equipment, or a process to operate in a normal or 
usual manner * * *'' (40 CFR 60.2). The EPA has determined that CAA 
sections 111 and 112 do not require that emissions that occur during 
periods of malfunction be factored into development of CAA section 111 
or 112 standards.
    CAA section 111 standards--See section III of this preamble for a 
detailed discussion on how the EPA sets or revises CAA section 111 NSPS 
to reflect the degree of emission limitation achievable through the 
application of the BSER.
    CAA section 112 standards--Under CAA section 112, emissions 
standards for new sources must be no less stringent than the level 
``achieved'' by the best controlled similar source and for existing 
sources, generally must be no less stringent than the average emission 
limitation ``achieved'' by the best performing 12 percent of sources in 
the category. Nothing in CAA section 112 directs the agency to consider 
malfunctions in determining the level ``achieved'' by the best 
performing or best controlled sources when setting emission standards. 
Moreover, while the EPA accounts for variability in setting emissions 
standards consistent with the CAA section 112 case law, nothing in that 
case law requires the agency to consider malfunctions as part of that 
analysis. CAA section 112 uses the concept of ``best controlled'' and 
``best performing'' unit in defining the level of stringency that CAA 
section 112 performance standards must meet. Applying the concept of 
``best controlled'' or ``best performing'' to a unit that is 
malfunctioning presents significant difficulties, as malfunctions are 
sudden and unexpected events.
    Further, accounting for malfunctions in setting NESHAP or NSPS 
standards would be difficult, if not impossible, given the myriad 
different types of malfunctions that can occur across all sources in 
the category and given the difficulties associated with predicting or 
accounting for the frequency, degree and duration of various 
malfunctions that might occur. As such, the performance of units that 
are malfunctioning is not ``reasonably'' foreseeable. See, e.g., Sierra 
Club v.

[[Page 49508]]

EPA, 167 F.3d 658, 662 (D.C. Cir. 1999) (``[T]he EPA typically has wide 
latitude in determining the extent of data-gathering necessary to solve 
a problem. We generally defer to an agency's decision to proceed on the 
basis of imperfect scientific information, rather than to `invest the 
resources to conduct the perfect study.' ''); see, also, Weyerhaeuser 
Co. v. Costle, 590 F.2d 1011, 1058 (D.C. Cir. 1978) (``In the nature of 
things, no general limit, individual permit, or even any upset 
provision can anticipate all upset situations. After a certain point, 
the transgression of regulatory limits caused by `uncontrollable acts 
of third parties,' such as strikes, sabotage, operator intoxication or 
insanity, and a variety of other eventualities, must be a matter for 
the administrative exercise of case-by-case enforcement discretion, not 
for specification in advance by regulation.''). In addition, in the 
NESAHP context, the goal of a best controlled or best performing source 
is to operate in such a way as to avoid malfunctions of the source and 
accounting for malfunctions could lead to standards that are 
significantly less stringent than levels that are achieved by a well-
performing non-malfunctioning source. Similarly, in the NSPS context, 
accounting for malfunctions when setting standards of performance under 
CAA section 111, which reflect the degree of emission limitation 
achievable through ``the application of the best system of emission 
reduction'' that the EPA determines is adequately demonstrated could 
lead to standards that are significantly less stringent than levels 
that are achieved by a well-performing non-malfunctioning source. The 
EPA's approach to malfunctions is consistent with CAA section 112 and 
CAA section 111 and is a reasonable interpretation of the statute.
    Finally, the EPA recognizes that even equipment that is properly 
designed and maintained can sometimes fail and that such failure can 
sometimes cause a violation of the relevant emission standard. See, 
e.g., State Implementation Plans: Policy Regarding Excessive Emissions 
During Malfunctions, Startup, and Shutdown (September 20, 1999); Policy 
on Excess Emissions During Startup, Shutdown, Maintenance, and 
Malfunctions (February 15, 1983). The EPA is, therefore, adding to the 
final NSPS and NESHAP an affirmative defense to civil penalties for 
violations of emission standards that are caused by malfunctions. See 
40 CFR 63.761 for sources subject to the Oil and Natural Gas Production 
MACT standards; 40 CFR 63.1271 for sources subject to the Natural Gas 
Transmission and Storage MACT standards (defining ``affirmative 
defense'' to mean, in the context of an enforcement proceeding, a 
response or defense put forward by a defendant, regarding which the 
defendant has the burden of proof, and the merits of which are 
independently and objectively evaluated in a judicial or administrative 
proceeding). We also have added other regulatory provisions to specify 
the elements that are necessary to establish this affirmative defense; 
a source subject to the Oil and Natural Gas Production or Natural Gas 
Transmission and Storage MACT standards must prove by a preponderance 
of the evidence that it has met all of the elements set forth in 40 CFR 
63.762 and a source subject to the Natural Gas Transmission and Storage 
NSPS must prove by a preponderance of the evidence that it has met all 
of the elements set forth in 40 CFR 60.41Da (NSPS). See 40 CFR 22.24. 
The criteria ensure that the affirmative defense is available only 
where the event that causes a violation of the emission standard meets 
the narrow definition of malfunction in 40 CFR 60.2 (NSPS) and 40 CFR 
63.2 (NESHAP), respectively, (sudden, infrequent, not reasonably 
preventable and not caused by poor maintenance and/or careless 
operation). For example, the final NSPS and NESHAP provide that to 
successfully assert the affirmative defense, the source must prove by a 
preponderance of the evidence that the violation ``[w]as caused by a 
sudden, infrequent, and unavoidable failure of air pollution control 
and process equipment, or a process to operate in a normal or usual 
manner. * * *'' The criteria also are designed to ensure that steps are 
taken to correct the malfunction, to minimize emissions in accordance 
with 40 CFR 63.762 for sources subject to the Oil and Natural Gas 
Production MACT standards, 40 CFR 63.1272 for sources subject to the 
Natural Gas Transmission and Storage MACT standards, and 40 CFR 
60.5415(h) for the Standards of Performance for Crude Oil and Natural 
Gas Production, Transmission and Distribution, and to prevent future 
malfunctions. For example, the final NSPS and NESHAP provide that the 
source must prove by a preponderance of the evidence that ``[r]epairs 
were made as expeditiously as possible when a violation occurred * * 
*'' and that ``[a]ll possible steps were taken to minimize the impact 
of the violation on ambient air quality, the environment and human 
health. * * *'' In any judicial or administrative proceeding, the 
Administrator may challenge the assertion of the affirmative defense 
and, if the respondent has not met its burden of proving all of the 
requirements in the affirmative defense, appropriate penalties may be 
assessed in accordance with section 113 of the CAA (see also 40 CFR 
part 22.27).
    The EPA proposed and is now finalizing an affirmative defense in 
the final NSPS and NESHAP in an attempt to balance a tension, inherent 
in many types of air regulations, to ensure adequate compliance, while 
simultaneously recognizing that, despite the most diligent of efforts, 
emission standards may be violated under circumstances beyond the 
control of the source. The EPA must establish emission standards that 
``limit the quantity, rate, or concentration of emissions of air 
pollutants on a continuous basis.'' 42 U.S.C. 7602(k) (defining 
``emission limitation and emission standard''). See, generally, Sierra 
Club v. EPA, 551 F.3d 1019, 1021 (D.C. Cir. 2008). Thus, the EPA is 
required to ensure that CAA section 112 emissions standards are 
continuous. The affirmative defense for malfunction events meets this 
requirement by ensuring that, even where there is a malfunction, the 
emission standard is still enforceable through injunctive relief. While 
``continuous'' standards, on the one hand, are required, there is also 
case law indicating that, in many situations, it is appropriate for the 
EPA to account for the practical realities of technology. For example, 
in Essex Chemical v. Ruckelshaus, 486 F.2d 427, 433 (D.C. Cir. 1973), 
the District of Columbia Circuit acknowledged that, in setting 
standards under CAA section 111, ``variant provisions'' such as 
provisions allowing for upsets during startup, shutdown and equipment 
malfunction ``appear necessary to preserve the reasonableness of the 
standards as a whole and that the record does not support the `never to 
be exceeded' standard currently in force.'' See, also, Portland Cement 
Ass'n v. Ruckelshaus, 486 F.2d 375 (D.C. Cir. 1973). Though intervening 
case law such as Sierra Club v. EPA and the CAA 1977 amendments call 
into question the relevance of these cases today, they support the 
EPA's view that a system that incorporates some level of flexibility is 
reasonable. The affirmative defense simply provides for a defense to 
civil penalties for violations that are proven to be beyond the control 
of the source. By incorporating an affirmative defense, the EPA has 
formalized its approach to upset events. In a Clean

[[Page 49509]]

Water Act setting, the Ninth Circuit required this type of formalized 
approach when regulating ``upsets beyond the control of the permit 
holder.'' Marathon Oil Co. v. EPA, 564 F.2d 1253, 1272-73 (9th Cir. 
1977); see, also, Mont. Sulphur & Chem. Co. v. EPA, 2012 U.S. App. 
LEXIS 1056 (Jan 19, 2012) (rejecting industry argument that reliance on 
the affirmative defense was not adequate). But see Weyerhaeuser Co. v. 
Costle, 590 F.2d at 1057-58 (holding that an informal approach is 
adequate). The affirmative defense provisions give the EPA the 
flexibility to both ensure that its emission standards are 
``continuous,'' as required by 42 U.S.C. 7602(k), and account for 
unplanned upsets and, thus, support the reasonableness of the standard 
as a whole.
    Refer to preamble section IX for the NSPS, preamble section X for 
the NESHAP and the Response to Comments document for both the NSPS and 
the NESHAP, available in the docket, for detailed discussions regarding 
these changes.

B. How do the NSPS and NESHAP provide for compliance assurance?

    The final rule includes various notification, recordkeeping and 
reporting requirements that we believe provide a robust compliance 
assurance program, while reducing burden and streamlining requirements. 
The EPA also considered a variety of innovative compliance approaches 
that could maximize compliance and transparency, while minimizing 
burden on the regulated community and regulators. More detailed 
information on public comments received and the EPA's responses are 
included in sections IX and X of the preamble or in the response to 
comments document.
1. Notification, Recordkeeping and Reporting Requirements
    For well completions, owners or operators are required to submit an 
email notification no later than 2 days prior to each anticipated well 
completion. The notification must identify the owner or operator and 
provide the American Petroleum Institute (API) well number, 
geographical coordinates of the affected wells and the estimated date 
of commencement of the flowback period immediately following 
hydrofracturing. The owner or operator must keep records identifying 
each well completion operation and documenting the portions of the 
flowback period when the gas was recovered, combusted or vented.
    Annually, owners or operators of all affected facilities under the 
NSPS, including gas wells, compressors, pneumatic controllers, storage 
vessels and gas processing plants, must report any deviation from the 
NSPS requirements during the reporting period. Each annual report must 
include a signed certification by a senior company official that 
attests to the truth, accuracy and completeness of the report. For 
affected gas wells, the report must also identify each well completion 
conducted during the reporting period and submit detailed completion 
records for each well as part of the annual report.
    In the final rule, the recordkeeping and reporting requirements for 
well completions also provide a streamlining option that owners and 
operators may choose in lieu of the standard annual reporting 
requirements. The alternative, streamlined annual report for gas well 
affected facilities requires submission of a list, with identifying 
information of all affected gas wells completed, electronic or hard 
copy photographs documenting REC in progress for each well for which 
REC was required and the self-certification required in the standard 
annual report. The operator retains a digital image of each REC in 
progress. The image must include a digital date stamp and geographic 
coordinates stamp to help link the photograph with the specific well 
completion operation. The owner or operator is not required to submit 
detailed completion records as part of the annual report.
    For centrifugal compressors with wet seal systems, the annual 
report must include identification of each affected facility 
constructed, modified or reconstructed during the reporting period. The 
annual report for reciprocating compressors must identify each 
reciprocating compressor constructed, modified or reconstructed during 
the reporting period. The report also must include, for each affected 
compressor, the elapsed time of operation since the most recent rod 
packing change as of the end of the reporting period. For affected 
pneumatic controllers and storage vessels, the annual report must 
identify each affected facility constructed, modified or reconstructed 
during the reporting period.
    Owners or operators who conduct certain performance tests on 
control devices must report results of those tests using the Electronic 
Reporting Tool (ERT). Further discussion of reporting of emissions 
tests is presented in section VIII.D of this preamble.
NESHAP
    The final amendments to 40 CFR part 63, subparts HH and 40 CFR part 
63, subpart HHH revise certain recordkeeping requirements. 
Specifically, facilities using carbon adsorbers as a control device are 
now required to keep records of their carbon replacement schedule and 
records of each carbon replacement. We are requiring that owners and 
operators that use a manufacturer's tested control device keep records 
of visible emissions readings and flowrate calculations and records of 
periods when the pilot flame is absent. The final amendments require 
records of the date of each semi-annual maintenance inspection be 
maintained. Finally, 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 conjunction with the final MACT standards for small glycol 
dehydration units, owners and operators of such units are required to 
submit an initial notification within 1 year after becoming subject to 
40 CFR part 63, subpart HH or by October 15, 2013, whichever is later.
    Similarly, in conjunction with the final MACT standards for small 
glycol dehydration units in the final 40 CFR part 63, subpart HHH 
amendments, owners and operators of small glycol dehydration units are 
required to submit an initial notification within 1 year after becoming 
subject to subpart HHH or by October 15, 2013, whichever is later.
    The final amendments to 40 CFR part 63, subpart HH and 40 CFR part 
63, subpart HHH include new requirements for the contents of 
Notification of Compliance Status Reports. The owners and operators are 
required to include an electronic copy of the performance test results 
for the manufacturer's tested control device, if applicable; the 
predetermined carbon replacement schedule for carbon adsorbers, if 
applicable; and data related to the manufacturer's performance tests 
conducted for certain models of control devices, if compliance is being 
achieved using the manufacturer's performance tests.
    The final amendments to the NESHAP also include additional 
requirements for the contents of periodic reports. Each semiannual 
report must include a signed certification by a senior company official 
that attests to the truth, accuracy and completeness of the report. For 
both 40 CFR part 63, subpart HH and 40 CFR part 63, subpart HHH, in the 
final amendments, periodic reports are

[[Page 49510]]

required to include periodic test results and information regarding any 
carbon replacement events that occurred during the reporting period. 
Owners and operators are also required to include in the periodic 
reports information regarding any excursions that occur when the inlet 
gas flow rate deviates from that identified in the manufacturer's 
performance test, and any excursions caused when visible emissions 
exceed the maximum allowable duration.
    Owners or operators who conduct certain performance tests on 
control devices must report results of those tests using the ERT. 
Further discussion of reporting of emissions tests is presented in 
section VIII.C below.
2. Innovative Compliance Approaches
    At proposal, given the number and diversity of sources potentially 
affected by the NSPS and/or the NESHAP, we solicited comments on 
optional compliance tools that could reduce compliance burden and 
enhance transparency. Specifically, we asked for suggestions on: (1) 
Registration of wells and advance notification of planned completions; 
(2) use of third party verification; and (3) electronic reporting using 
existing mechanisms. We received comments on each of the topics above 
and have presented summaries of those comments and the EPA's responses 
in the Response to Comments document. The commenters were generally 
opposed to third party verification. However, one suggestion was a 
voluntary random verification program, similar to one used in the past 
for gasoline marketing, where operators who participated in this 
program potentially could receive lower priority for enforcement 
inspections by regulators. Other suggested innovative approaches 
include use of social media, including Facebook and Twitter, plus new 
technologies such as quick response codes, to provide timely public 
notification and access to compliance records for individual wells and 
other affected facilities. Other suggestions included use of a 
centralized database for industry and public access to compliance 
information. Further discussion of these approaches is provided in the 
response to comments. While we considered these suggestions, we did not 
adopt them in the final rule, for reasons explained further in the 
Responses to Comments document.

C. What are the requirements for submission of performance test data to 
the EPA?

    The EPA must have performance test data to conduct effective 
reviews of CAA sections 111, 112 and 129 standards, as well as for many 
other purposes, including compliance determinations, emission factor 
development and annual emission rate determinations.
    As stated in the proposal preamble, the EPA is taking a step to 
increase the ease and efficiency of data submittal and data 
accessibility. Specifically, the EPA is requiring owners and operators 
of oil and natural gas sector facilities to submit electronic copies of 
required performance test reports.
    As mentioned in the proposal preamble, data entry will be conducted 
through an electronic emissions test report structure called the ERT. 
The ERT will generate an electronic report which will be submitted to 
the EPA's Central Data Exchange (CDX) through the Compliance and 
Emissions Data Reporting Interface (CEDRI). A description of the ERT 
can be found at http://www.epa.gov/ttn/chief/ert/index.html and CEDRI 
can be accessed through the CDX Web site (www.epa.gov/cdx).
    The requirement to submit performance test data electronically to 
the EPA does not create any additional performance testing and would 
apply only to those performance tests conducted using test methods that 
are supported by the ERT. A list of the pollutants and test methods 
supported by the ERT is available at http://www.epa.gov/ttn/chief/ert/index.html.
    The major advantages of electronic reporting are more fully 
explained in the proposal preamble.
    An important benefit of using the ERT is that the performance test 
data will become available to the public through WebFIRE. Having such 
data publicly available enhances transparency and accountability.
    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 will save industry; state, local and tribal agencies; and the 
EPA significant time, money and effort while improving the quality of 
emission inventories and, as a result, air quality regulations.

IX. Summary of Significant NSPS Comments and Responses

    For purposes of this document, the text within the comment 
summaries was provided by the commenter(s) and represents their 
opinion(s), regardless of whether the summary specifically indicates 
that the statement is from a commenter(s) (e.g., ``The commenter 
states'' or ``The commenters assert''). The comment summaries do not 
represent the EPA's opinion unless the response to the comment 
specifically agrees with all or a portion of the comment.

A. Major Comments Concerning Applicability

1. Activities That Constitute a Modification
    Comment: Referring to the definition of ``modification'' in section 
111(a)(4) of the CAA, one commenter asserts that a modification occurs 
only if two things happen: (1) There must be a ``physical change or 
change in the method of operation,'' and (2) the change must result in 
an emissions increase.
    The commenter states that, in the context of the New Source Review 
program, the District of Columbia Circuit Court has opined that 
``Congress's use of the word `any' in defining a `modification' means 
that all types of `physical changes' are covered'' (New York v. EPA, 
443 F.3d 880, 890 (D.C. Cir. 2006)) and that the District of Columbia 
Circuit Court has determined that ``the plain language of the CAA 
indicates that Congress intended to apply NSR to changes that increase 
actual emissions instead of potential or allowable emissions.'' New 
York v. EPA, 413 F.3d 3, 40 (DC Cir. 2005).
    However, according to the commenter, the Supreme Court has 
concluded that the CAA section 111 definition of modification does not 
have to have the same meaning under the NSPS and New Source Review 
(NSR) programs (Environmental Defense v. Duke Energy Corp., 127 S. Ct. 
1423, 1434 (2007)), and, thus, the EPA has latitude within the context 
of CAA section 111 to implement different rules regarding 
modifications.
    The commenter believes, in particular, that the EPA's regulatory 
definition of ``modification'' under the NSPS program provides several 
categories of activities that alone, are not to be considered 
modifications, including ``maintenance, repair, and replacement which 
the Administrator determines to be routine for a source category,'' and 
``an increase in production rate that can be accomplished without a 
capital expenditure.'' 40 CFR 60.14(e). The commenter believes these 
provisions reflect the fact that Congress established the NSPS program 
for ``new'' sources. According to the commenter, without these 
exclusions, even the most minor activities would convert an existing 
source into a ``new source.'' The commenter states that the premise 
behind characterizing these activities as

[[Page 49511]]

not being ``changes'' is that they all contemplate that the plant will 
continue to be operated in a manner consistent with its original design 
and, thus, is not a ``new'' facility.
    We also received a number of comments objecting to consideration of 
recompletion activities \10\ as modifications, claiming that it is a 
significant departure from the definition of ``modification'' under the 
General Provision at 40 CFR 60.14. Some commenters argue that well 
completion expenditures do not meet the regulatory definition of 
``capital expenditure'' while others argue that they are maintenance 
activities excluded in 40 CFR 60.14 others note that we have not 
traditionally regulated temporary ``construction'' activities.\11\
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    \10\ At proposal, EPA used the term ``recompletion'' to describe 
completions of previously fractured new gas wells that are 
refractured at some future date, and we specified that such actions 
are considered modifications. In addition, we used the term 
``recompletion'' to describe completions of existing wells (i.e., 
those wells that were constructed before August 23, 2011) that 
subsequently are fractured for the first time or that are 
refractured.
    \11\ We disagree with the commenter. Fracturing and refracturing 
are not maintenance activities. On the contrary, these are essential 
processes that allow production of gas from shale and other 
formations, either during the initial development of a well or in 
development of new horizons within a previously fractured well. We 
also disagree with the characterization that we are regulating 
``construction activities.'' Rather we are regulating the emissions 
resulting from the physical change.
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    Response: In this final rule, the EPA addresses modifications in 
the context of well completions and has deleted the proposed definition 
of ``modification,'' though the underlying rationale presented in the 
proposal remains, and we are providing alternative regulatory text. 
Pursuant to this final rule and as discussed below, well completions 
conducted on gas wells that are refractured on or after the effective 
date of this rule are considered modifications and subject to the NSPS, 
with the exception of such well completions that, immediately upon 
flowback, use emission control techniques otherwise required for new 
wells and satisfy other requirements for gas well facilities, including 
notification, recordkeeping and reporting requirements.
    As discussed in the proposal, the EPA has chosen to depart from the 
definition of modification in 40 CFR 60.14 with respect to regulation 
of wells that primarily produce natural gas. As explained in the 
proposal and elsewhere in the preamble for this rule, the VOC emissions 
from the flowback following refracturing of gas wells are significant, 
the EPA has identified cost-effective controls to reduce VOC emissions 
during this operating phase, and these controls are required for only a 
relatively short time during the well's operating life. The EPA 
therefore concludes that it is appropriate for treatment of these 
activities to depart from the definition of modification in 40 CFR 
60.14 to ensure that emissions from these activities are controlled.
    We do not in this package question the broad appropriateness of the 
NSPS General Provisions at 40 CFR 60.14. However, as the General 
Provisions on modification in 40 CFR 60.14 themselves recognize, they 
may not be appropriate in all cases. Given the significant, although 
short-term, increase in emissions from flowback caused by refracturing 
activities when such activities are not controlled, and the cost-
effective nature of the control on such emissions, we have concluded 
that covering these refracturing activities is appropriate even if it 
requires departing from the General Provisions' definition of 
modification.
    Specifically, we are providing in the final rule at 40 CFR 60.5365:

    (h) The following provisions apply to gas well facilities that 
are hydraulically refractured.
    (1) A gas well facility that conducts a well completion 
operation following hydraulic refracturing is not an affected 
facility, provided that the requirements of Sec.  60.5375 are met. 
For purposes of this provision, the dates specified in Sec.  
60.5375(a) do not apply, and such facilities, as of the effective 
date of this rule, must meet the requirements of Sec.  
60.5375(a)(1)-(4).
    (2) A well completion operation following hydraulic refracturing 
at a gas well facility not conducted pursuant to Sec.  60.5375 is a 
modification to the gas well affected facility.
    (3) Refracturing of a gas well facility does not affect the 
modification status of other equipment, process units, storage 
vessels, compressors, or pneumatic controllers located at the well 
site.
    (4) Sources initially constructed after August 23, 2011, are 
considered affected sources regardless of this provision.

    As a result of this provision, a modification of a well, defined as 
``an onshore well drilled principally for production of natural gas,'' 
occurs when a well is refractured on or after the effective date of 
this rule, except when the owner or operator of a well controls 
emissions during the completion operation by the use, immediately upon 
flowback, of emission control techniques otherwise required for new 
wells, as discussed more below.\12\
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    \12\ While we have not done so often, in situations such as 
this, where there is a defined set of physical changes that 
inevitably lead to an emissions increase, regulatory certainty and 
clarity can be provided by, as EPA is doing, providing a categorical 
listing of activities that constitute modifications. See, e.g., 40 
CFR 60.751 (addressing landfills; definition of modification); 40 
CFR 60.100a(c) (addressing refineries; stayed pending 
reconsideration).
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Consistency With the Definition of Modification
    This provision is consistent with the statutory definition of 
modification contained in CAA 111(a)(4).\13\ As discussed in the 
proposal, CAA section 111(a)(4) defines a modification based on two 
requirements: (1) A physical change and (2) an emissions increase. The 
consistency of our approach with these two elements is discussed below.
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    \13\ We need not address if New York v. EPA, 443 F.3d 880, 890 
(D.C. Cir. 2006) compels the result here. As we explain, in the body 
of this preamble our approach is consistent with CAA section 
111(a)(4), and we provide a reasonable rationale for adopting the 
approach we take here.
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Physical Change
    Uncontrolled completion following refracturing of gas wells fits 
well within the statutory definition of modification (the refracturing 
results in a physical change which causes flowback and an increase in 
emissions relative to the emissions level prior to the refracturing). 
Accordingly, the NSPS' treatment of modification applies to completions 
of hydraulically refractured gas wells.
    One commenter contends that recompletion does not constitute 
physical change even if there is re-perforation because it is an 
expected part of well operation. However, both the CAA and our 
regulation define modification to mean ``physical change'' without 
providing any qualification to that term, thus indicating that the term 
``physical change'' is very broad to include any physical change. The 
commenter's interpretation of the term ``physical change'' is without 
support.
Emissions Increase
    As a result of these physical changes, a multi-day period of 
flowback of natural gas, hydrocarbon condensate, water and sand is 
necessary to clean up the formation and wellbore prior to production of 
gas for sale. This flowback period is characterized by release of 
substantial amounts of VOC-containing natural gas and hydrocarbon 
condensate that would not have occurred absent the refracturing 
operation, thus meeting the second part of the statutory test--an 
increase in the amount of emissions.
    As discussed in the proposal, EPA's data indicate that uncontrolled 
well completions with hydraulic refracturing consistently result in VOC 
emissions that were not present prior to such activities. Data in 
comments received also confirm that these uncontrolled

[[Page 49512]]

refracturing activities result in significant VOC emissions. Our data 
indicate very low VOC emissions from gas wells (2.6 tpy on average) at 
the wellhead during ongoing production prior to such activities. In 
light of the above, we reasonably conclude that such activities result 
in an increase in the amount of VOC emissions and, therefore, 
constitute a modification.
    We reject the comments suggesting that we should adopt the prior 
fracturing activity as the baseline for determining if an emission 
increase has occurred.\14\ We note that these comments appear in part 
to rely upon a misunderstanding of the EPA's longstanding practice that 
the relevant baseline for determining an emissions increase under the 
NSPS is not based on the potential emissions profile associated with a 
prior physical change or the original construction but rather the 
emissions immediately prior to the physical change. See 57 FR 32314, 
32330 (July 21, 1992) (explaining that, under CAA section 111(a), an 
emission increase is based on current potential emissions rather than 
original design capacity). Accordingly, under historical regulations, 
the proposed regulatory language and the final rule that ``initial 
production volumes may have been higher than subsequent re-completions 
or refracturing operations because the formation has been depleted by 
production activities'' does not mean that there would not be an 
emissions increase. Ongoing emissions during day-to-day production are 
very small and are not a function of well productivity, since these 
emissions originate from leaking valves and other components that do 
not leak more or less as production increases or declines. However, 
flowback emissions following refracturing are orders of magnitude 
greater than the production phase emissions.
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    \14\ One commenter relies on a passage from a proposed, but 
never finalized, rule preamble to argue that under the NSPS emission 
increase test prechange emissions are based on the highest level 
achievable in the 5 years immediately preceding a physical change. 
The passage, however, is not addressing the NSPS test generally 
applicable to modifications, but, rather, is addressing a specific 
regulatory provision applicable to modifications at electric utility 
steam generating units (EUSGU). See 70 FR 61081, 61089 (October 20, 
2005). Specifically, the preamble discussion is describing 40 CFR 
60.14(h), which states that a change at an EUSGU will not be a 
modification if ``such change does not increase the maximum hourly 
emissions achievable at the unit during the five years prior to the 
change.'' See, also, 57 FR 32314, 32330 (July 21, 1992) (adopting 40 
CFR 60.14(h) and contrasting the provision with the pre-existing 
test).
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    Moreover, adoption of a prior fracturing activity as the baseline 
for comparison here is inappropriate. The purpose of the refracturing 
activity is to increase production from its current level. As explained 
above, at least for the short term, VOC emissions from the affected 
facility increase as a direct result of the physical change.\15\ That 
is, these emissions would not have (and could not have) occurred 
without the physical change. Accordingly, we conclude that reliance on 
the prior fracturing activity as a baseline is inappropriate.\16\
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    \15\ Our data show that the magnitude of ongoing VOC emissions 
from a producing gas well is approximately 2.6 tpy or about 14 
pounds per day, while the magnitude of VOC emissions is 23 tons over 
an average period of 7 days, or about 6,600 pounds per day, during a 
completion operation following refracturing. At this time, we do not 
have similar data on emissions from oil wells.
    \16\ One commenter claims that one cannot determine whether a 
given well completion activity qualifies as a modification based on 
the proposed definition because it is infeasible to measure the 
amount of flowback emission according to the EPA in proposing a work 
practice standard. However, nothing in CAA 111(a)(4) and 40 CFR 60.2 
requires quantification of the amount of emission increase, only 
that there be an increase as a result of the physical change. In 
addition, the commenter's argument would appear to apply equally to 
any time we set a work practice.
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De Minimis Exception
    We recognize that there are reasons to limit the scope of the 
modification definition so as to not include certain well-controlled 
refracturing activities performed by sources. We recognize that the 
approach that we are taking in this final rule differs from the 
approach that we have taken in the past, as it excludes certain 
emission increases associated with a physical change from constituting 
a modification based on the de minimis exception. This exception allows 
agency flexibility in interpreting a statute to prevent ``pointless 
expenditures of effort'' and has been previously recognized by the 
United States Court of Appeals for the District of Columbia Circuit as 
an appropriate tool when interpreting the CAA section 111(a)(4) 
definition of modification in the context of New Source Review. Alabama 
Power Co. v. Costle, 636 F.2d 323, 360 (D.C. Cir. 1979).
    Since the inception of the NSPS program, certain emission controls 
could be used by a source to avoid having an activity constitute a 
modification provided that the controls prevented emissions from 
increasing. As the District of Columbia Circuit explained:
    Under provisions of the regulations that are not challenged in 
this litigation, the operator of an existing facility can make any 
alterations he wishes in the facility without becoming subject to 
the NSPS as long as the level of emissions from the altered facility 
does not increase. Thus the level of emissions before alterations 
take place, rather than the strict NSPS, effectively defines the 
standard that an altered facility must meet.

Asarco Inc. v. EPA, 578 F.2d 319, 328-29 (D.C. Cir. 1978); see, also, 
75 FR 54970, 54996 (September 9, 2010) (``However, sources always have 
the option of adding sufficient NOX control to avoid an 
hourly emissions increase and avoid thus triggering the modification 
provision.''). We have allowed such controls to permit the source to 
avoid being considered ``modified'' if the controls fully negate the 
emissions increase.
    In this case, we are providing that where a source has in place, 
and, immediately upon flowback, applies emission controls equivalent to 
those required for a new source (as specified in 40 CFR 60.5375(a)(1) 
through (4)), the physical change will not constitute a modification 
despite the small remaining emission increase. Specifically, well 
completions conducted by sources for refractured wells and with the 
use, immediately upon flowback, of emission controls equivalent to 
those required for new sources will not be considered a modification, 
due to the de minimis increase in emissions of such wells using these 
controls. Several unique factors justify finding that application of 
the de minimis doctrine is appropriate here.
    First, to qualify for the exclusion from the definition of 
modification the source must be using controls equivalent to those 
required were it to trigger the NSPS. As a result, the imposition of 
the NSPS would not yield additional regulatory or environmental 
benefits. See Environmental Defense Fund, Inc. v. EPA, 82 F.3d 451, 466 
(D.C. Cir. 1996). Second, as a result of imposition of controls 
emissions are very low in magnitude. This is both with respect to the 
size of the increase associated with the physical change and the total 
emissions from the unit after the physical change. Third, the emissions 
associated with the change, and peak emissions post change, are time-
limited. A well completion is a discrete activity, occurring over a 3-
10-day period on an occasional basis, which may be as infrequent as 
once every 10 years. This is different from the type of emitting 
activity typically regulated as a modification under NSPS, which would 
involve ongoing emissions indefinitely into the future. Further, a 
source qualifying for this exception must comply with the recordkeeping 
and reporting requirements that are required of new sources. 
Accordingly, the increase in emissions from the physical

[[Page 49513]]

change, and the total amount of additional emissions, will be very 
small.
    We are providing the de minimis exception discussed above to 
provide states with flexibility in application of their permitting 
authority and resources. Commenters pointed out that a number of state 
permitting programs are triggered for sources that are subject to an 
NSPS as a result of a modification. The EPA recognizes that states are 
the most appropriate entities to determine whether and how sources 
should be permitted, and we have concern regarding potential impacts of 
this final rule on states' permitting resources. Accordingly, with this 
final rule, we intend that states retain the discretion to determine 
whether refracturing activities by sources employing control techniques 
that are required for new wells will require changes in that source's 
permit status.
Clarifying Changes
    Although we are not finalizing the proposed definition of 
``modification'' for the reasons discussed above, we believe it is 
important to address certain comments regarding the proposed definition 
in order to clarify the agency's intent as it relates to well 
completions. For example, we included ``natural gas'' in the proposed 
definition for ``modification'' in recognition that our proposed work 
practice requirements for well completions use natural gas as a 
surrogate for VOC. We consider natural gas to be an appropriate 
surrogate for VOC for well completion activities because our analyses 
of data on composition of natural gas at the wellhead indicated that 
emissions of natural gas during well completions contain various 
chemical species that are VOC. The inclusion of natural gas in the 
proposed definition for modification was not an indication that EPA was 
proposing natural gas as a pollutant to be regulated, as some 
commenters mistakenly thought.
    We also received comment objecting to defining ``modification'' 
based on increase in the ``amount of emission'' instead of ``emission 
rate'' as provided in the General Provisions for modifications in 40 
CFR 60.14. We had intended but were not clear in our proposed rule that 
the definition would apply only to well completions. In the final rule, 
we have promulgated the provisions discussed above regarding well 
provisions in lieu of the proposed definition for modification to 
clarify our intent.
    Finally, this provision is intended to address comments suggesting 
confusion associated with our proposed definition of ``modification'' 
and the separate, proposed provision in 40 CFR 60.5420 that a workover 
is considered a modification. The second of these provisions is being 
removed in light of comments that there is no common understanding of 
this term and, as a result, it may be interpreted to cover more than 
the fracturing activities the EPA intended to cover.\17\
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    \17\ We are not considering ``workovers'' to be modifications 
because: (1) They include truly routine activities; (2) in most 
instances we would anticipate only a small emissions increase, if 
any; and (3) we have no reason to think that these wells differ in 
emission profile or control options from non-fractured wells (or 
fractured wells after flow back), and accordingly we have not 
identified a BSER that would apply following any such modification.
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    In summary, as a result of the comments and considerations 
discussed above, the final rule provides that well completions 
conducted on gas wells that are refractured on or after the effective 
date of this rule are modifications and are subject to the NSPS. 
However, gas wells that undergo completion following refracturing, with 
the use, immediately upon flowback, of emission control techniques 
otherwise required for new wells and that satisfy other requirements 
for gas well facilities, including notification, recordkeeping and 
reporting requirements, are not considered modified and, as a result, 
are not affected facilities under the NSPS. This provision is 
consistent with the NSPS program's history of allowing sources to use 
certain emission controls to avoid having an activity constitute a 
modification. In this situation, we consider it appropriate to require 
notification, recordkeeping and reporting requirements in order to 
ensure that a source is meeting the requirements to avail itself of 
this provision. We believe this approach will encourage early use of 
REC and will result in 1,000 to 1,500 REC that would not otherwise 
occur during the REC phase-in period ending January 1, 2015, discussed 
in section IX.B of this preamble.
2. Regulation of Methane and Other Pollutants
    Comment: One commenter believes that under CAA section 111, the EPA 
must regulate each dangerous pollutant emitted by sources in the oil 
and gas source category in more than de minimis quantities for which 
controls are available and asserts that the EPA has failed to do so. In 
particular, the commenter states that the EPA must regulate methane, 
particulate matter (PM), hydrogen sulfide and nitrogen oxides 
(NOX) from oil and gas operations. The commenter states that 
the EPA's explanation of why it declined to regulate certain pollutants 
does not discuss PM or hydrogen sulfide, address the most important 
sources of NOX or offer a legal justification for its 
failure to regulate methane. The commenter interprets the CAA to mean 
that the EPA must, every 8 years, (1) review its standards (as it has 
done here), (2) determine whether it is ``appropriate'' to revise them, 
including whether it is appropriate to add additional pollutants to the 
standards, and (3) if so, revise them accordingly.
    Response: In this rule, we are not taking final action with respect 
to regulation of methane. Rather, we intend to continue to evaluate the 
appropriateness of regulating methane with an eye toward taking 
additional steps if appropriate. On November 8, 2010, EPA finalized 
reporting requirements for the petroleum and natural gas industry under 
40 CFR Part 98, the regulatory framework for the Greenhouse Gas 
Reporting Program (GHGRP). Beginning in September 2012, this program 
requires annual reporting of greenhouse gases (GHG) from large 
emissions sources and fuel suppliers in the United States. Petroleum 
and natural gas facilities will report annual methane and carbon 
dioxide (CO2) emissions from equipment leaks and venting, 
and emissions of CO2, methane and nitrous oxide from 
flaring, onshore production stationary and portable combustion 
emissions, and combustion emissions from stationary equipment involved 
in natural gas distribution. The EPA estimates that the rule will cover 
85 percent of the total GHG emissions from the United States petroleum 
and natural gas industry with approximately 2,800 facilities reporting. 
The data submitted under the GHGRP will provide important information 
on the location and magnitude of GHG emissions from petroleum and 
natural gas systems and will allow petroleum and natural gas facilities 
to track their own emissions, compare them to similar facilities and 
aid in identifying cost-effective opportunities to reduce emissions in 
the future.
    As noted in the proposal, the control measures that the EPA is 
requiring for VOC result in substantial methane reductions as a co-
benefit. Over time, collection of data through the GHGRP and other 
sources will help EPA evaluate whether it is appropriate to directly 
regulate methane from the oil and gas sources covered by this rule. The 
EPA will be in a better position to characterize (1) the extent of 
methane emissions from these sources that will remain after imposition 
of controls

[[Page 49514]]

required by this rule; and (2) whether additional measures are 
available and appropriate for addressing such emissions.
    With regard to other pollutants, including PM, H2S and 
NOX, many of the sources of PM and NOX within the 
Crude Oil and Natural Gas Production source category are within the 
scope of units covered by other NSPS and will be evaluated in the 
context of subsequent revisions of those rules, if appropriate. This 
approach is consistent with what the agency articulated when we 
promulgated the original oil and gas rules. See 49 FR 2637. For 
example, NSPS covering stationary reciprocating internal combustion 
engines (40 CFR part 60, subparts IIII and JJJJ) and combustion 
turbines (40 CFR part 60, subpart KKKK) regulate emissions of PM and 
NOX from sources found in this category. These engines and 
turbines are found in a variety of locations in this category including 
gathering and boosting stations, natural gas processing plants and 
natural gas transmission and storage facilities. In addition, some 
mobile source regulations (40 CFR part 1039) cover nonroad engines such 
as those used on drilling rigs, electrical generators and hydraulic 
fracturing pumps. As we discussed at proposal (see 76 FR 52756) most, 
if not all, of the process heaters and boilers used in this category 
fall below applicability thresholds for EPA's boiler rules (40 CFR part 
60, subparts Db and Dc). Although these smaller heaters and boilers are 
generally within the scope of this category, we received no 
quantitative data in the public comments on NOX or PM 
emissions from these units. Given the broad coverage of the PM and 
NOX sources in this category by other NSPS we did not depart 
from the approach adopted in 1984 of considering these pollutants in 
development of other standards.
    Although the NSPS does not provide direct regulation of 
H2S, the VOC control requirements in the final rule achieve 
reductions of H2S a co-benefit in cases where H2S 
is otherwise emitted in the oil and natural gas production segment. 
While amine treatment and sulfur recovery are routinely employed both 
upstream and at natural gas processing plants to remove H2S 
from the natural gas stream, we believe that it would not be reasonable 
or cost-effective to require amine units and sulfur recovery for every 
emission point in the oil and natural gas production segment. We 
received no public comments suggesting other control technologies that 
could be applied to control H2S in the field. Such emissions 
occur in the field as fugitive emissions at the wellhead and vented 
emissions from well completions, storage vessels, pneumatic controllers 
and compressors. However, as mentioned above, the VOC control measures 
provided in the final rule for well completions, storage vessels, 
pneumatic controllers and compressors greatly reduce any H2S 
emissions along with the VOC emissions controlled.
3. Expanded Scope of the Source Category
    Comment: One commenter states that, in the preamble, the EPA makes 
reference to its proposal to significantly expand the scope of oil and 
gas operations that would be covered by the new NSPS, and states that 
``[t]o the extent that 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'' (citing 76 FR 52745, 
August 23, 2011). The commenter is not aware of any authority pursuant 
to which the EPA may affect a significant expansion of the category 
list merely through the language of the preamble in an NSPS rulemaking. 
The commenter states that, in a related context, the CAA requires that 
the EPA engage in consultation with state governors and air pollution 
control agencies, suggesting that more than a preamble reference is 
needed in order to expand the category list and impose NSPS 
requirements on the new and unique affected sources addressed in this 
rule. See 42 U.S.C. 7411(f)(3). The commenter asserts that the sources 
the EPA seeks to regulate are different types of stationary sources 
than gas processing plant, and contends that oil and gas production 
wells are stationary sources, but are, clearly, not processing plants.
    Response: Because EPA has concluded that the currently listed Oil 
and Natural Gas source category covers at least those operations in 
this industry for which we are finalizing standards, we need not 
address what steps the agency must take if expanding a source 
category.\18\ As we explained in the preamble to the proposed rule, 
when the EPA initially listed this source category, it did so in a 
document where it described its listings as broad. 76 FR at 52745.\19\ 
Contrary to commenters assertions, the EPA has viewed this source 
category listing very broadly. Specifically, when promulgating the 
first sets of standards of performance for this source category, we 
stated that the source category ``encompass[es] the operations of 
exploring for crude oil and natural gas products, drilling for these 
products, removing them from beneath the earth's surface, and 
processing these products from oil and gas fields for distribution to 
petroleum refineries and gas pipelines.'' 49 FR at 2637 (emphasis 
added). That preamble linked the endangerment finding under CAA section 
111(a) to the industry as a whole: ``The crude oil and natural gas 
production industry causes or contributes significantly to air 
pollution that may reasonably be anticipated to endanger public health 
or welfare'' (Emphasis added). 49 FR 2636. The statements above affirm 
our conclusion that the currently listed Oil and Natural Gas source 
category covers all operations for which we are setting standards. That 
the original NSPS's only set standards for a limited set of sources 
within the category cannot be taken to imply that other units were not 
within the scope of this original listing. See, e.g., Nat'l Lime Ass'n 
v. EPA, 627 F.2d at 426 n. 27 (noting that the EPA set standards for 
only certain kiln types within the source category). Indeed, the 
preamble to the 1984 proposed NSPS rule directly addresses regulation 
of wells, concluding that the agency was not setting standards at that 
time; not because they were outside the scope of the source category, 
but because the agency was unable at that time to identify ``[b]est 
demonstrated control technology.'' 49 FR at 2637. As all of the units 
that we are regulating fall within the scope of the original listing, 
we need not address what steps would be necessary were we to expand the 
scope of the listing.
---------------------------------------------------------------------------

    \18\ For the same reason, we need not address the comment 
claiming that CAA section 111(f)(3) requires that the EPA consult 
with state governors before amending CAA section 111(b) listing.
    \19\ While not required to do so, we have included the 
Background Information Document for the listing rule in the docket 
for this rule. We note that those documents shed no additional light 
on the scope of the listing beyond our interpretation of the listing 
preamble described in the proposed rule.
---------------------------------------------------------------------------

B. Major Comments Concerning Well Completions

1. Applicability and Exemptions
a. Well Exemptions
    Comment: One commenter suggests adding ``appraisal wells'' as a 
third subcategory of well to be exempt from the REC requirements, and 
defines these wells as those drilled in an area where the reservoir has 
not been classified for that area as containing proved reserves of 
natural gas. According to the commenter, adding this definition and 
exemption better reflects the universe of wells for which a gas flow 
line system

[[Page 49515]]

will not be available. The commenter adds that it also avoids a 
potential problem where a shale play appraisal well system is 
effectively compelled to install a flow line system before the wells 
are determined to be economically viable, in order to assure compliance 
with 40 CFR part 60, subpart OOOO.
    Response: The EPA recognizes that a flow line at the well pad is a 
necessary precondition to capture flowback gas for emissions control so 
that the REC process has an outlet for the captured gas. However, the 
EPA does not agree that appraisal wells need to be exempt. Appraisal 
wells are drilled and then logged to assess productivity. If well logs 
indicate that the well is productive, then fracturing will be 
performed, and the cost to fracture, complete and produce the well, 
including installing a flow line, will be incurred. If the well logs 
indicate the well is not economically productive, then no fracturing 
occurs and the NSPS does not apply. The EPA, therefore, believes it is 
reasonable to require appraisal wells that are hydraulically fractured 
to comply with Subcategory 3 rule requirements.
b. Threshold for Low Pressure (Low Volume) Gas Wells and Wells with Low 
or No VOC Emissions
    Comment: One commenter expresses support for the REC requirements 
and urges the EPA to limit the number of well completions exempted from 
the requirements as much as possible. Several commenters contend that 
not all well completions can be conducted successfully under a 
requirement to flow back to the flow line, since the imposition of the 
flow line backpressure may reduce the flowback gas velocity 
sufficiently so that it is not energetic enough to clean up the well of 
liquid and sand. One commenter recommends that any well whose reservoir 
pressure (measured at the wellhead immediately after perforation) is 
less than 4 times (in absolute units) the line pressure measured at the 
flow meter, would be exempt from any requirement to flow to sales 
during the flowback period. According to the commenter, variability in 
reservoir and line pressures across the United States makes setting a 
specific pressure threshold difficult.
    Response: The EPA has established three subcategories of wells in 
response to public comments, as described above. One of those 
categories comprises non-wildcat and non-delineation low pressure gas 
wells. Low pressure gas wells are defined as wells with reservoir 
pressure and vertical well depth such that 0.445 times static reservoir 
pressure (in pounds per square inch absolute (psia)) minus 0.038 times 
the vertical well depth (in feet) minus 67.578 psia is less than the 
flow line pressure at the sales meter. Thus, wells above this pressure 
differential must implement REC, while wells below this pressure 
differential are required to route emissions to a completion combustion 
device.
    The EPA solicited comment in the proposed rule on situations where 
REC may be infeasible and criteria and thresholds for distinguishing 
well completion operations in those situations from others where REC is 
feasible. As noted above, several commenters highlighted the technical 
issues that prevent an operator from implementing an REC on a low 
pressure gas well, which is the inability to attain a gas velocity 
sufficient to clean up the well when flowing against the flow line 
backpressure. Based on this information, the EPA agrees that a pressure 
differential threshold is reasonable and addresses the technical 
limitations of low pressure gas wells to produce to the flow line 
during completion.
    As noted above, a commenter recommended specific approaches to 
developing a pressure threshold, including specifying that any well 
whose reservoir pressure is less than 4 times (in absolute units) the 
line pressure measured at the flow meter would be exempt from any 
requirement to flow to the flow line during the flowback period. This 
recommendation is based on a flowing bottom hole to reservoir pressure 
ratio of 1:2 and a line pressure to flowing bottom hole pressure of 
1:2. The EPA concurs with the commenter that flowing bottom hole 
pressure can be represented as half of the reservoir pressure for this 
rule. The EPA disagrees with the commenter that line pressure can be 
represented as half of the flowing bottom hole pressure for this rule 
since this pressure relationship can be more accurately determined 
using the Turner equation for liquids unloading from a well paired with 
models relating fluid velocity to pressure drop. Therefore, the EPA has 
modeled a worst-case pressure drop factor between the line pressure and 
flowing bottom hole pressure and has established a pressure threshold 
using this factor and the 1:2 factor for flowing bottom hole pressure 
to reservoir pressure. The result of this modeling is the equation 
discussed above in the definition of low pressure gas wells.
    As discussed in the proposal preamble, potential control options 
are REC with combustion or a completion combustion device alone. 
Because REC may not always be technically feasible for wells that fall 
below the pressure threshold, the EPA has determined that the BSER for 
reducing VOC emissions for this subcategory of wells is a completion 
combustion control device. However, the EPA encourages the use of REC 
with combustion should that be a viable option for any well within this 
subcategory. Therefore, in the final rule, for non-wildcat and non-
delineation wells with a pressure drop below the differential described 
above, the EPA requires the use of either a completion combustion 
device or REC with combustion to control gas not suitable for entering 
the flow line.
    Comment: Several commenters address parameters for defining which 
well completions would be subject to REC requirements. Commenters 
request that the EPA exempt wells with low VOC concentrations from the 
REC requirements and not issue the proposed standards before 
reconsidering the emissions estimates. One commenter suggests that the 
EPA exempt hydraulically fractured natural gas horizontal wells with de 
minimis VOC concentrations because the cost per ton of VOC reductions 
is extremely high for these wells and the emissions from the combustion 
of the produced gas could worsen ozone formation in the area. 
Commenters also provide, as examples, some wells with low or no VOC as 
support for exempting wells with a low VOC content or for exempting 
certain classes of wells such as coal bed methane. Several commenters 
contend that coal bed methane wells have low VOC, while several other 
commenters contend that coal bed methane wells have no VOC. Some 
commenters provide examples of coal bed methane wells with low VOC or 
no VOC, and one commenter provides an example of a shale gas well with 
no VOC.
    Response: The EPA acknowledges that the VOC concentration in 
natural gas can vary across wells and reservoir types such as coal bed 
methane (CBM), shale and tight sands. However, the information provided 
in the comment is insufficient for the EPA to determine that any 
specific class of wells, or wells with VOC concentration below a 
specific threshold, would not be cost-effective to regulate, as the 
commenters recommend. For example, several commenters contend that CBM 
wells have low or no emissions. In response to comments received, the 
EPA assessed the VOC content of CBM wells, including a review of the 
gas composition data presented in the gas

[[Page 49516]]

composition memo\20\ available in the docket and in an article\21\ by 
the United States Geological Survey. The VOC concentrations among CBM 
wells will vary and are not always low. The limited CBM data submitted 
by the commenter, while suggesting low-VOC concentrations at some CBM 
wells, is not to the contrary. Accordingly, we conclude that it would 
be inappropriate to provide a categorical exclusion for such wells.
---------------------------------------------------------------------------

    \20\ Memorandum from Brown, Heather, EC/R Inc., to Moore, Bruce, 
EPA/OAQPS/SPPD, Composition of Natural Gas for use in the Oil and 
Natural Gas Sector Rulemaking, July 28, 2011. Docket ID No. EPA-HQ-
OAR-2010-0505-0084.
    \21\ Rice, Dudley, Composition and Origins of Coalbed Gas, U.S. 
Geological Survey, Denver, Colorado.
---------------------------------------------------------------------------

    We also have determined that providing a low-VOC concentration 
exclusion would be inappropriate, both because the submitted data do 
not support such an exclusion (they do not demonstrate that such 
circumstances are frequent) and because of implementation concerns. 
Specifically, even if such a VOC concentration threshold described 
above can be determined, to ensure compliance with the rule, an 
operator would have to determine with certainty before production, 
whether a particular well was going to be above or below the threshold 
in order to mobilize the necessary capture equipment and secure a flow 
line, etc. This would require the operator to determine the reservoir 
composition, e.g., the gas composition prior to separation, in advance 
of the well completion (i.e., the determination of whether the well 
would be subject to the NSPS would have to be performed before the 
information on which to base such a determination would be available). 
Although nearby existing wells could potentially provide some 
indication of the general VOC content of the gas from the future well 
in question, there would be no assurance of certainty. In addition, the 
operator would need to certify that the reservoir sample is going to 
stay consistent and representative of the gas stream throughout the 
full completion process through multiple gas composition analyses.
    Taking into account the variability in VOC concentrations across 
reservoir types, the EPA's cost analysis illustrates that these 
requirements are cost-effective, especially when taking into account 
the gas savings. Compliance with a VOC concentration threshold-based 
rule for well completions could actually increase the burden to the 
operator by requiring numerous compositional analyses to demonstrate 
compliance with the rule.
    c. Definition of Gas Well
    Comment: Several commenters mentioned that the proposed definition 
of ``gas well'' was unclear due to the term ``principal production'' 
used in describing what the well produces. One commenter requests that 
the definition of gas well be modified to be each respective state's 
definition of gas well. The commenter states that, by doing this, the 
EPA would eliminate any confusion associated with having to apply 
different criteria (NSPS versus state regulations) for how to define a 
well-type in assessing the applicability of the rule.
    Response: In response to comments requesting further clarity in the 
definition, the EPA has revised the definition. The proposed definition 
was ``Gas well means an onshore well, the principal production of which 
at the mouth of the well is gas.'' In the final rule, in response to 
the comments we received, the EPA has revised the definition to exclude 
the phrase ``at the mouth of the well is gas.'' Based on this revision, 
the definition for the final rule is ``Gas well or natural gas well 
means an onshore well drilled principally for production of natural 
gas.''
    EPA's intent in setting standards for completion of hydraulically 
fractured gas wells is to require reduced emissions completions for 
wells where infrastructure is generally present to get recovered 
natural gas to market. Our understanding is that owners and operators 
plan their operations to extract a target product and evaluate whether 
the appropriate infrastructure is available to ensure their product has 
a viable path to market before completing a well. We expect that the 
final rule will result in control of hydraulically fractured gas wells 
drilled in the four formation types generally accepted as gas-producing 
formations: (1) High-permeability gas, (2) shale gas, (3) other tight 
reservoir rock or (4) coal seam. We believe that the wording changes 
made to the definition of ``gas well'' clarify the intent so that 
implementing agencies and industry will not be burdened with complex 
applicability determinations.
    With respect to using State gas well definitions, basing 
applicability on different definitions from State to State could 
introduce inconsistencies that are counter to the goal of nationwide 
regulation. We believe the NSPS, being a national rule, should contain 
a single definition applicable nationwide. However, states may choose 
to use a definition more expansive than our definition for their 
programs.
    Comment: One commenter states that, based on the EPA's discussion 
in Section 4 of the Technical Support Document (TSD), it appears the 
EPA's intent is to require reduced emissions completions only for 
natural gas wells. The commenter supports that the EPA applied reduced 
emissions completions only to natural gas wellhead facilities and 
excluded oil wellhead facilities and other types of gas wells which 
have little or no VOC emissions. The commenter states that, as shown on 
page 4-13 on Table 4.4, Nationwide Baseline Emissions from Uncontrolled 
Oil and Gas Well Completions and Recompletions, of the TSD, there are 
only 134 tpy of VOC emissions from oil well completions and 
recompletions for the entire United States, which is not worth 
regulating.
    One commenter recommends the following revision: ``Gas well means a 
well, the principal production of which at the mouth of the well is 
[add: hydrocarbon gas, not CO2] * * * Well means an oil or 
gas well, a hole drilled for the purpose of producing oil or gas, or a 
well into which fluids are injected.'' One commenter proposes the 
following revision: ``Gas well means a well, [DELETE the principal 
production of which at the mouth of the well is gas] completed for 
production of natural gas from one or more gas zones or reservoirs. 
Such wells contain no completions for the production of crude oil.'' 
The commenter also proposes the following revision: ``Gas well means a 
well [STRIKETHROUGH: the principal production of which at the mouth of 
the well is gas.] [ADD TEXT: completed for production of natural gas 
from one or more gas zones or reservoirs. Such wells contain no 
completions for the production of crude oil.]''
    Response: Although some wells drilled in crude oil formations may 
produce associated gas along with the oil, without a gas infrastructure 
present, the EPA does not have sufficient data on VOC emissions during 
completion of hydraulically fractured oil wells to set standards for 
these operations at this time.\22\ As a result, the final rule will not 
affect drilling of oil wells.
---------------------------------------------------------------------------

    \22\ In the proposed rule, we briefly assessed well completions 
of hydraulically fractured oil wells and did not believe that either 
REC or a completion combustion device is cost effective for reducing 
VOC emissions from such operations. We note, however, that this 
brief assessment of oil wells in the proposed rule was based on 
limited information at the time and that more information is needed 
for us to fully evaluate the VOC emissions and control options for 
these operations.

---------------------------------------------------------------------------

[[Page 49517]]

d. Availability of Infrastructure to Convey Gas to Market
    Comment: Various commenters have asserted that, in some cases, REC 
cannot be performed on some wells because there is no gathering line 
available to convey gas produced during the completion flowback period.
    Response: As explained above, it is our understanding that owners 
and operators plan their operations to extract a target product and 
evaluate whether the appropriate infrastructure access is available to 
ensure their product has a viable path to market before completing a 
well. However, in the standards for gas well affected facilities, the 
provisions of 40 CFR 60.5375(a)(1) through (4) apply to all fractured 
gas wells that are not exploratory wells, delineation wells or low 
pressure wells. These standards require that the well completion 
flowback be conducted using a combination of collection (i.e., REC), 
combustion and venting, depending on the characteristics of the 
flowback material and feasibility of routing the gas to a collection 
system to be conveyed to market. Section 60.5375(a)(3) provides:

``You must capture and direct flowback emissions that cannot be 
directed to the flow line to a completion combustion device * * *''.

    We believe that owners and operators of gas wells subject to 40 CFR 
60.5375(a) that require REC for a portion of the flowback period will 
exercise due diligence in coordinating the completion event with 
availability of a flow line to convey captured gas to market. However, 
there may be cases in which, for some reason, the well is completed and 
flowback occurs without suitable flow line available. In those isolated 
cases, we believe 40 CFR 60.5375(a)(3) provides for gas not being 
collected and instead combusted or vented pursuant to that section.
e. Fracturing of Wells Using Nitrogen and Carbon Dioxide
    Comment: One commenter suggested that wells that are fractured 
using nitrogen or CO2 should be exempt from the NSPS but did 
not provide supporting rationale. Other commenters expressed concern 
that inert gases such as nitrogen are not flammable, making compliance 
with the combustion provisions of the NSPS impossible.
    Response: We believe that the standards for well completions 
adequately address the concerns expressed by operators using nitrogen 
and/or CO2 for fracturing. We provided in the proposed rule, 
and further clarified in the final rule, that these standards require 
that the well completion flowback be conducted using a combination of 
collection (i.e., REC), combustion and venting, depending on the 
characteristics (including flammability) of the flowback material and 
feasibility of routing the gas to a collection system to be conveyed to 
market. Both the proposed and final rules express our intent to require 
REC only where there is salable quality gas to the gather line. See 76 
FR 52800 and 40 CFR 60.5375(a)(2) of the final rule.
    Section 60.5375(a)(3) in the final rule provides: ``you must 
capture and direct flowback emissions that cannot be directed to the 
flow line to a completion combustion device, except in conditions that 
may result in a fire hazard or explosion, or where high heat emissions 
from a completion combustion device may negatively impact tundra, 
permafrost or waterways. Completion combustion devices must be equipped 
with a reliable continuous ignition source over the duration of 
flowback.''
    Under this provision, operators who employ energized fracturing 
using inert gases and cannot route the flowback gas to a collection 
system because of poor gas quality must direct the flowback to a 
completion combustion device with a continuous ignition source. 
Although part of the flowback gases directed to the combustion device 
would not be flammable, the ignition source will ignite the flammable 
portion of the flowback, including VOC. Therefore, the presence of 
inert gases such as nitrogen and CO2 in the flowback gas has 
no bearing on the VOC reduction we expect to achieve through the NSPS 
or on compliance with provisions of the final rule.
2. Rule Should Not Prescribe Equipment
    Comment: Several commenters suggest revising 40 CFR 60.5375(a)(2) 
equipment requirements to be less prescriptive, especially in cases 
where use of specified or all listed equipment may not be necessary, 
and to provide flexibility to include newly developing technology. 
Other commenters assert that language in 40 CFR 60.5375(a)(1) and (2) 
stating that source owners or operators should ``minimize the emissions 
associated with venting of hydrocarbon fluids and gas'' and that 
``[a]ll salable gas must be routed to the gas gathering line as soon as 
practicable'' is vague and recommended a requirement that facility 
owners follow a Best Management Practice (BMP) plan that the EPA could 
develop, informed by the Natural Gas STAR program.
    Response: The EPA agrees that prescribing specific equipment to 
accomplish a reduced emissions completion is not necessary and has 
revised the rule language to not prescribe specific equipment. The 
operational standards provided in the NSPS allow the operator 
flexibility to perform the REC using equipment and practices best 
determined by the operator. As a result, we believe that a BMP plan 
developed by the EPA would not provide a higher degree of emissions 
control and could hinder innovation.
3. Availability of Equipment and Trained Personnel
    Comment: Commenters state that the supply of REC equipment and 
personnel is insufficient to meet the requirements of the proposed 
rule, applied nationally. According to commenters, proper surface 
equipment, collection infrastructure and qualified personnel are not 
readily available; they assert that this equipment is fairly 
specialized, the shops licensed to make it are limited and some of the 
components require a long lead time. For these reasons, commenters 
indicate that compliance by the issuance date of the rule would be 
unrealistic and that the EPA should provide a longer compliance period.
    Response: Based on information submitted by commenters, we have 
reason to believe that, currently, there is already significant demand 
for REC equipment. For example, Colorado, Wyoming, the City of Fort 
Worth, Texas, and the City of Southlake, Texas, require REC under 
certain conditions. Additionally, public comments, reports to the EPA's 
Natural Gas STAR Program and press statements from companies indicate 
that some producers implement REC voluntarily, based upon economic and 
environmental objectives. If REC were to be immediately required of all 
well completions, NSPS would place significant additional demands on 
REC equipment supply and experienced personnel.
    As the near-term supply of REC equipment and trained personnel will 
be insufficient to meet the new national demand for equipment and 
labor, immediate compliance with the REC requirements could be 
impossible, potentially causing producers to delay well completions 
until appropriate equipment and labor are available. Resulting delays 
in well completions while awaiting equipment availability could cause a 
decrease in the nationwide natural gas supply and would drive up the 
cost of completions doing REC. It is not the EPA's intent to set in 
motion a series of events through this rule that has the potential to 
affect

[[Page 49518]]

the natural gas supply and increased cost of REC would undermine our 
BSER analysis. Accordingly, it is important that the EPA consider the 
availability of REC equipment and personnel in its BSER analysis.
    Through EPA and industry events and collaborative studies, the EPA 
has interacted with operating companies that have extensive experience 
implementing REC. In particular, the EPA developed a detailed study 
\23\ on REC in collaboration with service providers. Based on this 
experience, the EPA has gained extensive information on this 
technology. Despite these efforts, the EPA is not aware of any 
quantitative information on the current and future supply of workers 
trained in REC techniques.
---------------------------------------------------------------------------

    \23\ Available at: http://www.epa.gov/gasstar/documents/reduced_emissions_completions.pdf.
---------------------------------------------------------------------------

    The EPA received data on the current and future supply of REC 
equipment. According to one commenter, about 300 REC units are in use 
today, with the ability to process about 4,000 wells per year, and 
1,300 additional units would be required to perform 20,000 REC per 
year. About 1,600 units performing 20,000 REC/year implies a REC 
productivity rate of about 12.5 REC/year/unit, or roughly each unit 
performing one REC per month, on average.
    The NSPS proposal estimated 9,300 REC performed for new natural gas 
well completions and 12,200 REC performed for existing natural gas well 
completions following refracturing would be required, in addition to 
those already required by state regulations. In the analysis supporting 
the final rule, the EPA revised estimates show 11,403 hydraulically 
fractured and 1,417 hydraulically refractured natural gas well 
completions will be performed in a representative year, which includes 
completions in states which currently have REC requirements. The 
revised estimate also reflects a change in the refracture frequency of 
existing wells from 10 percent to 1 percent based on information 
provided by commenters. Of the total hydraulically fractured well 
completions, the EPA estimates that about 11,300 REC will be required 
nationally on the basis of the final rule's provisions for wildcat 
(exploratory) and delineation wells, flowback gas pressure and natural 
gas well completions conducted on existing gas wells that are 
subsequently fractured or refractured. This estimate excludes REC 
required by state regulations.
    Assuming a REC unit performs 12.5 REC/year, as is asserted by the 
commenter, about 900 units would be required. This implies a current 
shortfall of about 600 units, based upon the numbers and assumptions 
provided by the commenter. The commenter states that industry can 
deliver about 50 units per quarter, after a 1-year build-up period. 
Given that the EPA does not have an alternative estimate of the number 
of REC units industry can produce per year, we adopt the estimate of 50 
units per quarter for this analysis, although the EPA disagrees with 
the assumption that a 1-year build-up period is required. Using the 
commenter's assumptions, it would take about 4.25 years to meet demand. 
This scenario is depicted in Scenario A in Table 6 below, assuming 
compliance is initiated at the beginning of the second quarter, 2012, 
and the industry begins delivering 50 units per quarter roughly 1 year 
after the compliance date.
    Surveys conducted by one commenter indicate that nine companies 
expect to perform more REC than the current stock is capable of. Given 
this growing demand, it is reasonable to assume industry can deliver 
units during the build-up period of the first year of implementation, 
which would reduce the time required to meet full demand another year 
to a total of about 3.25 years (Scenario B).
    The EPA also assessed whether the productivity of equipment in use 
could be higher than the 12.5 REC/year/unit derived from the comment, 
and the potential impact of such increase on the equipment supply. The 
EPA estimated that flowback periods will typically be 3 to 10 days with 
7 being a reasonable average. Therefore, because it is likely that a 
REC unit could be moved to another well site and be in operation in 
less than 20 to 27 days, it is reasonable to conclude that each REC 
unit can perform more than 12.5 REC/year.
    If the utilization rate of REC units is increased gradually from 
performing 12.5 REC/year/unit to 14 to 18 REC/year/unit, the time 
required to build the supply of REC units decreases (Scenarios C-G). As 
Table 6 shows, each 1 REC/year/unit increase reduces the build-up time 
by about 1 quarter. As is shown in Scenarios C and G, increasing the 
utilization rate of REC to 14 to 18 REC/unit/year with industry 
supplying new units beginning with the compliance date would provide 
between 1.75 and 2.75 years for full build-out of the REC unit supply 
by the beginning of calendar year 2015.

                                        Table 6--REC Unit Supply Analysis
----------------------------------------------------------------------------------------------------------------
              Scenario                   A          B          C          D          E          F          G
----------------------------------------------------------------------------------------------------------------
RECs Required......................     11,301     11,301     11,301     11,301     11,301     11,301     11,301
RECs/year/unit.....................       12.5       12.5       14.0       15.0       16.0       17.0       18.0
Units Needed.......................        904        904        807        753        706        665        628
----------------------------------------------------------------------------------------------------------------
Stock in Existence (assume industry can build 50 units/quarter; assuming industry starts with 300 units);
 compliance begins approximately at the end of the second quarter, 2012.
----------------------------------------------------------------------------------------------------------------
2012 (Q1)..........................        300        300        300        300        300        300        300
2012 (Q2)..........................        300        300        300        300        300        300        300
2012 (Q3)..........................        300        350        350        350        350        350        350
2012 (Q4)..........................        300        400        400        400        400        400        400
2013 (Q1)..........................        300        450        450        450        450        450        450
2013 (Q2)..........................        300        500        500        500        500        500        500
2013 (Q3)..........................        350        550        550        550        550        550        550
2013 (Q4)..........................        400        600        600        600        600        600        600
2014 (Q1)..........................        450        650        650        650        650        650        650
2014 (Q2)..........................        500        700        700        700        700        700  .........
2014 (Q3)..........................        550        750        750        750        750  .........  .........
2014 (Q4)..........................        600        800        800        800  .........  .........  .........
2015 (Q1)..........................        650        850        850  .........  .........  .........  .........

[[Page 49519]]

 
2015 (Q2)..........................        700        900  .........  .........  .........  .........  .........
2015 (Q3)..........................        750        950  .........  .........  .........  .........  .........
2015 (Q4)..........................        800  .........  .........  .........  .........  .........  .........
2016 (Q1)..........................        850  .........  .........  .........  .........  .........  .........
2016 (Q2)..........................        900  .........  .........  .........  .........  .........  .........
2014 (Q3)..........................        950  .........  .........  .........  .........  .........  .........
----------------------------------------------------------------------------------------------------------------

    Because of uncertainties in the supply of equipment and labor over 
the near-term, and based on our analysis described above, the EPA 
concludes that REC may not always be available through 2014. Therefore, 
during this period, the BSER for well completions is to combust 
completion emissions. REC with combustion as an alternative to 
combustion is permitted by the rule so that facilities that are able to 
obtain REC equipment may still capture completion emissions using a 
REC. After January 1, 2015, capturing completion emissions using a REC 
will be considered BSER. This period will permit the companies 
producing REC units to increase production to levels sufficient to meet 
new demand. In addition, because more REC will be performed as a result 
of this rule, the EPA believes that producers will take advantage of 
scale economies and use REC units at a higher rate of productivity than 
the rate implied by comments received.
    The EPA believes that the NSPS, as finalized, will minimize the 
risks of producers slowing well completion-related activities to obtain 
appropriate equipment and labor. While there would be NOX 
formation as a result from the additional combustion of completion 
emissions during the phase-in period, VOC emissions reductions would be 
maintained because completion emissions will be either combusted or 
captured. The EPA maintains that the benefit of the VOC reduction 
during the phase-in period far outweighs the secondary impact of 
NOX formation during pit flaring. The phase-in period would 
also minimize the possibility that the cost of REC equipment and labor 
increases over the near-term, enabling producers to better plan 
efficient use of existing and new capital and labor, and providing 
additional time for innovation in REC technologies and/or practices. We 
believe this period provides ample time for this technology to be built 
and available for use.
    At the same time, for wells undergoing recompletions during the 
period prior to January 1, 2015, the terms of 40 CFR 60.5365(h), which 
specify that ``[a] gas well facility that conducts a well completion 
operation following hydraulic refracturing is not an affected facility, 
provided that the requirements of section 60.5375 are met,'' may 
provide an additional incentive for producers to use REC units prior to 
January 1, 2015, if they can obtain appropriate equipment and labor. 
Also, considering the requirement in some states that any source 
subject to a federal NSPS must get a state minor source air permit, we 
anticipate that the desire to avoid even short term delays caused by 
state permitting, as well as the associated costs, will serve as an 
incentive for the use of REC during well completion operation following 
hydraulic refracturing, including operations prior to January 1, 2015. 
Furthermore, as January 1, 2015, approaches it is highly likely that 
providers of REC equipment and related services will be increasing 
availability of such equipment and services in ways that benefit supply 
and price. For these reasons, the EPA anticipates that during the 
period between promulgation and January 1, 2015, between 1,000 and 
1,500 wells will be recompleted with REC units, notwithstanding the 
requirements of 40 CFR 60.5375(a) and the combustion option they 
provide.
4. Cost and Emissions Calculations
    Comment: Some commenters request the EPA to fully explain or 
reconsider the 10-percent rate of refracturing of wells.
    Response: In response to comment, the EPA has reevaluated the 
assumption that, on average, each fractured gas well is re-fractured 
every 10 years, which equates to approximately 10 percent of fractured 
gas wells being re-fractured each year, based on drilling and re-
fracture records from an industry representative. Based on its review 
of the comment, including references noted in the comment and other 
information available to the agency, the EPA concluded that it had 
overestimated the re-fracturing frequency. The information reviewed by 
the EPA, which, altogether, represent over 20,000 gas wells over 
multiple years, some as far back as 2000, indicate that the annual 
recompletion frequency can be as low as 0.1 percent and as high as 0.8 
percent. Based on this information, the EPA has revised its estimate of 
re-fracturing frequency from 10 percent to 1 percent of fractured gas 
wells per year. The EPA rounded the figures provided by the companies 
to reflect the uncertainty in the data.
5. Definition of Affected Facility
    Comment: Several commenters assert that a well completion is 
different from a well workover and should be better defined in the 
rule.
    Response: Based on the comments received, the EPA acknowledges that 
the term ``workover'' is a general term that may have a number of 
different meanings. Based on the various definitions of the term 
provided by the commenters, we realize that workover may be interpreted 
to include routine maintenance activities that we did not intend to 
cover under the rule and which result in no increase in emissions. 
Therefore, in the final rule we have revised the definition of ``well 
completion operation'' to exclude the term ``workover'' and, instead, 
include the phrase ``with hydraulic fracturing.''

C. Major Comments Concerning Pneumatic Controllers

1. Definition of Affected Facility
    Comment: Some commenters request that the EPA consider excluding or 
exempting emergency and/or safety system devices (such as a pilot 
operated pressure relief valve). According to one commenter, safety 
system devices typically do not emit gas unless there is an emergency, 
have a near-zero VOC-level static state and, if regulated, could be 
replaced by substandard, cheaper technology of spring operated valves 
which would create much more leakage of gas into the environment.
    With regard to emergency situations, another commenter argues that 
the proposed standards that apply to pneumatic controller affected 
facilities (40 CFR 60.5390(b)) could inhibit safe plant operation 
during an emergency because they require that each pneumatic controller 
located at a natural gas processing plant have zero

[[Page 49520]]

natural gas emissions. According to the commenter, a gas-powered 
controller is a reliable alternative for safe plant operation during 
emergencies, and the commenter suggests that the final rule include an 
exception to allow gas plants to use natural gas-driven pneumatic 
controllers for emergency plant shutdown and subsequent startup.
    With regard to high-bleed pneumatic controllers, several commenters 
request that the EPA further explain when the use of high-bleed 
pneumatic controllers is allowed and provide specific examples of 
exemptions. The commenters suggest exemptions that address situations 
such as those where the natural gas includes impurities that could 
increase the likelihood of fouling a low-bleed pneumatic controller, 
such as paraffin or salts; where weather conditions could degrade 
pneumatic controller performance; during emergency conditions; where 
flow is not sufficient for low-bleed pneumatic controllers; where 
electricity is not available; and where engineering judgment recommends 
their use to maintain safety, reliability or efficiency. Several 
commenters request that the EPA provide additional information about 
how to demonstrate that the use of high-bleed pneumatic controllers is 
predicated, as stated in proposed 40 CFR 60.5390(a). The commenters 
suggest that this exemption is very vague, will allow for excessive 
emissions and is not enforceable.
    Response: The EPA included in the proposed rule exemptions from the 
NSPS to allow the use of a controller with a natural gas bleed rate 
greater than 6 scfh due to functional needs. These exemptions include, 
but are not limited to, response time, safety and actuation of valves. 
These functional exemptions to the requirement address the commenters' 
concerns of safety, emergency and otherwise non-routine situations that 
require the use of a controller with a natural gas bleed rate greater 
than 6 scfh. In response to comments regarding vagueness of the 
proposed exemption, the EPA revised this exemption provision in the 
final rule. We believe the provision in the final rule clarifies the 
scope of this exemption.
    Comment: Several commenters express concerns with the proposed 
rule's treatment of various types of pneumatic devices and controllers. 
One commenter requests that the EPA clarify in 40 CFR part 60, subpart 
OOOO that intermittent bleed pneumatic devices are not affected 
sources. Another commenter asserts that continuous low-bleed 
controllers that replace existing continuous low-bleed controllers 
should not be ``affected facilities.'' According to this commenter, 
some designed high-bleed devices may be isolated from the gas pressure 
with a valve and operated manually on an intermittent basis. The 
commenter wants clarification in the rule that will allow an operator 
to use a high-bleed device if it is operated in a manner that keeps its 
emission levels less than 6 scfh.
    One commenter requests that the EPA clarify in the final rule that 
the distribution segment and self-contained devices that release gas to 
a downstream pipeline instead of to the atmosphere are exempt. Another 
commenter argues that no-bleed pneumatic devices have zero emissions 
and, thus, should not be included in the proposed rule.
    One commenter discusses the use of solar-powered controllers, fuel-
cell powered controllers and mechanically-controlled devices in remote 
locations as an alternative to natural gas where grid electricity is 
not available. This commenter also recommends that the EPA set a zero 
emissions standard based upon no-bleed devices wherever electricity 
(either from a grid or from field power sources) is available within a 
reasonable distance from the facility and suggests that the EPA could 
establish an exemption to no-bleed devices where low-bleed devices are 
necessary because no-bleed devices cannot be feasibly installed.
    Another commenter states the definition of ``pneumatic controller'' 
is unclear and should be revised.
    Response: In the final rule, the EPA has revised the definition of 
``affected facility'' for pneumatic controllers in the production 
segment \24\ to address a number of the comments described above. 
Specifically, for pneumatic controllers at gas processing plants where 
the standard is zero bleed rate, we have defined the affected facility 
as a continuous bleed natural gas-driven pneumatic controller. For 
other areas in the production segment (i.e., excluding gas processing 
plants), where the standard is a bleed rate of 6 scfh or less, we have 
defined the affected facility as a continuous bleed natural gas-driven 
pneumatic controller operating at a bleed rate greater than 6 scfh. By 
defining the pneumatic controllers affected facilities to be continuous 
bleed and gas-driven, we clarify that the NSPS does not apply to 
intermittent bleed devices, no-bleed pneumatic devices (by design), 
self-contained devices and devices driven by instrument air. The 
revised definitions also exclude from the NSPS coverage owners and 
operators who are already using (including replacement) pneumatic 
controllers that meet the applicable standards, thus, relieving them 
from the cost and other burdens related to compliance.
---------------------------------------------------------------------------

    \24\ The NSPS does not cover pneumatic controllers in the 
distribution segment. The EPA did not address those controllers in 
the proposed rule. Although the EPA had proposed standards for 
pneumatic controllers in the transmission and storage segment, for 
reasons explained in section IX.C.2 of this preamble, the EPA did 
not include such standards in the final rule.
---------------------------------------------------------------------------

    Regarding the comments related to solar-powered controllers, fuel-
cell powered controllers, mechanically-controlled devices and no-bleed 
devices wherever electricity is available, we considered these types of 
devices in the BSER analysis, as discussed in the TSD. Any such 
controller system would require a backup system (consisting of at least 
an electrical generator) to operate the controllers when the primary 
system was inoperable. When considering the cost of the backup system, 
these options were not cost-effective. We, therefore, do not believe 
that they are BSER for reducing VOC emissions from pneumatic 
controllers where grid electricity is not available. We also decline to 
set a zero emission standard ``wherever electricity * * * is available 
within a reasonable distance,'' as a commenter suggests. We have no 
information, nor has the commenter provided any, on how to determine 
the suggested ``reasonable distance.''
    Comment: Several commenters request an exemption for all affected 
facilities handling gas with less than 10-percent VOC content by 
weight. Some commenters offer suggestions for such exemption, such as 
requiring recordkeeping of the gas VOC content in order for a facility 
to maintain the exemption.
    One commenter believes that the EPA should delete the pneumatic 
controller requirements because most of the gas emitted is methane, and 
there is little VOC emission reduction benefit. Another commenter 
suggests limiting applicability to pneumatic controllers at natural gas 
processing plants or upstream of processing that exceeds a defined VOC 
threshold.
    Several commenters opine that pneumatic device definitions and 
applicability should be based on VOC emissions, not natural gas as a 
surrogate. Commenters assert that the 6 scfh high-bleed/low-bleed 
threshold value is unsupported, that natural gas VOC content varies 
widely and that, in most cases, unconventionally produced CBM and shale 
gas have little, if any, measurable VOC.
    Several commenters also wanted to exclude pneumatic controllers 
driven by a specified percentage of VOC.

[[Page 49521]]

According to the commenters, regulating the use of compressed air or 
``instrument air'' or other gas having little or no VOC would impose a 
significant burden on the industry without any added benefit.
    Response: The EPA disagrees with the comment that the pneumatic 
controller standards must be based on VOC emissions instead of natural 
gas bleed rate as a surrogate for VOC emissions rate. Natural gas is 
being used as a surrogate for VOC given the proportional relationship 
between them. When a natural gas stream is emitted to the atmosphere, 
VOC in the gas also reaches the atmosphere since it is a component of 
the natural gas stream. The natural gas emissions occur without any 
physical separation, chemical separation or chemical reaction process 
of the chemical species within the natural gas; therefore, the 
proportion of VOC in natural gas is not altered during the course of 
being emitted to the atmosphere, and natural gas is an appropriate 
surrogate for VOC. As an example, when the natural gas emissions 
change, the VOC emissions change proportionately. In addition, 
measuring the VOC content of a pneumatic controller's bleed gas adds 
cost burden to companies and, to the EPA's knowledge, vendors/
manufacturers do not report the VOC emissions from a pneumatic 
controller primarily because the VOC emissions would depend on the gas 
composition at the site the pneumatic controller is located.
    In the preamble to the proposed rule, the EPA set forth its BSER 
analysis for pneumatic controllers. In the TSD, the EPA has provided 
cost-effectiveness calculations for the proposed pneumatic device 
emission limits. The commenters do not dispute the EPA's analysis. 
Rather, the commenters ask that the EPA establish a VOC threshold. 
However, the commenters have not provided information on how an 
appropriate threshold can be established. One commenter suggests a 
threshold of 10-percent VOC content by weight, but has not provided 
supporting information justifying this threshold. However, for the 
reasons stated in the response to comment in section IX.C.2 of this 
preamble, the EPA has decided not to cover in this final rule the 
pneumatic controllers in the transmission and storage segment. With 
respect to those controllers we are not taking final action at this 
time.
    Comment: One commenter suggested that the EPA provide a phase-in 
period to allow manufacturers and companies time to designate which 
controllers qualify as low-bleed. This commenter further notes that 
bleed rates are not specified for pneumatic controllers or are 
inconsistently represented without distinguishing between the 
continuous bleed stream and the actuation stream rates within the gas 
consumption specifications.
    Response: In the proposed rule, for pneumatic controllers \25\ in 
the production segment other than gas processing plants, the EPA 
proposed a performance standard of a natural gas bleed rate of 6 scfh 
to reflect the use of a low-bleed controller, which we had determined 
to be the BSER for reducing VOC emissions from pneumatic controllers in 
the production segment.\26\ Owners and operators would demonstrate 
compliance based on information in the manufacturers' specifications 
for the pneumatic controllers, which we had believed would provide 
either the bleed rate or relevant information for such determination. 
Upon further investigation, in light of the comments, we conclude that 
such information is not always included in current manufacturers' 
specifications. We anticipate that manufacturers who currently do not 
provide the relevant information for determining bleed rate would 
adjust to this need and begin testing their products and provide the 
necessary information on the products' specifications. Based on public 
comments and other available information, the EPA believes that an 
adjustment period is needed, during which owners and operators could 
face increased cost and, in some instances, difficulty in obtaining 
necessary supplies due to the limited number of currently available 
controllers with adequate documentation for determining bleed rate. In 
light of the above, we conclude that a low-bleed controller is not the 
BSER for pneumatic controller affected facilities in the production 
segment (excluding gas processing plants) during this first year. As 
explained in the proposed rule, we are not aware of any add-on controls 
that are or can be used to reduce VOC emissions from gas driven 
pneumatic devices. 76 FR 52760. One commenter broadly suggests that we 
consider flares, combustion devices and vapor recovery, but provides no 
supporting information. In light of the above, we conclude that there 
is no BSER for pneumatic controller affected sources in the production 
segment (excluding gas processing plants) during the ``adjustment 
period'' mentioned above.
---------------------------------------------------------------------------

    \25\ For the reasons explained earlier in this section, we have 
changed the definitions of the pneumatic controller affected 
facility in the production segment other than gas processing plants 
to be a continuous bleed natural gas driven pneumatic controller 
with a natural gas bleed rate greater than 6 scfh. This change does 
not affect the proposed BSER analysis and VOC limit, which apply to 
high-bleed pneumatic controllers in the final rule.
    \26\ For reasons explained in section IX.C.2 of this preamble, 
unrelated to the comment at issue, the final rule does not include 
standards for pneumatic controllers in the transmission and storage 
segment.
---------------------------------------------------------------------------

    In determining the length of the adjustment period, the EPA 
evaluated relevant comments and available information, including 
information from promulgation and implementation of 40 CFR part 98, 
subpart W of the Greenhouse Gas Reporting rule. Subpart W requires 
operators to conduct a complete inventory and report to EPA the number 
of low- and high-bleed pneumatic devices, as those terms are defined in 
subpart W, over a 3-year period (i.e., \1/3\ of their devices every 
year over a 3-year period) starting January 2011. We believe that 
efforts are well under way for manufacturers to provide necessary 
information to help facilities subject to subpart W determine the 
pneumatic controllers' bleed rates and comply with the reporting rule 
requirements, \1/3\ of which must be reported by September 2012 and 
another third by September 2013 and the entire inventory by September 
2014. In light of the above, we do not believe that owners and 
operators would face the difficulty described above beyond the first 
year after this NSPS becomes effective. After this first year of 
``adjustment period,'' we believe owners and operators should have no 
problem securing controllers with relevant documentation for 
determining bleed rate. Therefore, beginning the second year, the BSER 
remains the low-bleed controllers, as proposed.
    For the reasons stated above, the final rule contains no standards 
for pneumatic controller affected facilities in the production segment 
during the first year after this rule becomes effective, but, 
thereafter, requires that all new and modified affected facilities to 
meet a VOC limit of 6 scfh natural gas bleed rate to reflect the use of 
a low-bleed controller. The need for adequate manufacturers' 
specifications is not an issue for pneumatic controllers at natural gas 
processing plants. For pneumatic controller affected facilities at 
natural gas processing plants, we had proposed a zero VOC emission 
limit, the compliance of which can be demonstrated by the use of a non-
gas-driven controller system. As noted by commenters, most natural gas 
processing plants already use non-gas-driven technology such as 
instrument air systems for safety and operational reasons. While one 
cannot distinguish

[[Page 49522]]

gas-driven pneumatic controllers of different bleed-rates without 
information from manufacturers, a non-gas-driven controller can be 
easily identified by visual inspection. Therefore, no change is made 
since proposal to the standards for pneumatic controller affected 
facilities at gas processing plants.
    In response to comments that units already in stock at the time of 
proposal cannot be used, the EPA clarifies that pneumatic controllers 
that were already in stock or ordered prior to August 23, 2011, are 
considered existing sources and, therefore, their installation is not 
subject to the pneumatic controllers NSPS in this final rule.
2. Controllers in the Transmission and Storage Segment
    Comment: Several commenters requested the EPA reevaluate 
requirements for pneumatic controller/devices in the natural gas 
transmission segment of the industry. The commenters argue that the 
proposed rule's applicability is too broad and would result in an undue 
recordkeeping and permitting burden.
    Several commenters recommend that 40 CFR part 60, subpart OOOO 
should limit pneumatic controller applicability to upstream processes. 
Some commenters suggest that, for natural gas transmission and storage, 
either pneumatic controllers should be completely excluded or subpart 
OOOO should limit applicability to equipment located at 
``conventional'' facilities, e.g., within the fence line at a 
compressor stations. One commenter recommends limiting the emission 
limit requirement to controllers at natural gas processing plants or 
locations upstream from gas processing that exceed a defined VOC 
threshold. The commenter suggests that this exclusion would reduce 
administrative costs in two ways: Mandatory recordkeeping and reporting 
would be removed and the documentation required to explain why excluded 
controllers would no longer be necessary would be removed. Another 
commenter suggests that the EPA state in the final rule that NSPS/
NESHAP applicability alone should not trigger minor source permitting 
requirements.
    Response: The EPA agrees that cost and other compliance burdens are 
important considerations in a rulemaking. In fact, the EPA believes 
that such consideration is particularly important here given that 
coverage of the transmission sector would result in a significant 
number of sources and owner and operators that are not subject to the 
current standards. Specifically, were we to finalize standards, we 
estimate that we would end up covering an additional 67 sources. We 
estimate VOC emissions from these units to be 0.1 tpy per facility or 
about 6 tpy nationwide for new sources, which is well below the level 
emitted by other affected facilities in this sector.
    While our analysis suggests that this is an important set of 
sources to regulate, given the large number of sources, and the 
relatively low level of VOC emitted from these sources, we have 
concluded that additional evaluation of these compliance and burden 
issues is appropriate prior to taking final action on pneumatic 
controllers in the transmission and storage segment. For this reason, 
the requirements for pneumatic controllers in the final rule only apply 
to production through processing segments. Our current data indicate 
that the VOC content of the natural gas used for pneumatic controllers 
in the transmission and storage segment is low, while higher VOC 
content natural gas is used in the segments we are regulating. Also, 
for the reasons explained in the previous response to comment, no VOC 
threshold will be included in this regulation.
3. Cost and Emissions Calculations
    Comment: One commenter asserts that the EPA's estimate of 14,000 
new and replaced controllers in a given year is grossly underestimated. 
By the commenter's data and calculations, approximately 750,000 
controllers in Texas alone may need to be replaced (unless an exemption 
is granted) once a well becomes subject to the new rule.
    Response: The commenter incorrectly claims that the EPA's estimate 
of the number of pneumatic controllers installed in a given year is 
14,000. In Section 5.3.2 of the TSD, the EPA explains its methodology 
for estimating the number of pneumatic controllers in both gas/oil 
production and gas transmission and storage. Table 5-3 of the TSD gives 
a breakdown of snap-acting versus bleed controllers and shows the total 
number of controllers to be 33,673. The commenter did not provide data 
to support its claim that there are 750,000 pneumatic controllers in 
Texas, or that all of them have bleed rates higher than the proposed 
NSPS requirements such that any future replacement would require the 
use of a different model (i.e., low bleed or no bleed, depending on its 
location) of controller. In any event, the EPA has analyzed and 
determined that such replacement is cost-effective. One explanation for 
the commenter's high estimate may be a misunderstanding of the 
applicability of the final rule. We remind the commenter that the final 
rule does not apply to existing sources, unless the existing source is 
replaced, modified or reconstructed after August 23, 2011.

D. Major Comments Concerning Compressors

1. Compressors in the Transmission and Storage Segment
    Comment: One commenter stated that the agency should exempt 
reciprocating and centrifugal compressors in the transmission and 
storage sector located after the point of custody transfer, because 
there is low-VOC content in natural gas from that sector. Another 
commenter urged the EPA to revise 40 CFR 60.5365 to exclude centrifugal 
compressors not associated with the Crude Oil and Natural Gas 
Production, Transmission, and Distribution sector. One commenter noted 
that some large natural gas customers (who are not in the Crude Oil and 
Natural Gas Production, Transmission, and Distribution sector) have 
natural gas centrifugal compressors that are used to increase the 
pressure of natural gas for use in an industrial process, or to 
compress natural gas used as the fuel in compressed natural gas 
vehicles.
    One commenter argued further that even without regard to 
fundamental flaws stated in the five factors or methods, there still 
would be only trivial and inconsequential VOC reductions relative to 
the national VOC inventory. The commenter observed that achieving VOC 
reductions of 1 percent of the national anthropogenic VOC inventory 
would require over 21,000 regulations at 6.9 tpy, and that the EPA's 
estimated annual VOC reductions for compressors was similarly 
inconsequential. Nor, said the commenter, had the EPA adequately 
considered administrative burdens associated with reporting, 
recordkeeping and permitting. The commenter said the trivial, 
incremental emissions reductions that would result from the rule failed 
to justify the associated compliance costs and that the final rule 
should exclude transmission and storage sources. Another commenter 
expressly called on the EPA to reanalyze VOC emissions reductions and 
to reassess whether the rule would be cost effective. Also taking issue 
with supportive data, another commenter said the EPA should suspend 
rulemaking and expand its fact-finding to include a statistically 
significant sampling of affected sources. One commenter suggested that 
the EPA exclude centrifugal compressor facilities that compress natural 
gas that is less

[[Page 49523]]

than 10 percent, weight basis, VOC. The commenter stated that 
compression of gas that does not contain VOC should not be subject to 
standards for VOC. The commenter believes this is consistent with 
equipment leak rules which do not regulate components that are not in 
VOC service.
    Response: The EPA agrees with the commenter that natural gas in the 
transmission and storage segment has low-VOC content. The EPA notes 
that cost and other compliance burdens are important considerations in 
a rulemaking. We estimated the VOC emissions reductions from these 
units located in the transmission and storage segment to be 14.1 tpy 
for reciprocating compressors and 6.6 tpy for centrifugal compressors, 
which is well below the level emitted by other affected facilities in 
this segment. The EPA has not fully considered compliance burden for 
reciprocating and centrifugal compressors in the transmission and 
storage segment and is, therefore, not ready to take final action with 
respect to these sources. While our analysis suggests that this is an 
important set of sources to regulate, given the number of sources, and 
the relatively low level of VOC emitted from these sources, we have 
concluded that additional evaluation of these compliance and burden 
issues is appropriate prior to taking final action on reciprocating and 
centrifugal compressors in the transmission and storage segment.
    Also, no VOC threshold will be included in this regulation given 
the arbitrary nature of defining one using available data. We believe 
this revision also addresses centrifugal compressors not associated 
with the Crude Oil and Natural Gas Production, Transmission, and 
Distribution sector.
2. Dry Seals Versus Wet Seals
    Comment: Several commenters address the issue of whether the EPA 
should permit the use of a system other than dry seal to control 
emissions from centrifugal compressors. Some commenters provide 
information on situations where dry seal systems for centrifugal 
compressors are not technically feasible, such as where gas composition 
is inadequate, in some processing plants that already have a capture 
system in place, and in retrofits of some existing compressors due to 
housing design or operational requirements. Commenters opine that the 
rule should allow compliance using either system, depending upon 
particular circumstances, and should not preclude use of a wet seal-
equipped compressor with controls capable of meeting a 95-percent VOC 
control efficiency or routing captured seal-oil gas to a fuel gas, 
recycling or other processing system. According to another commenter, 
it would not be feasible to capture gas that escapes from a centrifugal 
compressor and route it back to a low-pressure fuel stream for 
combustion as fuel gas; although such a process would capture a minimal 
amount of VOC emissions, the high cost of equipment to recapture the 
emissions would make the method described cost-prohibitive.
    Commenters generally concurred that a 95-percent reduction in 
emissions was achievable through installing a capture system on a wet 
seal compressor. In addition, commenters disagreed with the EPA's cost 
estimates and concluded that a wet seal capture system is cost 
effective.
    Response: In the preamble to the proposed rule, the EPA proposed 
that a dry seal system is the BSER for centrifugal compressors, but 
solicited comments on situations where the use of a dry seal is 
infeasible or otherwise inappropriate and wet seal is the only option. 
76 FR 52762. As noted above, several commenters provided information on 
situations where dry seals are not technically feasible. Therefore, the 
EPA has concluded that dry seal is not the BSER for all new and 
modified centrifugal compressors. Instead, the EPA separately evaluates 
the control options for wet seal compressors. The EPA has identified 
one control option through its review of available information, 
including comments and other information obtained since proposal. The 
option is to route captured seal-oil gas to the compressor suction, 
fuel gas system or flare, all of which can achieve 95-percent control 
efficiency.
    Based on the discrepancy between commenters' and the EPA's cost 
data, the EPA re-evaluated its cost information for this control 
option. The EPA cost estimates in the proposed rule assumed the use of 
a new flare to combust the captured seal oil gas, and, based on 
commenter information, the EPA is revising this assumption since a 
flare or other combustion source is expected to be available in gas 
processing facilities. From reviewing comments received, the EPA is 
aware that the captured gas is not always routed to a flare but in many 
cases is routed back to the compressor suction or fuel system. Given 
this information, the EPA has re-evaluated the costs for the 
centrifugal compressor wet seal capture system and determined a system 
of this type, in which the seal oil degassing vents are routed to fuel 
gas, compressor suction or an existing flare would cost $22,000. The 
estimated cost includes an intermediate pressure degassing drum, new 
piping, gas demister/filter and a pressure regulator for the fuel line. 
With this cost, the estimated VOC control cost effectiveness is $161/
ton of VOC for the processing segment. If savings are included, the 
cost effectiveness for VOC control is -$2,408/ton of VOC.
    In light of the above, we have determined that the control option 
described above is the BSER for wet seal compressors. Accordingly, the 
final NSPS would require that wet seal compressors reduce emission by 
95 percent. For dry seal compressors, the only emission control option 
we have identified is the use of dry seal. Accordingly, there is no 
requirement in the final rule for dry seal compressors, and dry seal 
compressors are not affected facilities under the NSPS.
3. New Source Definition
    Comment: Several commenters oppose the proposal in 40 CFR 
60.5365(b) and (c) that a reciprocating compressor be considered as 
``commenced construction'' on the date of installation at a facility. 
Commenters argue that the EPA was ``arbitrary and capricious'' in 
proposing to apply the concept of ``commenced construction'' in the 
NSPS context to a relocated compressor, because the agency had no 
``reasoned explanation'' for making the change and that applying the 
concept of ``commenced construction'' to a relocated compressor is 
contrary to the plain language of the CAA.
    Response: The EPA traditionally defines the term ``commence 
construction,'' as it applies to an equipment, to mean the time an 
owner or operator has entered into a contractual obligation to acquire 
the equipment. This is reflected in the definition of ``commenced'' in 
the General Provisions at 40 CFR 60.2, as well as in the relevant NSPS 
(see, e.g., 40 CFR 60.4230(a) of subpart JJJJ). We, therefore, agree 
with the commenters that our proposed definition of ``commence 
construction'' in 40 CFR 60.5365(b) and 40 CFR 60.5365(c) as the time 
of installation is a deviation from our traditional view. Upon 
reviewing the comments and re-evaluating the proposed definition, we 
conclude that there is no discernible difference between the 
compressors at issue and other equipment subject to NSPS that would 
make such deviation necessary or appropriate in this case. We have, 
therefore, removed these specific definitions of ``commence 
construction'' in 40 CFR 60.5365(b) and 40 CFR 60.5365(c) in the final 
rule.

[[Page 49524]]

    The NSPS also does not apply to relocated compressors. As provided 
in the NSPS General Provisions at 40 CFR 60.14(e)(6), relocation of an 
existing facility is not modification.

E. Major Comments Concerning Storage Vessels

1. Applicability Threshold Metric
    Comment: Numerous commenters objected to the EPA's proposed use of 
liquid throughput to determine which storage vessels should be subject 
to the standards, asserting that the high variability in volatility of 
stored liquids and other parameters affecting emissions makes 
throughput a poor indicator of VOC emissions. The commenters indicate 
that, as a result, basing applicability on throughput would bring many 
storage vessels with low VOC emissions (some less than 1 tpy) under the 
standard and the required emission controls would not be cost-
effective. Some commenters point out that certain storage vessels with 
high emissions might not be subject to the standards based on 
throughput.
    Response: In its BSER analysis for storage vessels, the EPA 
estimated the VOC emissions for storage vessels with various levels of 
throughputs to determine the cost effectiveness of control. In that 
analysis, the EPA estimated that storage vessels with throughput rates 
of 1 barrel per day (bpd) of condensate or 20 bpd of crude oil are 
equivalent to VOC emissions of 6 tpy and determined that control is 
cost effective for these storage vessels. The EPA agrees with the 
comments that throughput is not a good indicator of VOC emissions and, 
therefore, not appropriate for determining the standards' 
applicability. However, the EPA has received no comment contesting the 
EPA's conclusion that regulating storage vessels emitting 6 tpy or more 
of VOC is cost effective and appropriate (the basis of our proposed 
throughput limit). Accordingly, in the final rule, the storage vessels 
NSPS applies to those emitting 6 tpy or more of VOC. This change from 
proposal would ensure that controls will be required only on those 
storage vessels where they can be applied cost effectively. This 
approach also allows for broader coverage across all types of storage 
vessels, regardless of the fluid that is stored or where the storage 
vessel may be located. The final rule reflects this change and has 
established a VOC emissions threshold of 6 tpy for storage vessels to 
require control. Based on our revised cost analysis, we determined that 
storage vessels with VOC emissions equal to or greater than 6 tpy or 
greater were cost effective to control at $3,400/ton of VOC. The final 
rule requires each facility to determine its own emission factor and 
calculate the estimated emissions from each storage vessel.
2. Definition of Affected Facility
    Comment: Numerous commenters commented on the definition of storage 
vessel in 40 CFR part 60, subpart OOOO, calling for greater clarity and 
consistency and requesting that certain activities or equipment be 
included or excluded from the definition.
    Response: The EPA agrees with the commenters who assert that a more 
specific and consistent definition of a storage vessel is needed. The 
revised definition more clearly focuses on identifying which units are 
considered storage vessels under this subpart and which units are not 
and describes a storage vessel using terminology similar to that used 
in 40 CFR part 63, subpart HH. We believe it is important to be 
somewhat consistent in terminology because the NSPS and NESHAP both 
apply to the oil and natural production segment where these tanks are 
primarily located. We also removed the emissions threshold from the 
definition and, instead, based the standard in 40 CFR 60.5395 on the 
VOC emission rate of the storage vessel. In response to comments 
requesting clarification on whether mobile units are considered storage 
vessels, we have set a minimum amount of time (180 consecutive days) 
that the storage vessel must be stationed at the same site before it is 
subject to 40 CFR part 60, subpart OOOO. Our reasoning for setting this 
minimum amount of time is discussed in the response to comment 
immediately below. Additionally, we have not excluded wastewater 
storage vessels, as the NSPS requires control for all storage vessels 
emitting at least 6 tpy of VOC. Further, some wastewater tanks 
containing significant amounts of organic compounds could exceed VOC 
emissions of 6 tpy. Finally, the revised definition includes specific 
exemptions for process vessels and pressure vessels to clarify that 
these units are not considered storage vessels. Since the applicability 
of subpart OOOO, as finalized, is not based on throughput, we believe 
it is not necessary to specify which types of stored materials are 
regulated and which are not, as suggested by commenters. If a stored 
material is emitting at least 6 tpy of VOC, then the storage vessel 
will need to reduce its VOC emissions by 95 percent.
    Comment: Some commenters assert that the EPA should limit 
applicability to storage vessels that are stationary and should clarify 
the meaning of ``stationary'' to include or exclude certain types of 
storage vessels.
    Additionally, the EPA received comments requesting that the 
stationary aspect of the ``storage vessel'' definition should be 
consistent with other rules, while acknowledging the particular 
scenarios unique to the oil and gas production segment. The commenter 
notes that the stationary aspect of a storage vessel is typically 
addressed by the EPA in terms of whether it is reasonably portable, 
although the EPA sometimes addresses portability based on the size of 
the vessel. The commenter states that another criterion specified by 
the EPA in several regulations is that ``vessels permanently attached 
to motor vehicles'' are not storage vessels, and the EPA has issued a 
determination that this exemption extends to storage vessels ``equipped 
with a permanently attached wheel assembly and a truck hitch'' (U.S. 
Environmental Protection Agency, letter from George T. Czerniak to Ken 
Comey, Flint Hills Resources L.P., September 2, 2004). According to the 
commenter, this renders most so-called frac tanks, Baker tanks, 
International Organization for Standardization tanks, etc., exempt from 
the storage vessel provisions when this form of definition is used. 
However, the commenter recognizes that such storage vessels sometimes 
become effectively ``stationary'' in oil and gas production operations 
and suggests that storage vessels should be deemed stationary if they 
remain at a given site for more than 180 consecutive days, consistent 
with the period of time allowed under 40 CFR 60.14(g) to achieve 
compliance after a modification. The commenter notes that this 180-day 
period is reasonable given that the definition of non-road engines in 
40 CFR 89.2 allows a period of 12 consecutive months.
    The commenter also points out that cost effectiveness of the 
proposed control measures has been evaluated under the assumption that 
storage vessels remain in place for the useful life of the control 
equipment, and, thus, the control costs are amortized over a period of 
years. Since the cost per ton of emission reductions would be much 
higher if the controls were applied to a storage vessel that is only on 
site temporarily, the commenter believes that a cost-effectiveness 
analysis for permanent storage vessels would not be valid for temporary 
storage vessels, and, thus, the control requirements for permanent 
storage vessels are not justified for temporary storage vessels. The 
commenter provides recommended language for the definition of ``storage 
vessel'' that addresses this and other

[[Page 49525]]

concerns. Another commenter similarly states that costly control 
requirements are not appropriate for temporary storage vessels (on site 
less than 180 days).
    Response: Based on the commenter's suggestion, the EPA has revised 
the definition of storage vessel to clarify that a storage vessel is 
subject to 40 CFR part 60, subpart OOOO if it remains on a given site 
for more than 180 consecutive days.
    In general, we agree with the commenter's discussion about the 
EPA's past practices related to storage vessels. In particular, we 
agree that the inherent differences between ``mobile'' or temporary 
storage vessels in this source category and other categories indicate 
that they should be regulated differently. As mentioned in the previous 
response, there are many storage vessels in this source category that 
travel from site to site, so we did not feel it was appropriate to 
exclude all of these mobile storage vessels from control requirements. 
Many temporary storage vessels in this source category are typically 
bringing in material such as fracking fluid to well sites and can stay 
at a well site for up to several months in order to receive flowback. 
These storage vessels are considered to be an essential part of the 
drilling and production operation, more akin to how permanent storage 
vessels are utilized in the refining and organic chemical manufacturing 
sectors, rather than to conventional tank trucks that are typically 
excluded in other EPA rules. Therefore, we believe that 180 days is an 
appropriate period of time to establish a temporary tank as being 
subject to 40 CFR part 60, subpart OOOO, and, therefore, potentially 
required to install controls.
3. References to MACT Standards
    Comment: The EPA received comment asserting that the outcome of its 
best demonstrated technology (BDT) analysis for proposed 40 CFR part 
60, subpart OOOO was calculated to achieve the same level of control as 
40 CFR part 63, subpart HH--undermining the BDT determination and 
effectively (and unlawfully) extending subpart HH major source MACT 
requirements to area source storage vessels.
    As a result, the commenter asserts that the EPA's analysis 
precludes other potentially relevant regulatory alternatives--such as 
marginally less effective controls that might be applied to a broader 
range of storage vessels. The commenter states that the EPA's failure 
to consider other control techniques and other levels of control 
efficiency that might be achieved by its preferred techniques is 
arbitrary and capricious.
    Response: The commenter incorrectly asserts that the EPA's NSPS for 
storage vessels was designed to achieve the same level of control as 
MACT in 40 CFR part 63, subpart HH. In Portland Cement Assoc. v. EPA, 
665 F.3d 177 (D.C. Cir. 2011), the United States Court of Appeals for 
the District of Columbia Circuit rejected an argument that the EPA 
adopted NESHAP PM standards for NSPS, noting that the EPA arrived at 
the same limit for both NESHAP and NSPS using two different mechanisms. 
Similarly, in this case, although both the NESHAP and the NSPS require 
95-percent control, the EPA established the two standards based on 
separate mechanisms. The EPA established the MACT standard in 1998 
pursuant to section 112(d)(2) and (3) of the CAA. In contrast, the EPA 
established the NSPS based on BSER analysis under CAA section 111. The 
BSER analysis for storage vessels consists of the same steps as those 
for other affected sources evaluated in the proposed NSPS. 
Specifically, the EPA evaluated available information to identify VOC 
control options. The EPA then assessed various aspects of the control 
options, including their VOC reduction potentials, their cost 
effectiveness and secondary air impacts. The commenter did not claim 
that any part of the EPA's BSER analysis above was inaccurate or 
inappropriate. For the reasons stated above, the commenter's assertion 
is without support.
    The commenter also claims that the EPA only analyzed two controls 
and, therefore, failed to consider other ``potentially relevant 
regulatory alternatives.'' However, the commenter did not identify any 
other control option for the EPA's consideration. The commenter simply 
suggests that the EPA should consider some less effective controls, 
which the commenter claims would have led to greater coverage. Without 
more information, it is unclear whether a less effective control than 
that we have identified would, in fact, qualify as BSER for controlling 
VOC emissions from storage vessels or would have resulted in coverage 
of additional storage vessels.
    Comment: Two commenters state that the cost of the performance 
tests, monitoring, recordkeeping, etc., that are required through 
cross-references to 40 CFR part 63, subpart HH were not adequately 
considered by the EPA in the cost-effectiveness determination for 40 
CFR part 60, subpart OOOO, which applies to dispersed locations that do 
not have electricity or automation, and have limited remote 
transmitting unit space.
    Response: The EPA does not take into account monitoring, 
recordkeeping and reporting costs in determining cost effectiveness of 
controls and in evaluating BSER. Based on this and other comments 
detailed in the response to comments for this final rulemaking, the EPA 
removed from 40 CFR part 60, subpart OOOO the citations to the 
requirements for performance tests, monitoring, recordkeeping, etc., in 
40 CFR part 63, subpart HH and incorporated these subpart HH 
requirements into subpart OOOO. During the incorporation process, we 
made minor revisions to the subpart HH requirements, as appropriate for 
subpart OOOO. For example, we removed references to glycol dehydrators 
and paragraphs listed as ``reserved.''
4. Availability of Control Equipment
    Comment: Some commenters believe that there will be a shortage of 
control equipment available to meet the proposed storage vessel 
requirements, and recommend revisions to the compliance deadline for 
storage vessels based on a variety of considerations, including the 
availability of control devices, lead time needed for manufacturer 
testing of their combustors to be compliant with the NSPS and time 
needed to install the compliant devices.
    Response: We agree that it will likely take some time beyond the 
promulgation date of the NSPS for combustor manufacturers to have 
control devices constructed, tested, documented and available for 
operators to install in efforts to comply with the storage vessel 
requirements of the NSPS. Under the final rule, operators are not 
required to conduct individual performance tests on combustors 
installed in the field if the combustor manufacturer tests and 
documents for the owner or operator that the model achieves a control 
efficiency of 95.0 percent. The time required for testing and 
documentation is often longer than for a single model when 
manufacturers provide multiple models for varying applications based on 
capacity. We believe this testing and documentation program would 
require an ``adjustment period'' for manufacturers to be ready to 
supply the operators with the correct equipment they need.
    We considered whether it would be feasible for on-site testing to 
mitigate the shortage of manufacturer tested combustors. Although 
owners and operators can test their individual combustors in the field 
to determine combustor efficiency, such emissions testing is expensive 
and can only be

[[Page 49526]]

performed if testing consultants are available to conduct the testing. 
We believe that immediately after the effective date of the NSPS there 
will be a shortage of available testing consultants concurrent with the 
shortage of pre-tested combustor models. As a result, we conclude that 
on-site testing would not sufficiently mitigate the difficulty of 
owners and operators complying with the NSPS.
    We evaluated whether controls other than combustors would be 
available during this adjustment period. Although vapor recovery units 
(VRU) can provide 95.0-percent control for storage vessels and are one 
means of meeting the storage vessel standards in the NSPS, VRU cannot 
be used in every situation. For example, storage vessels located 
remotely where there is no available electrical service may not be able 
to be controlled using VRU. In addition, storage vessels with low 
concentration emission streams or fluctuating emissions may not be 
amenable to control by VRU. Further, VRU installations would also 
require on-site testing, and owners and operators would be hampered by 
the same consultant shortage situation described above for combustors.
    In light of the above, we conclude that there is no BSER for 
storage vessel affected sources during the first year after 
promulgation, which we believe is appropriate for the adjustment period 
mentioned above. At the end of this adjustment period, we believe 
owners and operators should have no problem securing control devices 
that are manufacturer-tested and have appropriate documentation for 
determining control efficiency. Accordingly, the final rule provides 
for a 1-year phase-in beginning October 15, 2012 before the 95.0-
percent control requirement is effective.
    With regard to providing time for operators to establish the need 
for controls and install them where called for, the EPA agrees that 
some lag time may be needed after initial start-up for the owner or 
operator to determine the long-term production level of a well and to 
procure the appropriate control equipment. The EPA evaluated the 
approach taken in the Wyoming rules for new sources, which allows from 
30 to 90 days for a source to achieve compliance, depending on the area 
of the state. Wyoming allows only 30 days in ozone nonattainment areas, 
60 days for concentrated development areas or 90 days elsewhere in the 
state. The EPA believes that 60 days is a reasonable period for 
controlling new storage vessels at wells sites with no wells already in 
production.
    However, for replacement storage vessels or additional storage 
vessels at well sites with one or more wells already in production, we 
believe the operator already should have information on liquid 
composition and throughput. This information would allow estimation of 
VOC emissions to determine applicability of control requirements and 
for acquisition and installation of a control device concurrent with 
the replacement or additional storage vessel being installed. In the 
final rule, for storage vessels constructed, modified or reconstructed 
at well sites with no well already in production, we have provided for 
a 30-day period for throughput to stabilize and for the operator to 
estimate VOC emissions to determine whether a control device will be 
required. If VOC emissions are estimated to be at least 6 tpy, the 
operator is provided an additional 30 days for the control device to 
become operational. We believe that the Wyoming experience illustrates 
that this will be sufficient time to size and obtain suitable controls.

F. Major Comments Concerning Notification, Recordkeeping and Reporting 
Requirements

1. 30-Day Notification and Annual Reports
    Comment: Multiple commenters state that the 30-day advance 
notification of well completions under 40 CFR 60.5420(a) should be 
removed from the final rule. Commenters assert that this and 
notification requirements in 40 CFR 60.7(a) are unduly burdensome and 
costly, not adequately explained, not related to verifying compliance 
with the proposed rule and could conflict with the need to protect 
proprietary business information.
    Multiple commenters also note that industry's estimate of annual 
completions is several times higher than the EPA's estimate of 20,000 
completions following fracturing and completions following refracturing 
annually. The commenters believe that these requirements will likely 
overwhelm both regulated entities and state regulators alike. 
Commenters offer suggestions, including requiring annual certifications 
or maintaining records available for inspection, reducing the proposed 
advance notification requirement to 5-10 days and considering 
notification programs such as those in Texas and Wyoming. Different 
commenters support or oppose requiring a 30-day advance notice with 
follow-up notification of 1-2 days before an impending completion.
    Several commenters suggest that the EPA should coordinate with 
state and local agencies to eliminate duplicative recordkeeping and 
reporting requirements, and that records of interest other than those 
submitted to the respective Oil and Gas Commissions should only be 
required to be retained and available upon inspection, similar to other 
permit requirements.
    Several commenters do not agree that an annual report under 40 CFR 
60.7(a)(1), 40 CFR 60.7(a)(3) and 40 CFR 60.7(a)(4) adds any value for 
verifying compliance and the EPA should remove this requirement from 
the final rule. The commenters add that the best method for compliance 
is for an owner or operator to maintain necessary records and to have 
the records available for review during an on-site inspection. One 
commenter suggests the annual report should include for each type of 
affected facility (1) the total number of affected facilities at the 
site; (2) the number of facilities that became affected facilities 
during the reporting period; (3) the number of exempted facilities; and 
(4) the number of affected facilities with a non-compliance situation 
during the reporting period. One commenter suggests that it would be 
easier for facilities to submit an annual report on a set date each 
year, and multiple affected facilities could be included in a single 
report. Two commenters propose that all notifications for each year be 
delivered in a single annual report corresponding to the reporting 
period in which the affected facilities become subject to the rule. One 
commenter suggests that operators should be required to keep records at 
the nearest manned office, but reports should only be required if they 
are requested by the EPA.
    The commenters recommend, where feasible, streamlining the final 
notification and reporting requirements to eliminate unduly burdensome 
notification and reporting requirements.
    Response: The EPA agrees that certain notification, recordkeeping 
and reporting requirements in the General Provisions are unduly 
burdensome for the new affected facilities in this NSPS. For that 
reason, well completions, pneumatic controllers and storage vessels 
will be exempt from the notifications required by 40 CFR 60.7(a)(1), 
(3) and (4). We agree that notifications of well completions should be 
as streamlined as possible to remove excess burden from both the owners 
and operators and regulatory agencies, as well. As a result, we have 
removed the 30-day advance notification requirement and instead are 
requiring an advance notice via email to the EPA or delegated

[[Page 49527]]

authority no later than 2 days prior to completion.
    To avoid duplicative and potentially conflicting notification 
requirements and to relieve notification burden from owners and 
operators, we have added a provision in the final rule that, if an 
owner or operator has met the state requirements for advance 
notification of well completions, then the owner and operator are 
considered to have met the advance notification requirement for gas 
well completions under the NSPS.
    We also believe that the operator should be provided flexibility to 
use new technology to document compliance that would result in less 
paperwork burden on the part of the operators themselves and on 
regulators. To lessen the reporting burden, the final recordkeeping and 
reporting requirements for well completions also provide for a 
streamlining option that owners and operators may choose in lieu of the 
standard annual reporting requirements. The standard annual report must 
include copies of all well completion records for each gas well 
affected facility for which a completion operation was performed during 
the reporting period. The alternative, streamlined annual report for 
gas well affected facilities requires submission of a list, with 
identifying information of all affected gas wells completed, electronic 
or hard copy photographs documenting REC in progress for each well for 
which REC was required and the self-certification required in the 
standard annual report. The operator retains a digital image of each 
REC in progress. The image must include a digital date stamp and 
geographic coordinates stamp to help link the photograph with the 
specific well completion operation. Operators are not required to take 
advantage of the optional recordkeeping and reporting approach, as some 
may choose to follow the standard reporting requirements. Under either 
approach, the report must include a record of all deviations during the 
reporting period in cases where well completion operations with 
hydraulic fracturing were not performed in compliance with the 
requirements for each gas well affected facility.
    Comment: One commenter requested that the EPA add a self-
certification requirement to the annual report similar to that used in 
the title V program. The commenter recommended that the final rule 
require the annual report to include a statement signed by a senior 
official of the facility attesting to the truth, accuracy and 
completeness of the report.
    The commenter also requested that the EPA require that the annual 
reports be submitted electronically to facilitate making the reports 
publicly available. The commenter suggested using social media outlets, 
smart phone applications and other electronic means to make the annual 
reports readily available.
    Response: The EPA agrees that self-certification is an important 
mechanism for assuring the public that the information submitted by 
each facility is accurate. In addition, the title V program has 
successfully employed self-certification since its inception. 
Therefore, we are requiring self-certification, based on requirements 
in the title V program, in the final rule.
    While we agree that having annual reports readily available to the 
public is a desirable goal, we did not identify any reporting programs 
or electronic databases that may be used for this purpose without 
significant modification. Therefore, we are not requiring annual 
reports to be submitted electronically, but we will continue to 
evaluate this option in the future.
2. Duplicative Recordkeeping and Reporting Requirements
    Comment: Multiple commenters state that the notification, 
recordkeeping, monitoring and annual reporting requirements in the 
proposed NSPS are duplicative and extremely burdensome for operators 
and for state regulators with limited resources. The commenters make 
both general and specific recommendations to revise the reporting 
requirements in the final rule to eliminate duplication and reduce 
burden or better inform the public and regulatory agencies about 
deviations. Some commenters would eliminate all or some reports, while 
others argue that reporting is an essential compliance and enforcement 
mechanism and that additional information should be provided. Some 
commenters feel that an owner or operator should maintain necessary 
records and have them available for review.
    Commenters want the compliance assurance requirements to be 
appropriate for the oil and gas industry and commensurate to the 
environmental benefit that will be generated. For example, some 
commenters feel that the EPA should exempt small sources regulated 
under this rule from the notification and reporting requirements.
    Response: We have considered these and other related comments 
presented in the response to comments regarding the proposed reporting 
requirements. The EPA agrees that certain notification, recordkeeping 
and reporting requirements are unduly burdensome and believes it is 
important to minimize the burden of reporting requirements. However, as 
noted in several comments, states and other enforcement entities are 
confronting limited resources and visiting sites is not always 
practical and is particularly challenging in this industry. For that 
reason, the EPA believes notifications and reporting requirements are 
vital to ensure compliance with our regulations. Therefore, the EPA has 
evaluated the proposed notification, recordkeeping and reporting 
requirements in an effort to streamline the requirements to reduce 
burden on both industry and enforcement at the same time, assuring 
compliance with the NSPS. In the final rule, the EPA has removed or 
otherwise revised proposed reporting requirements that the EPA believes 
to be duplicative or unnecessary, including, but not limited to, those 
raised in the comments. These changes will streamline the reporting 
process and reduce the reporting burden on sources, including small 
sources. For example, as previously discussed, well completions and 
continuous bleed natural gas controllers are exempt from the 
notifications required by 40 CFR 60.7(a)(1), 40 CFR 60.7(a)(3) and 40 
CFR 60.7(a)(4). In addition, the EPA has revised the rule language such 
that only continuous bleed natural gas controllers installed, modified 
or replaced during the reporting period are reported in the annual 
report. In addition, the EPA has revised the 30-day individual 
notification requirement for well completions, as discussed above.
3. Electronic Reporting of Emissions Data
    Comment: Commenters suggest a variety of ways in which electronic 
reporting could be structured and implemented, with attention to 
coordination with various CAA requirements and programs to avoid 
duplicative and potentially burdensome requirements. Several commenters 
support electronic reporting of emissions data from all sources to be 
stored on existing EPA databases, such as the Electronic Greenhouse Gas 
Reporting Tool (e-GGRT) or added to the Toxics Release Inventory, and 
available to the public. These commenters believe that communities must 
have access to air quality information in order to protect public 
health. One commenter objects to the use of e-GGRT as a reporting 
mechanism in place of a state's own tracking system, where the state 
has enforcement responsibility for the emissions date and tracking of 
sources subject to the proposed rule. The commenters also suggested a 
variety of ways in which electronic

[[Page 49528]]

reporting could be structured and implemented.
    Several commenters oppose the implementation of electronic 
reporting at this time and are concerned that an ERT will result in 
numerous complications and undue additional burden. The commenters 
point out that the EPA's experience with e-GGRT indicates that 
considerable time and resources are needed to develop and implement 
efficient systems and to ensure that electronic reporting enhances 
efficiency rather than incurring additional burden on affected sources. 
The commenters state that a potential disadvantage associated with an 
ERT is that new and/or alternative test methods would not be in the 
system. In addition, the commenters believe that an ERT could be 
complicated and burdensome for smaller companies that lack 
environmental personnel or experience with electronic reporting under 
other rules. The commenters suggest that if the EPA delegates authority 
to states to implement and enforce the standards, some states may be 
unable or unwilling to accept electronic reports. The commenters urge 
the EPA to consider other more simplified options to report only the 
needed information.
    Response: While the EPA supports and encourages electronic 
reporting, after further consideration of all the comments, we do not 
believe the e-GGRT is the appropriate mechanism for electronic 
reporting under this rule, as recommended by some commenters. The e-
GGRT is not designed to accept all of the types of information required 
to be reported under the final rule, and significant modification of 
the system would be required to make it operational for this rule.
    However, the final rule does include reporting of performance test 
data via the ERT. The EPA must have performance test data to conduct 
effective reviews of CAA sections 112 and 129 standards, as well as for 
many other purposes, including compliance determinations, emission 
factor development and annual emission rate determinations. In 
conducting these required reviews, the EPA has found it ineffective and 
time consuming, not only for us, but also for regulatory agencies and 
source owners and operators, 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.
    In the final rule, as a step to increase the ease and efficiency of 
data submittal and improve data accessibility, the EPA is requiring the 
electronic submittal of select performance test data. Data entry will 
be through an electronic emissions test report structure called the 
ERT. The ERT will generate an electronic report which will be submitted 
using the CEDRI. The submitted report is submitted through the EPA's 
CDX network for storage in the WebFIRE database making submittal of 
data very straightforward and easy. Webfire is the EPA's online 
emissions factor repository, retrieval and development tool. The 
WebFIRE database is open to the public and contains the EPA's 
recommended emissions factors for criteria and HAP for industrial and 
non-industrial processes. Emissions data collected from the oil and 
natural gas sector, as well as many other sectors, will be used to 
update our emissions factors. The data will also be used by the EPA's 
rule writers to make better informed decisions and learn more detailed 
information about emissions from sources. The electronic reporting 
requirement in this rule (and other NSPS/NESHAP rules) is only for test 
methods that are supported by the ERT.
    One major advantage of submitting 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 what testing information 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.
    State, local and tribal agencies can also benefit from a more 
streamlined and accurate review of electronic data submitted to them. 
The ERT allows for an electronic review process rather than a manual 
data assessment making review and evaluation of the data and 
calculations easier and more efficient. Finally, another benefit of 
submitting data to WebFIRE electronically is that these data will 
greatly improve the overall quality of the existing and new emission 
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 will be able to ensure that emission 
factors, when updated, represent the most current range of operational 
practices.

X. Summary of Significant NESHAP Comments and Responses

    For purposes of this document, the text within the comment 
summaries was provided by the commenter(s) and represents their 
opinion(s), regardless of whether the summary specifically indicates 
that the statement is from a commenter(s) (e.g., ``The commenter 
states'' or ``The commenters assert''). The comment summaries do not 
represent the EPA's opinion unless the response to the comment 
specifically agrees with all or a portion of the comment.

A. Major Comments Concerning Previously Unregulated Sources

    Comment: One commenter asserts that, although the EPA's original 
MACT analysis covered all storage vessels, it issued a MACT standard at 
that time that applied to storage vessels with the PFE only. The 
commenter states that, while they support the EPA's effort to correct 
this omission, the initial analysis for the tanks that the agency did 
regulate in 1999 was seriously flawed, and the proposed rule provides 
no justification for continuing to rely on a 13-year old analysis to 
propose a MACT standard for an entirely new universe of storage vessel 
sources. Thus, according to the commenter, the EPA's failure to 
properly calculate the MACT floor in setting the MACT standard for 
storage vessels violates CAA section 112(d)(2) and (3).
    The commenter states that, because this method has been found to be 
unlawful and substantially more data are available at this time, the 
EPA must now recalculate the MACT floor and MACT limits for tanks with 
the PFE. Cement Kiln Recycling Coalition, et. al. v. U.S. EPA, 255 F.3d 
855, 863-64 (D.C. Cir. 2001). The commenter asserts that, in addition 
and partly as a consequence of its unlawful reliance on the prior 
standards, the EPA also has failed to fulfill the beyond-the-floor 
requirement of CAA section 112(d)(2). The commenter opines that, absent 
an up-to-date analysis based on current emission controls, an 
appropriate beyond-the-floor determination cannot be made.
    Two commenters do not believe that the dataset used is 
representative of currently operating small glycol dehydrators. One 
commenter believes that the EPA has not satisfied section 112(d)(2) and 
(3) of the CAA and that the EPA needs to calculate the MACT

[[Page 49529]]

limit based on the best-performing sources that currently exist.
    One commenter recommends that the EPA base its MACT floor analyses 
on emissions data from a representative population of small dehydrators 
that characterize the population of affected sources within the 
category or subcategory. The commenter reports that more current data 
sources may be available, such as dehydrator emissions data reported to 
state agencies in annual emission reports or in permit applications.
    One commenter opines that the EPA's proposal misses the opportunity 
and fails to fulfill the agency's responsibility to properly calculate 
the MACT for all sources in this sector based on current, reliable and 
representative emission test data. The commenter believes that, by 
relying on an incomplete and outdated dataset to set MACT floors and 
limits, the EPA has ignored data demonstrating trends in practices, 
processes and technologies and the resulting improved performance that 
CAA section 112(d) mandates. The commenter asserts that the EPA ignores 
the potential HAP emissions that the control devices themselves emit by 
failing to collect such emissions data from facilities that have 
installed control devices. The commenter argues that the EPA must 
collect the appropriate emission test data needed in order to 
recalculate and set a proper MACT for glycol dehydrators, storage 
vessels and equipment leaks.
    One commenter states that section 112 of the CAA requires the EPA 
to set a NESHAP for each category or subcategory of ``major sources'' 
of HAP emissions. 42 U.S.C. 7412(d)(1). The commenter asserts that the 
EPA must set CAA section 112(d) emission standards based on ``maximum 
achievable control technology'' or ``MACT.'' The commenter states that 
the EPA largely bases its MACT proposal for small glycol dehydrators on 
emissions data collected from the industry during the development of 
the original MACT standards. 76 FR 52768. The commenter contends that 
the data were collected prior to 1997 and did not adequately represent 
the emissions profile at that time, and do not reflect the significant 
changes in the industry and other technological developments that have 
occurred during the past 13 years. According to the commenter, the EPA 
has not provided a reasoned explanation of how those data could be 
representative of currently operating glycol dehydrators and associated 
emission reductions, and how proposals based on those data can 
currently meet the MACT requirements for new and existing sources. The 
commenter states that the dehydrator technology performance in 1997 was 
not accurately reflected in the legacy EPA dataset and has advanced 
significantly in the past 13 years. Consequently, according to the 
commenter, the EPA has not provided a reasoned explanation of how those 
data could be representative of currently operating glycol dehydrators 
and associated emission reductions, and how proposals based on those 
data can currently meet the MACT requirements for new and existing 
sources. The commenter believes this is critical because the 2005 NEI 
data reveal that improvements in the environmental performance of the 
category have progressed such that there are far more units in service 
with lower emissions than reflected in the 1997 data.
    One commenter states that the EPA did not collect recent data 
regarding emissions of HAP, including BTEX, from small glycol 
dehydrators in either source sector in support of this rulemaking. 
Instead, according to the commenter, the EPA appears to have relied on 
data collected in the prior MACT rulemaking, going back to 1998 or 
prior. The commenter believes that the EPA's analysis is flawed and 
questionable because it simply relies on the best-performing sources 
that existed a decade ago and fails to identify the best controlled 
sources today. The commenter contends that it is unlikely that these 
MACT standards reflect either the current best controlled similar 
source emissions or the average of the top 12 percent of the currently 
best controlled sources. The commenter states that, while the EPA 
appropriately proposes to set a MACT limit for these sources for the 
first time, the EPA's use of out-dated data fails to demonstrate that 
its proposed limit is stringent enough in light of significant 
developments in emission control technologies and practices that have 
occurred since 1998.
    Response: One commenter argues that EPA has not satisfied sections 
112(d)(2) and (3) of the CAA, because the MACT standards set in the 
1999 rule have not been re-calculated using current data. To the extent 
the commenter is arguing that CAA section 112(d)(6) requires that the 
EPA recalculate the MACT standards set in 1999, based on current 
emissions test data, the commenter is incorrect. In NRDC v. EPA, 529 
F.3d 1077, 1084 (D.C. Cir. 2008), the District of Columbia Circuit held 
that it ``[did] not think the words `review, and revise as necessary' 
can be construed reasonably as imposing any such obligation'' to re-
calculate the MACT floors. NRDC v. EPA, 529 F.3d 1077, 1084 (D.C. Cir. 
2008).
    Moreover, in this action, we did not re-open the MACT standards in 
40 CFR part 63, subpart HH for large glycol dehydrators, storage 
vessels with the PFE and equipment leaks for or in 40 CFR part 63, 
subpart HHH for large glycol dehydrators. As such, the commenter's 
request that we re-calculate those standards based on current emissions 
data is outside the scope of this rulemaking. We did, however, conduct 
a CAA section 112(d)(6) technology review for subpart HH and determined 
that there have been no developments in practices, processes or control 
technologies for large glycol dehydrators, storage vessels with the PFE 
and equipment leaks and that there have been developments for equipment 
leaks. See Technology Review for the Final Amendments to Standards for 
the Oil and Natural Gas Production and Natural Gas Transmission and 
Storage Source Categories and responses on section 112(d)(6) comments 
below. We also conducted a CAA section 112(d)(6) technology review for 
subpart HHH and determined that there have been no developments in 
practices, processes or control technologies for large glycol 
dehydrators. Id.
    The remaining comments focus on the data the agency used to set the 
proposed MACT standards for small glycol dehydrators, which were left 
unregulated in the 1999 rule. The commenters claim that the data the 
EPA used to set the BTEX MACT standards for the small glycol 
dehydrators subcategory are outdated and that the EPA must collect new 
data. However, CAA section 112(d)(3) specifically provides that the 
Agency is to determine the average emission limit achieved by the best 
performing 12 percent of existing sources ``(for which the 
Administrator has emissions information).'' Thus, the EPA is not 
required to collect information if it determines that the information 
it has is sufficient for it to calculate the MACT standards consistent 
with the requirements of CAA section 112. Although the available 
emissions information is over a decade old, the available controls for 
reducing BTEX emissions from small glycol dehydrators and their control 
efficiencies have remained the same during this period, and the 
commenters have not provided any data to the contrary.\27\ We,

[[Page 49530]]

therefore, believe the data we have are still representative of the 
performance of the small dehydrators.
---------------------------------------------------------------------------

    \27\ Memorandum from Brown, Heather, EC/R Inc., to Moore, Bruce, 
U.S. EPA, titled Technology Review for the Final Amendments to 
Standards for the Oil and Natural Gas Production and Natural Gas 
Transmission and Storage Source Categories. Dated April 17, 2012.
---------------------------------------------------------------------------

    Moreover, we believe that the collection and analysis of additional 
data would take time and further delay control of these sources, which 
we do not think is warranted where, as here, we believe the data on 
BTEX emissions for the subcategory of small glycol dehydrators are 
still representative of these sources' performance today and the 
commenter did not provide any data that indicates otherwise.
    Finally, for small glycol dehydrators, we considered using more 
current available data, like the 2005 NEI, however, the NEI dataset 
lacks specific information that we believe is relevant to identifying 
the best performing units. Specifically, the NEI data lacks information 
on inlet HAP content and gas throughput, both of which affect a glycol 
dehydrator's HAP emissions. Inlet HAP content varies from well site to 
well site. A well-controlled glycol dehydrator at a well site with high 
inlet HAP content may have higher HAP emissions than a totally 
uncontrolled glycol dehydrator at a well site with a low inlet HAP 
content. Natural gas throughput also affects a glycol dehydrator's 
overall emissions (i.e., low throughput units will tend to have lower 
overall emissions, and vice versa). For the reasons stated above, in 
addition to emissions, we need to consider the inlet HAP content and 
gas throughput of the small glycol dehydrators in order to properly 
identify the best performing sources and establish the MACT standard 
for this subcategory. However, information on natural gas throughput 
and inlet HAP content is not included in the NEI or any other readily 
available data source. Therefore, we used the 1997 data which included 
such information for the small dehydrators.
    Comment: One commenter supports the EPA's regulation of previously 
unregulated sources in the oil and natural gas sector and the commenter 
asserts that CAA sections 112(c) and 112(k) (Urban Air Toxics Strategy) 
support their position regarding the regulation of previously 
unregulated sources. The commenter asserts that historical regulation 
of emission sources within the sector leaves a large number of 
dehydrators, storage vessels and equipment at gas processing plants 
unregulated. Additionally, the commenter states that historical 
regulation has also not limited emissions from a number of other 
emission sources (i.e., wells, pneumatic devices, compressor seals, 
valves, or flanges or other production equipment located at oil and gas 
production facilities or natural gas storage transmission facilities).
    One commenter supports the EPA's recognition of the need to control 
emissions from previously uncontrolled emission points and commends the 
EPA on addressing small glycol dehydration units and storage vessels 
without the PFE. The commenters request that the EPA address all of the 
uncontrolled HAP emission points of which it is aware.
    Response: This rule establishes MACT standards for major sources of 
small glycol dehydrators that were left unregulated in the 1999 MACT 
rule. As explained further below, in several recent rulemakings, we 
have chosen to fix certain underlying defects in existing MACT 
standards under CAA sections 112(d)(2) and (3), which are the 
provisions that directly govern the initial promulgation of MACT 
standards (see National Emission Standards for Hazardous Air Pollutants 
From Petroleum Refineries, October 28, 2009, 74 FR 55670; and National 
Emission Standards for Hazardous Air Pollutants: Group I Polymers and 
Resins; Marine Tank Vessel Loading Operations; Pharmaceuticals 
Production; and the Printing and Publishing Industry, April 21, 2011, 
76 FR 22566). We believe that this approach is reasonable because using 
those provisions ensures that the process and considerations are those 
associated with initially establishing a MACT standard, and it is 
reasonable to make corrections following the process that would have 
been followed if we had not made an error at the time of the original 
promulgation. We appreciate the commenter's support for regulating 
small glycol dehydrators.
    Although the agency had proposed MACT standards under CAA sections 
112(d)(2) and (3) for the subcategory of storage vessels without the 
PFE, we are not finalizing those standards here. Based on our review of 
the comments, we believe that we need additional data in order to set 
an emission standard for these vessels. We intend to collect the 
appropriate data and propose a MACT emission standard under CAA 
sections 112(d)(2) and (3) of the CAA.
    The commenter identifies certain emission sources, other than small 
glycol dehydrators and storage vessels without the PFE (e.g., wells), 
that it alleges are uncontrolled. CAA section 112(n)(4)(A) prohibits 
aggregation of emissions from any oil and gas exploration or production 
wells (with their associated equipment) in determining major source 
status or for any purpose under CAA section 112. In light of this 
prohibition on aggregation, and the fact that the sources identified by 
the commenter likely would not, if viewed alone, qualify as a major 
source, it is not clear whether emissions from the sources identified 
by the commenter can be addressed by a major source NESHAP.\28\
---------------------------------------------------------------------------

    \28\ Even if the commenter were to identify an unregulated 
emission point under the NESHAP, it can always petition the agency 
to revise the 1999 MACT standards.
---------------------------------------------------------------------------

    The commenter also references CAA section 112(k) (and the Urban Air 
Toxic Strategy). CAA section 112(k) is designed to address area source 
emissions in urban areas. This rule involves a review of 40 CFR part 
63, subparts HH and HHH, both of which address major sources, not area 
sources. Further, oil and gas production facilities are typically not 
sited in urban areas.
    To the extent that the commenter is requesting EPA to list area 
source oil and gas production wells, such a request is outside the 
scope of this action. See CAA section 112(n)(4)(B) (specifying certain 
requirements for listing ``oil and gas production wells (with its 
associated equipment)'' as an area source category).

B. Major Comments Concerning the Risk Review

    Comment: One commenter states that the EPA's analysis for 40 CFR 
part 63, subpart HH revealed two facilities (Hawkins Gas Plant, 
Hawkins, Texas, and Kathleen Tharp 2, Huffman, Texas) with a cancer MIR 
greater than 100-in-1 million based on MACT allowable emissions. The 
commenter notes that since the EPA determined that these facilities had 
a cancer MIR greater than 100-in-1 million based on MACT allowable 
emissions, the EPA determined that the risks are unacceptable for the 
Oil and Natural Gas Production MACT source category and additional 
regulation was needed. However, the commenter believes these results 
are entirely incorrect due to fundamental errors in the EPA's 
calculations of MACT allowable risk for these two facilities. In 
addition, even if the analysis had been correct, the commenter states 
there are significant issues associated with the data for both of these 
facilities, which the commenter discusses in detail, that the commenter 
believes are sufficient to invalidate the results and the EPA's 
conclusion that risks from the Oil and Natural Gas Production source 
category are unacceptable.
    Response: We have reviewed our risk results for the Oil and Natural 
Gas Production source category and agree

[[Page 49531]]

with the commenter that a number of errors were made in our analysis, 
including those noted by the commenter. As explained in VII.A.2 of this 
preamble, we have revised the risk assessment for this major source 
category to correct certain mistakes made in the analysis supporting 
the proposed rule.
    Based on our revised risk assessment, in which we evaluated the 
risks that remain after promulgation of the original MACT standards, as 
well as the MACT standards for small glycol dehydrators established in 
this final rule, we have determined the risks for the Oil and Natural 
Gas Production major source category are acceptable and that the MACT 
standards (including those promulgated here for small glycol 
dehydrators) provide an ample margin of safety. Further, we are 
retaining the 0.9 Mg/yr benzene compliance alternative, which we had 
proposed to remove based on our incorrect conclusion that this 
alternative was driving the risk for this major source category.
    Comment: One commenter states that the EPA bases the decision to 
eliminate the 0.9 Mg/yr benzene emission limitation for 40 CFR part 63, 
subpart HHH on two basic factors: (1) It would reduce the cancer MIR 
from 90-in-1 million to 20-in-1 million, and (2) the cost effectiveness 
to comply with this option is reasonable. The commenter states that 
both of these conclusions are erroneous.
    First, the commenter states that removal of 0.9 Mg/yr benzene 
alternative does not reduce risk. The commenter states that the EPA's 
own technical analysis indicates that removal of the 0.9 Mg/yr benzene 
alternative would have no effect on the MIR.
    Secondly, the commenter states that the EPA's cost analysis is 
severely flawed. The commenter also states that the EPA noted at 
proposal, that the cost-effectiveness associated with removing the 0.9 
Mg/yr benzene compliance alternative for natural gas transmission and 
storage facilities was reasonable. However, the commenter explained 
that the cost estimates used by the EPA in the ample margin of safety 
determination are inadequate. According to the commenter, the EPA did 
not conduct any analysis using actual data. Rather, the commenter notes 
that the EPA used costs estimated for small dehydrators and made 
general assumptions to estimate an upper-end cost effectiveness for 
removing the 0.9 Mg/yr benzene alternative limit for large dehydrators 
at natural gas transmission and storage facilities. The commenter 
believes that, in general, the emission reductions for dehydrators 
forced to switch from the 0.9 Mg/yr benzene alternative to 95-percent 
control would be considerably less than those achieved by small 
dehydrators. The commenter further notes that the cost-effectiveness 
calculated for small dehydrators is based on a 95-percent reduction 
from an uncontrolled baseline level. According to the commenter, if a 
large dehydrator has installed controls to meet the 0.9 Mg/yr 
alternative benzene limitation, the cost effectiveness must be based on 
the incremental reduction between the existing controls and 95 percent. 
The commenter states that the EPA has provided no evidence that these 
incremental reductions would be greater than or equal to the 95-percent 
reductions that would be achieved for smaller dehydrators. In 
conclusion, the commenter states that the rationale used by the EPA in 
the preamble to support the removal of the 0.9 Mg/yr compliance 
alternative for dehydrators at natural gas transmission and storage 
facilities under section 112(f)(2) of the CAA is not supported by any 
of the background technical documentation and analyses. The commenter 
believes that the EPA has no basis under any other CAA authority for 
this action.
    Response: In response to comments, we re-examined our risk 
assessment for the Natural Gas Transmission and Storage source category 
and discovered a number of errors, which we have discussed in more 
detail in section VII.B.2 of this preamble. As explained in that 
section, we have revised the risk assessment for this major source 
category to correct the mistakes. Based on our revised risk assessment, 
in which we evaluated the risks that remain after promulgation of the 
original MACT standards, as well as the MACT standards for small glycol 
dehydrators in this final rule, we have determined that the risks for 
the Oil and Gas Transmission and Storage major source category are 
acceptable and that the MACT standards (including those promulgated 
here) provide an ample margin of safety. Further, we are retaining the 
0.9 Mg/yr benzene compliance alternative, which we had proposed to 
remove based on our incorrect conclusion that it was driving the risk 
for this major source category. We agree with the commenter that 
removal of the 0.9 Mg/yr benzene compliance alternative does not reduce 
risks for this major source category. Because we are retaining this 
compliance alternative, we need not address the comment on the cost 
effectiveness of removing this alternative.

C. Major Comments Concerning the Technology Review

    Comment: One commenter states that, in conducting an 8-year review, 
the EPA must ``look back'' at the earlier standard and ascertain 
whether: (1) The standard was adopted using procedures that comply with 
the law as it has come to be interpreted by the courts; (2) the EPA had 
sufficiently accurate and comprehensive data at the time of the initial 
standard setting respecting the emissions profile of the category and 
properly identified the best performing unit(s); and (3) the EPA had 
properly used the available data.
    The commenter states the EPA then must ``look around'' using 
currently available data and determine whether: (1) The emissions 
profile of the industry has changed in a way that would substantially 
affect the MACT floor calculations (the commenter adds that this 
includes consideration of any increase in the number of good performing 
units available for use in the existing source MACT floor calculation 
and in the performance of the best performing unit); (2) data gaps or 
uncertainties that affected the earlier decision have been resolved in 
the interim or can be resolved using new information available to the 
agency; (3) costs or other factors have changed in a way that would 
substantially affect the ``beyond-the-floor'' determination; (4) the 
use of improved practices, processes or technologies (including 
improvements in the performance of existing technologies) has become 
more prevalent than at the time of the initial standard setting; or (5) 
whether newer regulatory requirements, work practices or emission 
limitations (including state and local jurisdiction air pollution 
standards and federal enforcement actions), which are more stringent 
than the existing CAA section 112(d) standard, have shown the 
achievement or achievability of greater emission reductions than the 
existing standard requires.
    Response: As explained in the preamble to the proposed rule, our 
technology review focused on the identification and evaluation of 
``developments in practices, processes, and control technologies'' 
since the promulgation of the MACT standards for the two oil and gas 
source categories at issue here. We first reviewed the available 
information. In this regard, we reviewed a variety of sources of data, 
including data obtained in subsequent air toxics rules to see if any 
practices, processes and control technologies

[[Page 49532]]

considered in these actions could be applied to emission sources in the 
source categories at issue here. We also consulted the EPA's Reasonably 
Available Control Technology (RACT)/Best Available Control Technology 
(BACT)/Lowest Achievable Emission Rate (LAER) Clearinghouse (RBLC) and 
the Natural Gas STAR program. At proposal, we explained that we 
consider any of the following to be a ``development'':

--Any add-on control technology or other equipment that was not 
identified and considered during MACT development;
--Any improvements in add-on control technology or other equipment 
(that was identified and considered during MACT development) that could 
result in significant additional emission reduction;
--Any work practice or operational procedure that was not identified 
and considered during MACT development; and
--Any process change or pollution prevention alternative that could be 
broadly applied that was not identified and considered during MACT 
development.

    The commenter views CAA section 112(d)(6) differently. It appears 
to argue that CAA section 112(d)(6) requires that the EPA recalculate 
the MACT based on current data and technology. The same argument was 
posed to the District of Columbia Circuit, and the Court ``[did] not 
think that the words `review, and revise as necessary' can be construed 
reasonably as imposing any such obligation.'' NRDC v. EPA, 529 F.3d 
1077, 1084 (D.C. Cir. 2008). Thus, contrary to the commenter's 
assertion, the EPA is not required pursuant to CAA section 112(d)(6) to 
re-calculate the floors it set in 1999.
    To the extent the commenter is arguing that CAA section 112(d)(6) 
mandates that the EPA correct any deficiency in an underlying MACT 
standard when it conducts the ``technology review'' under that section, 
we disagree. We believe that CAA section 112 does not expressly address 
this issue, and the EPA has discretion in determining how to address a 
purported flaw in a promulgated standard. CAA section 112(d)(6) 
provides that the agency must review and revise ``as necessary.'' The 
``as necessary'' language must be read in the context of the provision, 
which focuses on the review of developments that have occurred since 
the time of the original promulgation of the MACT standard and thus 
should not be read as a mandate to correct flaws that existed at the 
time of the original promulgation.
    In several recent rulemakings, we have chosen to fix underlying 
defects in existing MACT standards under CAA sections 112(d)(2) and 
(3), the provisions that directly govern the initial promulgation of 
MACT standards (see National Emission Standards for Hazardous Air 
Pollutants From Petroleum Refineries, October 28, 2009, 74 FR 55670; 
and National Emission Standards for Hazardous Air Pollutants: Group I 
Polymers and Resins; Marine Tank Vessel Loading Operations; 
Pharmaceuticals Production; and the Printing and Publishing Industry, 
April 21, 2011, 76 FR 22566). We believe that our approach is 
reasonable because using those provisions ensures that the process and 
considerations are those associated with initially establishing a MACT 
standard, and it is reasonable to make corrections following the 
process that would have been followed if we had not made an error at 
the time of the original promulgation. As explained elsewhere, we are 
not finalizing MACT standards for the subcategory of storage vessels 
without the PFE, which were unregulated in the 1999 rule, because after 
evaluating the available data and comments received, we believe that we 
need additional data in order to set an emission standard for these 
vessels. We are, however, finalizing MACT standards under CAA sections 
112(d)(2) and (3) for the subcategory of small glycol dehydration 
units.
    With regard to our CAA section 112(d)(6) review, we found no 
significant developments in practices, processes and control 
technologies for reducing emissions from large glycol dehydrators and 
storage vessels with PFE.\29\ Accordingly, we are not revising these 
standards under CAA section 112(d)(6).
---------------------------------------------------------------------------

    \29\ See footnote 25.
---------------------------------------------------------------------------

    The EPA also conducted a technology review evaluating various 
options for controlling HAP emissions from equipment leaks. As 
described in the proposed rule (76 FR 52784), we evaluated advancements 
in controlling this emissions source since the original standards were 
promulgated, including the emission reduction potential and associated 
cost-effectiveness of these advancements. As a result of our review, we 
revised the leak definition for valves at natural gas processing plants 
to 500 ppm, thus, requiring the application of the LDAR requirement at 
this lower detection level. As discussed above, the commenter appears 
to be arguing that the EPA must redo the MACT floor and beyond-the-
floor analysis under CAA sections 112(d)(2) and (3) within its CAA 
section 112(d)(6) technology review, which we disagree.
    Comment: One commenter states that the EPA's technology review for 
storage vessel control technologies is limited and makes incorrect 
assumptions. The commenter contends that without further support, the 
public cannot understand and the EPA cannot justify its proposed 
decision; therefore, the EPA's proposal is arbitrary and capricious. 
The commenter adds that the EPA must conduct an updated beyond-the-
floor analysis for storage vessels, by determining the ``maximum degree 
of reduction in emissions'' that is achievable, as required under CAA 
section 112(d)(2). The commenter states that the proposed rule fails to 
provide any discussion of a beyond-the-floor determination for storage 
vessels.
    One commenter states that the EPA must examine advances in vapor 
recovery unit technology and reconsider floating roof technology for 
tanks containing liquids that do not have the PFE. The commenter 
contends that the EPA improperly rejected technology advances and 
developments in pollution prevention systems found in its own RBLC 
database and employed by its own Natural Gas STAR partners. 
Specifically, according to the commenter, the EPA failed to evaluate 
the performance achieved by systems that use thermal or catalytic 
oxidizers, either alone or in combination with condensers. According to 
the commenter, the EPA's RBLC review identified a BACT determination 
for dehydrator efficiency of 98 percent. The commenter also urges the 
EPA to evaluate the use of combustion devices and vapor recovery units 
that capture vent steam from the tank and turn it into a saleable 
product by recompressing the hydrocarbon vapors. The commenter contends 
that the EPA rejects technology advances by asserting that those 
technologies were considered in the 1999 rulemaking, but fails to 
provide support for its decision in either the record of the 1999 
rulemaking or the current record. The commenter contends that the EPA 
must provide a basis for its decisions and conclusions.
    Response: For the reasons discussed in the prior response, the EPA 
disagrees with the commenter's assertion that it must re-do the MACT 
floor calculations, including the beyond-the-floor determination, for 
the standards that the agency set in 1999. As to the technologies 
identified by the commenter, they were in existence and considered by 
the EPA at the time the EPA promulgated the original MACT

[[Page 49533]]

standards for storage vessels.30 31 In addition, we are not 
finalizing control requirements for storage vessels without the PFE, as 
described in section VII.A of this preamble. The record does not 
support the assertion that the technologies identified by the commenter 
have advanced in terms of HAP emission reduction or have become 
significantly more cost effective. As explained in the preamble to the 
proposed rule (76 FR 52785), we examined technologies that were similar 
to the cover and route emissions to a control device that the MACT 
floor requires and, thus, would not result in reductions beyond the 
existing MACT requirements. Further, evaluation of technologies in the 
RBLC did not produce any applicable practices, processes or control 
technologies that were not considered during the original MACT for 
storage vessels with flash emissions.\32\
---------------------------------------------------------------------------

    \30\ See footnote 25.
    \31\ See EPA Legacy Docket A-94-04 MACT floor memos II-A-006 and 
-007.
    \32\ See footnote 25.
---------------------------------------------------------------------------

D. Major Comments Concerning Notification, Recordkeeping and Reporting 
Requirements

1. Annual Reports
    Comment: One commenter requested that the EPA add a self-
certification requirement to the annual report similar to that used in 
the title V program. The commenter recommended that the final rule 
require the annual report to include a statement signed by a senior 
official of the facility attesting to the truth, accuracy and 
completeness of the report.
    The commenter also requested that the EPA require that the annual 
reports be submitted electronically to facilitate making the reports 
publicly available. The commenter suggested using social media outlets, 
smart phone applications and other electronic means to make the annual 
reports readily available.
    Response: The EPA agrees that self-certification is an important 
mechanism for assuring the public that the information submitted by 
each facility is accurate. In addition, the title V program has 
successfully employed self-certification for since its inception. 
Therefore, we are requiring self-certification, based on requirements 
in the title V program, in the final rule.
    While we agree that having annual reports readily available to the 
public is a desirable goal, we did not identify any reporting programs 
or electronic databases that may be used for this purpose without 
significant modification. Therefore, we are not requiring annual 
reports to be submitted electronically, but we will continue to 
evaluate this option in the future.
2. Electronic Reporting of Emissions Data
    Several commenters raised similar issues regarding reporting of 
emissions data under the NESHAP as under the NSPS, described supra, and 
our responses there apply equally here. Please see comments and 
responses in section IX.F.3 of this preamble.

XI. What are the cost, environmental and economic impacts of the final 
NESHAP and NSPS amendments?

A. What are the air impacts?

    For the oil and natural gas sector NESHAP and NSPS, we estimated 
the emission reductions that will occur due to the implementation of 
the final emission limits. The EPA estimated emission reductions based 
on the control technologies selected by the engineering analysis. These 
emission reductions associated with the final amendments to 40 CFR part 
63, subpart HH and 40 CFR part 63, subpart HHH are based on the 
estimated population in 2008. Under the finalized limits for glycol 
dehydration units, we have estimated that the HAP emissions reductions 
will be 670 tons for existing units subject to the final emissions 
limits.
    For the NSPS, we estimated the emission reductions that will occur 
due to the implementation of the final emission limits. The EPA 
estimated emission reductions based on the control technologies 
selected by the engineering analysis. These emission reductions are 
based on the estimated population in 2015.
    The primary baseline used for the impacts analysis of our NSPS for 
completions of hydraulically fractured natural gas wells takes into 
account REC conducted pursuant to state regulations covering these 
operations and estimates of REC performed voluntarily. To account for 
REC performed in regulated states, the EPA subsumed emissions 
reductions and compliance costs in states where these completion-
related emissions are already controlled into the baseline. 
Additionally, based on public comments and reports to the EPA's Natural 
Gas STAR program, the EPA recognizes that some producers conduct well 
completions using REC techniques voluntarily for economic and/or 
environmental objectives as a normal part of business. To account for 
emissions reductions and costs arising from voluntary implementation of 
pollution controls, the EPA used information on total emission 
reductions reported to the EPA by partners of the EPA Natural Gas STAR. 
This estimate of this voluntary REC activity in the absence of 
regulation is also included in the baseline.\33\ More detailed 
discussion on the derivation of the baseline is presented in a 
technical memorandum in the docket, as well as in the Regulatory Impact 
Analysis (RIA).
---------------------------------------------------------------------------

    \33\ Voluntary short-term actions (such as REC) are challenging 
to capture accurately in a prospective analysis, as such, reductions 
are not guaranteed to continue. However, Natural Gas STAR represents 
a nearly 20-year voluntary initiative with participation from 124 
natural gas companies operating in the United States, including 28 
producers, over a wide historical range of natural gas prices. This 
unique program and dataset, the significant impact of voluntary REC 
on the projected cost and emissions reductions (due to significant 
REC activity), and the fact that REC can actually increase natural 
gas recovered from natural gas wells (offering a clear incentive to 
continue the practice), led the agency to conclude that it was 
appropriate to estimate these particular voluntary actions in the 
baseline for this rule.
---------------------------------------------------------------------------

    Additionally, in the RIA, we provide summary-level estimates of 
emissions reductions and engineering compliance costs for a case where 
no voluntary REC are assumed to occur. This alternative case is 
presented in order to show impacts if conditions were such that REC 
were no longer performed on a voluntary basis, but, rather, were 
compelled by the regulation, and serves, in part, to capture the 
inherent uncertainty in projecting voluntary activity into the future. 
As such, this alternative case establishes the full universe of 
emissions reductions that are guaranteed by this NSPS (those that are 
required to occur under the rule, including those that would likely 
occur voluntarily). While the primary baseline may better represent 
actual costs (and emissions reductions) beyond those already expected 
under business as usual, the alternative case better captures the full 
amount of emissions reductions where the NSPS acts as a backstop to 
ensure that emission reduction practices occur (practices covered by 
this rule).
    Under the final NSPS, we have estimated that the emissions 
reductions to be about 190,000 tons VOC affected facilities subject to 
the NSPS. The NSPS is also expected to concurrently reduce 1.0 million 
tons methane and 11,000 tons HAP. We estimate that direct reductions in 
HAP, methane and VOC for the final rules combined total about 12,000 
tons, 1.0 million tons and 190,000 tons, respectively. If voluntary 
action is not deducted from the NSPS baseline, the emissions reductions 
achieved by the final NSPS in HAP, methane and VOC are estimated at

[[Page 49534]]

about 19,000 tons, 1.7 million tons and 290,000 tons, respectively.
    The EPA received several comments regarding the emission factor 
selected to calculate whole gas emissions (and the associated VOC 
emissions) from hydraulically fractured well completions. Comments 
focused on the data behind the emission factor, what the emission 
factor is intended to represent and the procedures used to develop the 
emission factor from the selected data sets. We reviewed all 
information received and have decided to retain the data set and the 
analysis conducted to develop the emission factor of 9,000 thousand 
cubic feet (Mcf) per completion. More detailed discussion is presented 
in a technical memorandum on this subject in the docket.

B. What are the energy impacts?

    Energy impacts in this section are those energy requirements 
associated with the operation of emission control devices. Potential 
impacts on the national energy economy from the rule are discussed in 
the economic impacts section. There would be little national energy 
demand increase from the operation of any of the environmental controls 
analyzed under the final NESHAP amendments and final NSPS.
    The final NESHAP amendments and final NSPS encourage the use of 
emission controls that recover hydrocarbon products, such as methane 
and condensate that can be used on-site as fuel or reprocessed within 
the production process for sale. We estimated that the final standards 
will result in net annual costs savings of about $11 million (in 2008 
dollars) due to the recovery of salable natural gas and condensate. 
Thus, the final standards have a positive impact associated with the 
recovery of non-renewable energy resources.

C. What are the cost impacts?

    The estimated total capital cost to comply with the final 
amendments to 40 CFR part 63, subpart HH for major sources in the Oil 
and Natural Gas Production source category is approximately $2.6 
million. The total capital cost for the final amendments to 40 CFR part 
63, subpart HHH for major sources in the Natural Gas Transmission and 
Storage source category is estimated to be approximately $140,000. All 
costs are in 2008 dollars.
    The total estimated net annual cost to industry to comply with the 
final amendments to 40 CFR part 63, subpart HH for major sources in the 
Oil and Natural Gas Production source category is approximately $3.3 
million. The total net annual cost for final amendments to 40 CFR part 
63, subpart HHH for major sources in the Natural Gas Transmission and 
Storage source category is estimated to be approximately $180,000. 
These estimated annual costs include: (1) The cost of capital, (2) 
operating and maintenance costs, (3) the cost of monitoring, 
inspection, recordkeeping and reporting (MIRR) and (4) any associated 
product recovery credits. All costs are in 2008 dollars.
    The estimated total capital cost to comply with the final NSPS is 
approximately $25 million in 2008 dollars. The total estimated net 
annual cost to industry to comply with the final NSPS is estimated to 
be approximately $170 million in 2008 dollars. This annual cost 
estimate includes: (1) The cost of capital, (2) operating and 
maintenance costs and (3) the cost of MIRR. This estimated annual cost 
does not take into account any producer revenues associated with the 
recovery of salable natural gas and hydrocarbon condensates.
    When revenues from additional product recovery are considered, the 
final NSPS is estimated to result in a net annual engineering cost 
savings overall. When including the additional natural gas recovery in 
the engineering cost analysis, we assume that producers are paid $4/Mcf 
for the recovered gas at the wellhead. The engineering analysis cost 
analysis assumes the value of recovered condensate is $70 per barrel. 
Based on the engineering analysis, about 43 million Mcf (43 billion 
cubic feet) of natural gas and 160,000 barrels of condensate are 
estimated to be recovered by control requirements in 2015. Using the 
price assumptions, the estimated revenues from natural gas and 
condensate recovery are approximately $180 million in 2008 dollars.
    Using the engineering cost estimates, estimated natural gas product 
recovery and natural gas product price assumptions, the net annual 
engineering cost savings is estimated for the final NSPS to be about 
$15 million. Totals may not sum due to independent rounding.
    If voluntary action is not deducted from the baseline, capital 
costs for the NSPS are estimated at $25 million and annualized costs 
without revenues from product recovery for the NSPS are estimated at 
$330 million. In this scenario, given the assumptions about product 
prices, estimated revenues from product recovery are $350 million, 
yielding an estimated cost of savings of about $22 million.
    As the price assumption is very influential on estimated annualized 
engineering costs, we performed a simple sensitivity analysis of the 
influence of the assumed wellhead price paid to natural gas producers 
on the overall engineering annualized costs estimate of the final NSPS. 
At $4.22/Mcf, the price forecast reported in the 2011 Annual Energy 
Outlook in 2008 dollars, the annualized cost savings for the final NSPS 
are estimated at about $24 million. As indicated by this difference, 
the EPA has chosen a relatively conservative assumption (leading to an 
estimate of few savings and higher net costs) for the engineering costs 
analysis. The natural gas price at which the final NSPS breaks-even 
from an estimated engineering costs perspective is around $3.66/Mcf. A 
$1/Mcf change in the wellhead natural gas price leads to a $43 million 
change in the annualized engineering costs of the final NSPS. 
Consequently, annualized engineering costs estimates would increase to 
about $29 million under a $3/Mcf price or decrease to about -$58 
million under a $5/Mcf price. For further details on this sensitivity 
analysis, please refer the RIA for this rulemaking located in the 
docket.

D. What are the economic impacts?

    The analysis of energy system impacts EPA performed using the 
United States Department of Energy's (DOE) National Energy Modeling 
System (NEMS) shows that domestic natural gas production is not likely 
to change in 2015 as a result of the final rules, the year used in the 
RIA to analyze impacts. Average natural gas prices are also not 
estimated to change in response to the final rules. Domestic crude oil 
production is not expected to change, while average crude oil prices 
are estimated to decrease slightly (about $0.01/barrel or about 0.01 
percent at the wellhead for onshore production in the lower 48 states). 
All prices are in 2008 dollars. The NEMS-based analysis estimates in 
the year of analysis, 2015, that net imports of natural gas and crude 
oil will not change.

E. What are the benefits of this final rule?

    The final Oil and Natural Gas NSPS and NESHAP amendments are 
expected to result in significant reductions in existing emissions and 
prevent new emissions from expansions of the industry. These final 
rules combined are anticipated to reduce 12,000 tons of HAP, 190,000 
tons of VOC (a precursor to both PM (2.5 microns and less) 
(PM2.5) and ozone formation) and 1.0 million tons of methane 
(a GHG and a precursor to global ozone formation). These pollutants are 
associated with

[[Page 49535]]

substantial health effects, welfare effects and climate effects.
    With the data available, we are not able to provide credible health 
benefit estimates for the reduction in exposure to HAP, ozone and 
PM2.5 for these rules, due to the differences in the 
locations of oil and natural gas emission points relative to existing 
information and the highly localized nature of air quality responses 
associated with HAP and VOC reductions. This is not to imply that there 
are no benefits of the rules; rather, it is a reflection of the 
difficulties in modeling the direct and indirect impacts of the 
reductions in emissions for this industrial sector with the data 
currently available.\34\ In addition to health improvements, there will 
be improvements in visibility effects, ecosystem effects and climate 
effects, as well as additional product recovery.
---------------------------------------------------------------------------

    \34\ Previous studies have estimated the monetized benefits-per-
ton of reducing VOC emissions associated with the effect that those 
emissions have on ambient PM2.5 levels and the health 
effects associated with PM2.5 exposure (Fann, Fulcher, 
and Hubbell, 2009). While these ranges of benefit-per-ton estimates 
provide useful context for the break-even analysis, the geographic 
distribution of VOC emissions from the oil and gas sector are not 
consistent with emissions modeled in Fann, Fulcher, and Hubbell 
(2009). In addition, the benefit-per-ton estimates for VOC emission 
reductions in that study are derived from total VOC emissions across 
all sectors. Coupled with the larger uncertainties about the 
relationship between VOC emissions and PM2.5 and the 
highly localized nature of air quality responses associated with HAP 
and VOC reductions, these factors lead us to conclude that the 
available VOC benefit-per-ton estimates are not appropriate to 
calculate monetized benefits of these rules, even as a bounding 
exercise.
---------------------------------------------------------------------------

    Although we do not have sufficient information or modeling 
available to provide quantitative estimates for this rulemaking, we 
include a qualitative assessment of the health effects associated with 
exposure to HAP, ozone and PM2.5 in the RIA for this rule. 
These qualitative effects are briefly summarized below, but for more 
detailed information, please refer to the RIA, which is available in 
the docket. One of the HAP of concern from the oil and natural gas 
sector is benzene, which is a known human carcinogen. VOC emissions are 
precursors to both PM2.5 and ozone formation. As documented 
in previous analyses (U.S. EPA, 2006 \35\ and U.S. EPA, 2010 \36\), 
exposure to PM2.5 and ozone is associated with significant 
public health effects. PM2.5 is associated with health 
effects, including premature mortality for adults and infants, 
cardiovascular morbidity such as heart attacks, and respiratory 
morbidity such as asthma attacks, acute and chronic bronchitis, 
hospital admissions and emergency room visits, work loss days, 
restricted activity days and respiratory symptoms, as well as 
visibility impairment.\37\ Ozone is associated with health effects, 
including hospital and emergency department visits, school loss days 
and premature mortality, as well as injury to vegetation and climate 
effects.\38\
---------------------------------------------------------------------------

    \35\ U.S. EPA. RIA. National Ambient Air Quality Standards for 
Particulate Matter, Chapter 5. Office of Air Quality Planning and 
Standards, Research Triangle Park, NC. October 2006. Available on 
the Internet at http://www.epa.gov/ttn/ecas/regdata/RIAs/
Chapter%205_Benefits.pdf.
    \36\ U.S. EPA. RIA. National Ambient Air Quality Standards for 
Ozone. Office of Air Quality Planning and Standards, Research 
Triangle Park, NC. January 2010. Available on the Internet at http://www.epa.gov/ttn/ecas/regdata/RIAs/s1-supplemental_analysis_full.pdf.
    \37\ U.S. EPA. Integrated Science Assessment for Particulate 
Matter (Final Report). EPA-600-R-08-139F. National Center for 
Environmental Assessment--RTP Division. December 2009. Available at 
http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=216546.
    \38\ U.S. EPA. Air Quality Criteria for Ozone and Related 
Photochemical Oxidants (Final). EPA/600/R-05/004aF-cF. Washington, 
DC: U.S. EPA. February 2006. Available on the Internet at http://cfpub.epa.gov/ncea/CFM/recordisplay.cfm?deid=149923.
---------------------------------------------------------------------------

    In addition to the improvements in air quality and resulting 
benefits to human health and non-climate welfare effects previously 
discussed, this rule is expected to result in significant climate co-
benefits due to anticipated methane reductions. Methane is a potent GHG 
that, once emitted into the atmosphere, absorbs terrestrial infrared 
radiation, which contributes to increased global warming and continuing 
climate change. Methane reacts in the atmosphere to form ozone and 
ozone also impacts global temperatures. According to the 
Intergovernmental Panel on Climate Change (IPCC) 4th Assessment Report 
(2007), methane is the second leading long-lived climate forcer after 
CO2 globally. Total methane emissions from the oil and gas 
industry represent about 40 percent of the total methane emissions from 
all sources and account for about 5 percent of all CO2e 
emissions in the United States, with natural gas systems being the 
single largest contributor to United States anthropogenic methane 
emissions.\39\ Methane, in addition to other GHG emissions, contributes 
to warming of the atmosphere, which, over time, leads to increased air 
and ocean temperatures, changes in precipitation patterns, melting and 
thawing of global glaciers and ice, increasingly severe weather events, 
such as hurricanes of greater intensity and sea level rise, among other 
impacts.
---------------------------------------------------------------------------

    \39\ U.S. EPA (2011), 2011 U.S. Greenhouse Gas Inventory Report 
Executive Summary available on the internet at http://epa.gov/climatechange/emissions/downloads11/US-GHG-Inventory-2011-Executive-Summary.pdf, accessed 02/13/12.
---------------------------------------------------------------------------

    This rulemaking requires emission control technologies and 
regulatory alternatives that will significantly decrease HAP and VOC 
emissions from the oil and natural gas sector in the United States. As 
a co-benefit, the emission control measures the industry will use to 
reduce HAP and VOC emissions will also decrease methane emissions. The 
NESHAP Amendments and the NSPS combined are expected to reduce methane 
emissions annually by about 1.0 million short tons or about 19 million 
metric tons CO2e. After considering the secondary impacts of 
this rule as previously discussed, such as increased CO2 
emissions from well completion combustion and decreased CO2e 
emissions because of fuel-switching by consumers, the methane 
reductions become about 18 million metric tons CO2e. The 
methane reductions represent about 7 percent of the baseline methane 
emissions for this sector reported in the EPA's U.S. Greenhouse Gas 
Inventory Report for 2009 (251.55 million metric tons CO2e 
when petroleum refineries and petroleum transportation are excluded 
because these sources are not examined in this proposal). However, it 
is important to note that the emission reductions are based upon 
predicted activities in 2015; the EPA did not forecast sector-level 
emissions in 2015 for this rulemaking. These emission reductions equate 
to the climate benefits of taking approximately 4 million typical 
passenger cars off the road or eliminating electricity use from about 2 
million typical homes each year.\40\
---------------------------------------------------------------------------

    \40\ U.S. EPA. Greenhouse Gas Equivalency Calculator available 
at: http://www.epa.gov/cleanenergy/energy-resources/calculator.html, 
accessed 04/09/12.
---------------------------------------------------------------------------

    The EPA recognizes that the methane reductions from this rule will 
provide for significant economic climate benefits to society just 
described. However, the 2009-2010 Interagency Social Cost of Carbon 
Work Group did not produce directly modeled estimates of the social 
cost of methane. In the absence of direct model estimates from the 
interagency analysis, the EPA has used a ``global warming potential 
(GWP) approach'' to estimate the dollar value of this rule's methane 
co-benefits. Specifically, the EPA converted methane to CO2 
equivalents using the GWP of methane, then multiplied these 
CO2 equivalent emission reductions by the social cost of 
carbon developed by the Interagency Social Cost of Carbon Work Group.
    The social cost of carbon is an estimate of the net present value 
of the flow of monetized damages from a 1-metric ton increase in 
CO2 emissions in

[[Page 49536]]

a given year (or from the alternative perspective, the benefit to 
society of reducing CO2 emissions by 1 ton). For more 
information about the social cost of carbon, see the Support Document: 
Social Cost of Carbon for Regulatory Impact Analysis Under Executive 
Order 12866.\41\ Applying this approach to the methane reductions 
estimated for the NESHAP Amendments and NSPS, the 2015 climate co-
benefits vary by discount rate and range from about $100 million to 
approximately $1.3 billion; the mean social cost of carbon at the 3-
percent discount rate results in an estimate of about $440 million in 
2015.\42\
---------------------------------------------------------------------------

    \41\ Interagency Working Group on Social Cost of Carbon (IWGSC). 
2010. Technical Support Document: Social Cost of Carbon for 
Regulatory Impact Analysis Under Executive Order 12866. Docket ID 
EPA-HQ-OAR-2009-0472-114577. http://www.epa.gov/otaq/climate/regulations/scc-tsd.pdf, accessed 02/12/12.
    \42\ The ratio of domestic to global benefits of emission 
reductions varies with key parameter assumptions. See Interagency 
Working Group on Social Cost of Carbon. 2010. Technical Support 
Document: Social Cost of Carbon for Regulatory Impact Analysis Under 
Executive Order 12866.
---------------------------------------------------------------------------

    These co-benefits equate to a range of approximately $110 to $1,400 
per short ton of methane reduced, depending upon the discount rate 
assumed with a per ton estimate of $480 at the 3-percent discount rate. 
These social cost of methane benefit estimates are not the same as 
would be derived from direct computations (using the integrated 
assessment models employed to develop the Interagency Social Cost of 
Carbon estimates) for a variety of reasons, including the shorter 
atmospheric lifetime of methane relative to CO2 (about 12 
years compared to CO2 whose concentrations in the atmosphere 
decay on timescales of decades to millennia). The climate impacts also 
differ between the pollutants for reasons other than the radiative 
forcing profiles and atmospheric lifetimes of these gases.
    Methane is a precursor to ozone and ozone is a short-lived climate 
forcer that contributes to global warming. The use of the IPCC Second 
Assessment Report GWP to approximate co-benefits may underestimate the 
direct radiative forcing benefits of reduced ozone levels and does not 
capture any secondary climate co-benefits involved with ozone-ecosystem 
interactions. In addition, a recent the EPA National Center of 
Environmental Economics working paper suggests that this quick ``GWP 
approach'' to benefits estimation will likely understate the climate 
benefits of methane reductions in most cases.\43\ This conclusion is 
reached using the 100-year GWP for methane of 25 as put forth in the 
IPCC Fourth Assessment Report (AR 4), as opposed to the lower value of 
21 used in this analysis. Using the higher GWP estimate of 25 would 
increase these reported methane climate co-benefit estimates by about 
19 percent. Although the IPCC Assessment Report (AR4) suggested a GWP 
of 25 for methane, the EPA has used the GWP of 21 from the IPCC Second 
Assessment Report to estimate the methane climate co-benefits for this 
oil and gas rule. The EPA uses the 21 GWP in order to provide estimates 
more consistent with global GHG inventories, which currently use GWP 
from the IPCC Second Assessment Report, and with the US GHG Reporting 
program. See the Regulatory Impact Analysis for further details.
---------------------------------------------------------------------------

    \43\ Marten and Newbold (2011), Estimating the Social Cost of 
Non-CO2 GHG Emissions: Methane and Nitrous Oxide, NCEE 
Working Paper Series 11-01. http://yosemite.epa.gov/EE/epa/eed.nsf/WPNumber/2011-01?OpenDocument.
---------------------------------------------------------------------------

    Due to the uncertainties involved with the ``GWP approach'' 
estimates presented and methane climate co-benefits estimates available 
in the literature, the EPA chooses not to compare these co-benefit 
estimates to the costs of the rule for this proposal. Rather, the EPA 
presents the ``GWP approach'' climate co-benefit estimates as an 
interim method to produce these estimates until the Interagency Social 
Cost of Carbon Work Group develops values for non-CO2 GHG.
    For the final NESHAP amendments, a break-even analysis suggests 
that HAP emissions would need to be valued at $5,200 per ton for the 
benefits to exceed the costs if the health, ecosystem and climate 
benefits from the reductions in VOC and methane emissions are assumed 
to be zero. Even though emission reductions of VOC and methane are co-
benefits for the final NESHAP amendments, they are legitimate 
components of the total benefit-cost comparison. If we assume the 
health benefits from HAP emission reductions are zero, the VOC 
emissions would need to be valued at $2,900 per ton or the methane 
emissions would need to be valued at $8,300 per ton for the co-benefits 
to exceed the costs. All estimates are in 2008 dollars. For the final 
NSPS, the revenue from additional product recovery exceeds the costs, 
which renders a break-even analysis unnecessary when these revenues are 
included in the analysis. Based on the methodology from Fann, Fulcher, 
and Hubbell (2009),\44\ ranges of benefit-per-ton estimates for 
emissions of VOC indicate that on average in the United States, VOC 
emissions are valued from $1,200 to $3,000 per ton as a 
PM2.5 precursor, but emission reductions in specific areas 
are valued from $280 to $7,000 per ton in 2008 dollars. As a result, 
even if VOC emissions from oil and natural gas operations result in 
monetized benefits that are substantially below the national average, 
there is a reasonable chance that the benefits of the rule would exceed 
the costs, especially if we were able to monetize all of the additional 
benefits associated with ozone formation, visibility, HAP and methane.
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    \44\ Fann, N., C.M. Fulcher, B.J. Hubbell. The influence of 
location, source, and emission type in estimates of the human health 
benefits of reducing a ton of air pollution. Air Qual Atmos Health 
(2009) 2:169-176.
---------------------------------------------------------------------------

XII. Statutory and Executive Order Reviews

A. Executive Order 12866, Regulatory Planning and Review and Executive 
Order 13563, Improving Regulation and Regulatory Review

    Under section 3(f)(1) of Executive Order 12866 (58 FR 51735, 
October 4, 1993), this action is an ``economically significant 
regulatory action'' because it is likely to have an annual effect on 
the economy of $100 million or more. Accordingly, the EPA submitted 
this action to the Office of Management and Budget (OMB) for review 
under Executive Order 12866 and Executive Order 13563 (76 FR 3821, 
January 21, 2011), and any changes made in response to OMB 
recommendations have been documented in the docket for this action.
    In addition, the EPA prepared a Regulatory Impact Analysis (RIA) of 
the potential costs and benefits associated with this action. The RIA 
available in the docket describes in detail the empirical basis for the 
EPA's assumptions and characterizes the various sources of 
uncertainties affecting the estimates below. Table 7 shows the results 
of the cost and benefits analysis for these final rules.

[[Page 49537]]



Table 7--Summary of the Monetized Benefits, Social Costs and Net Benefits for the Final Oil and Natural Gas NSPS
                                          and NESHAP Amendments in 2015
                                             [Millions of 2008$] \1\
----------------------------------------------------------------------------------------------------------------
                                                                                          Final NSPS and NESHAP
                                              Final NSPS        Final NESHAP amendments    amendments combined
----------------------------------------------------------------------------------------------------------------
Total Monetized Benefits \2\.........  N/A....................  N/A....................  N/A.
Total Costs \3\......................  -$15 million...........  $3.5 million...........  -$11 million.
Net Benefits.........................  N/A....................  N/A....................  N/A.
Non-monetized Benefits \4\...........  11,000 tons of HAP.....  670 tons of HAP........  12,000 tons of HAP.
                                       190,000 tons of VOC....  1,200 tons of VOC......  190,000 tons of VOC.
                                       1.0 million tons of      420 tons of methane....  1.0 million tons of
                                        methane.                                          methane.
                                      --------------------------------------------------------------------------
                                       Health effects of HAP exposure.
                                       Health effects of PM2.5 and ozone exposure.
                                       Visibility impairment.
                                       Vegetation effects.
                                       Climate effects.
----------------------------------------------------------------------------------------------------------------
\1\ All estimates are for the implementation year (2015).
\2\ While we expect that these avoided emissions will result in improvements in air quality and reductions in
  health effects associated with HAP, ozone, and particulate matter (PM) as well as climate effects associated
  with methane, we have determined that quantification of those benefits and co-benefits cannot be accomplished
  for this rule in a defensible way. This is not to imply that there are no benefits or co-benefits of the
  rules; rather, it is a reflection of the difficulties in modeling the direct and indirect impacts of the
  reductions in emissions for this industrial sector with the data currently available.
\3\ The engineering compliance costs are annualized using a 7-percent discount rate. The negative cost for the
  final NSPS reflects the inclusion of revenues from additional natural gas and hydrocarbon condensate recovery
  that are estimated as a result of the NSPS. Possible explanations for why there appear to be negative cost
  control technologies are discussed in the engineering costs analysis section in the RIA.
\4\ For the NSPS, reduced exposure to HAP and climate effects are co-benefits. For the NESHAP, reduced VOC
  emissions, PM2.5 and ozone exposure, visibility and vegetation effects and climate effects are co-benefits.
  The specific control technologies for the final NSPS are anticipated to have minor secondary disbenefits,
  including an increase of 1.1 million tons of carbon dioxide (CO2), 550 tons of nitrogen oxides (NOX), 19 tons
  of PM, 3,000 tons of CO and 1,100 tons of total hydrocarbons (THC), as well as emission reductions associated
  with the energy system impacts. The specific control technologies for the NESHAP are anticipated to have minor
  secondary disbenefits, but the EPA was unable to estimate these secondary disbenefits. The net CO2-equivalent
  emission reductions are 18 million metric tons.

B. Paperwork Reduction Act

    The information collection requirements in this rule have been 
submitted for approval to the Office of Management and Budget (OMB) 
under the Paperwork Reduction Act, 44 U.S.C. 3501, et seq. The 
information collection requirements are not enforceable until OMB 
approves them.
    The ICR documents prepared by the EPA have been assigned EPA ICR 
numbers 2437.01, 2438.01, 2439.01 and 2440.01. The information 
requirements are based on notification, recordkeeping and reporting 
requirements in the NESHAP General Provisions (40 CFR part 63, subpart 
A), which are mandatory for all operators subject to national emission 
standards. These recordkeeping and reporting requirements are 
specifically authorized by CAA section 114 (42 U.S.C. 7414). All 
information submitted to the EPA pursuant to the recordkeeping and 
reporting requirements for which a claim of confidentiality is made is 
safeguarded according to Agency policies set forth in 40 CFR part 2, 
subpart B. This final rule requires maintenance inspections of the 
control devices but would not require any notifications or reports 
beyond those required by the General Provisions. The recordkeeping 
requirements require only the specific information needed to determine 
compliance.
    When a malfunction occurs, sources must report them according to 
the applicable reporting requirements of 40 CFR part 63, subpart HH or 
40 CFR part 63, subpart HHH. An affirmative defense to civil penalties 
for exceedances of emission limits that are caused by malfunctions is 
available to a source if it can demonstrate that certain criteria and 
requirements are satisfied. The criteria ensure that the affirmative 
defense is available only where the event that causes an exceedance of 
the emission limit meets the narrow definition of malfunction in 40 CFR 
63.2 (sudden, infrequent, not reasonable preventable, and not caused by 
poor maintenance and/or careless operation) and where the source took 
necessary actions to minimize emissions. In addition, the source must 
meet certain notification and reporting requirements. For example, the 
source must prepare a written root cause analysis and submit a written 
report to the Administrator documenting that it has met the conditions 
and requirements for assertion of the affirmative defense.
    For this rule, the EPA is adding affirmative defense to the 
estimate of burden in the ICR. To provide the public with an estimate 
of the relative magnitude of the burden associated with an assertion of 
the affirmative defense position adopted by a source, the EPA has 
provided administrative adjustments to this ICR that shows what the 
notification, recordkeeping and reporting requirements associated with 
the assertion of the affirmative defense might entail. The EPA's 
estimate for the required notification, reports, and records, including 
the root cause analysis, associated with a single incident totals 
approximately totals $3,141 and is based on the time and effort 
required of a source to review relevant data, interview plant 
employees, and document the events surrounding a malfunction that has 
caused an exceedance of an emission limit. The estimate also includes 
time to produce and retain the record and reports for submission to the 
EPA. The EPA provides this illustrative estimate of this burden, 
because these costs are only incurred if there has been a violation, 
and a source chooses to take advantage of the affirmative defense.
    The EPA provides this illustrative estimate of this burden because 
these costs are only incurred if there has been a violation and a 
source chooses to take advantage of the affirmative defense. Given the 
variety of circumstances under which malfunctions could occur, as well 
as differences among sources' operation and maintenance practices, we 
cannot reliably predict the severity and frequency of malfunction-
related excess emissions events for a particular source. It is 
important to note that the

[[Page 49538]]

EPA has no basis currently for estimating the number of malfunctions 
that would qualify for an affirmative defense. Current historical 
records would be an inappropriate basis, as source owners or operators 
previously operated their facilities in recognition that they were 
exempt from the requirement to comply with emissions standards during 
malfunctions. Of the number of excess emissions events reported by 
source operators, only a small number would be expected to result from 
a malfunction (based on the definition above), and only a subset of 
excess emissions caused by malfunctions would result in the source 
choosing to assert the affirmative defense. Thus, we believe the number 
of instances in which source operators might be expected to avail 
themselves of the affirmative defense will be extremely small.
    For this reason, we estimate a total of 39 such occurrences for all 
sources subject to 40 CFR part 63, subpart HH, a total of three such 
occurrences for all sources subject to 40 CFR part 63, subpart HHH, and 
a total of 6 such occurrences for all sources subject to 40 CFR part 
60, subparts KKK and LLL over the 3-year period covered by this ICR. We 
expect to gather information on such events in the future, and will 
revise this estimate as better information becomes available.
    The annual monitoring, reporting, and recordkeeping burden for this 
collection (averaged over the first 3 years after the effective date of 
the standards) is estimated to be $20.1 million. This includes 384,866 
labor hours per year at a total labor cost of $19.5 million per year, 
and annualized capital costs of $0.36 million, and annual operating and 
maintenance costs of $0.20 million. This estimate includes initial and 
annual performance tests, semiannual excess emission reports, 
developing a monitoring plan, notifications and recordkeeping. All 
burden estimates are in 2008 dollars and represent the most cost-
effective monitoring approach for affected facilities. Burden is 
defined at 5 CFR 1320.3(b).
    An agency may not conduct or sponsor, and a person is not required 
to respond to, a collection of information unless it displays a 
currently valid OMB control number. The OMB control numbers for the 
EPA's regulations in 40 CFR are listed in 40 CFR part 9. When these ICR 
are approved by OMB, the agency will publish a technical amendment to 
40 CFR part 9 in the Federal Register to display the OMB control 
numbers for the approved information collection requirements contained 
in the final rule.

C. Regulatory Flexibility Act

    The Regulatory Flexibility Act generally requires an agency to 
prepare a regulatory flexibility analysis of any rule subject to notice 
and comment rulemaking requirements under the Administrative Procedure 
Act or any other statute, unless the agency certifies that the rule 
will not have a significant economic impact on a substantial number of 
small entities (SISNOSE). Small entities include small businesses, 
small organizations, and small governmental jurisdictions. For purposes 
of assessing the impact of this rule on small entities, a small entity 
is defined as: (1) A small business as defined by NAICS codes 211111, 
211112, 221210, 486110 and 486210; whose parent company has no more 
than 500 employees (or revenues of less than $7 million for firms that 
transport natural gas via pipeline); (2) a small governmental 
jurisdiction that is a government of a city, county, town, school 
district, or special district with a population of less than 50,000; 
and (3) a small organization that is any not-for-profit enterprise 
which is independently owned and operated and is not dominant in its 
field.
    For the final NSPS, the EPA performed an analysis for impacts on a 
sample of expected affected small entities by comparing compliance 
costs to entity revenues. The baseline used in this analysis takes into 
account REC conducted pursuant to state regulations covering these 
operations and estimates of REC performed voluntarily. To account for 
REC performed in regulated states, the EPA subsumed emissions 
reductions and compliance costs in states where these completion-
related emissions are already controlled into the baseline. 
Additionally, based on public comments and reports to the EPA's Natural 
Gas STAR program, the EPA recognizes that some producers conduct well 
completions using REC techniques voluntarily for economic and/or 
environmental objectives as a normal part of business. To account for 
emissions reductions and costs arising from voluntary implementation of 
pollution controls, the EPA used information on total emission 
reductions reported to the EPA by partners of the EPA Natural Gas STAR. 
This estimate of this voluntary REC activity in the absence of 
regulation is also included in the baseline. More detailed discussion 
on the derivation of the baseline is presented in a technical 
memorandum in the docket, as well as in the RIA.
    Based upon the analysis in the RIA, which is in the Docket, when 
revenue from additional natural gas product recovered is not included, 
we estimate that 123 of the 127 small firms analyzed (97 percent) are 
likely to have impacts less than 1 percent in terms of the ratio of 
annualized compliance costs to revenues. Meanwhile, four firms (3 
percent) are likely to have impacts greater than 1 percent. Three of 
these four firms are likely to have impacts greater than 3 percent. 
However, when revenue from additional natural gas product recovery is 
included, we estimate that none of the analyzed firms will have an 
impact greater than 1 percent.
    For the final NESHAP amendments, we estimate that 11 of the 35 
firms (31 percent) that own potentially affected facilities are small 
entities. The EPA performed an analysis for impacts on all expected 
affected small entities by comparing compliance costs to entity 
revenues. Among the small firms, none are likely to have impacts 
greater than 1 percent in terms of the ratio of annualized compliance 
costs to revenues.
    After considering the economic impact of the combined NSPS and 
NESHAP amendments on small entities, I certify this action will not 
have a significant impact on a substantial number of small entities 
(SISNOSE). While both the NSPS and NESHAP amendment would individually 
result in a no SISNOSE finding, the EPA performed an additional 
analysis in order to certify the rule in its entirety. This analysis 
compared compliance costs to entity revenues for the total of all the 
entities affected by the NESHAP amendments and the sample of entities 
analyzed for the NSPS. When revenues from additional natural gas 
product sales are not included, 132 of the 136 small firms (97 percent) 
in the sample are likely to have impacts of less than 1 percent in 
terms of the ratio of annualized compliance costs to revenues. 
Meanwhile, four firms (3 percent) are likely to have impacts greater 
than 1 percent. Three of these four firms are likely to have impacts 
greater than 3 percent. When revenues from additional natural gas 
product sales are included, none of the 136 small firms (100 percent) 
are likely to have impacts greater than 1 percent.
    Our determination is informed by the fact that many affected firms 
are expected to receive revenues from the additional natural gas and 
condensate recovery engendered by the implementation of the controls 
evaluated in this RIA. As much of the additional natural gas recovery 
is estimated to arise from completion-related activities, we expect the 
impact

[[Page 49539]]

on well-related compliance costs to be significantly mitigated. This 
conclusion is enhanced because the returns to REC activities occur 
without a significant time lag between implementing the control and 
obtaining the recovered product, unlike many control options where the 
emissions reductions accumulate over long periods of time; the reduced 
emission completions occur over a short span of time, during which the 
additional product recovery is also accomplished and payments for 
recovered products are settled.
    Although this final rule will not impact a substantial number of 
small entities, the EPA, nonetheless, has tried to reduce the impact of 
this rule on small entities by setting the final emissions limits at 
the MACT floor, the least stringent level allowed by law.

D. Unfunded Mandates Reform Act

    This final action does not contain a federal mandate under the 
provisions of Title II of the Unfunded Mandates Reform Act of 1995 
(UMRA), 2 U.S.C. 1531-1538 for state, local, and tribal governments, in 
the aggregate, or to the private sector. The action would not result in 
expenditures of $100 million or more for state, local, and tribal 
governments, in the aggregate, or to the private sector in any 1 year. 
Thus, this final rule is not subject to the requirements of sections 
202 or 205 of UMRA.
    This final rule is also not subject to the requirements of section 
203 of UMRA because it contains no regulatory requirements that might 
significantly or uniquely affect small governments because it contains 
no requirements that apply to such governments nor does it impose 
obligations upon them.

E. Executive Order 13132: Federalism

    This action does not have federalism implications. It will not have 
substantial direct effects on the states, on the relationship between 
the national government and the states, or on the distribution of power 
and responsibilities among the various levels of government, as 
specified in Executive Order 13132. These final rules primarily affect 
private industry, and do not impose significant economic costs on state 
or local governments. On the contrary, we believe the modification 
provisions discussed in section IX.A for well completions conducted at 
gas wells constructed on or before August 23, 2011, will reduce 
permitting burden borne by the States. These provisions will result in 
fewer sources becoming affected facilities under the NSPS while 
achieving emission reductions beginning October 15, 2012 equal to those 
achieved by new sources beginning January 1, 2015. Thus, Executive 
Order 13132 does not apply to this action.

F. Executive Order 13175: Consultation and Coordination With Indian 
Tribal Governments

    Subject to the Executive Order 13175 (65 FR 67249, November 9, 
2000) the EPA may not issue a regulation that has tribal implications, 
that imposes substantial direct compliance costs, and that is not 
required by statute, unless the Federal government provides the funds 
necessary to pay the direct compliance costs incurred by tribal 
governments, or the EPA consults with tribal officials early in the 
process of developing the proposed regulation and develops a tribal 
summary impact statement.
    The EPA has concluded that this action will not have tribal 
implications because it doesn't impose a significant cost to the tribal 
government. However, there are significant tribal interests because of 
the growth of the oil and gas production industry in Indian country.
    The EPA initiated a consultation process with tribal officials 
early in the process of developing this regulation to permit them to 
have meaningful and timely input into its development. During the 
consultation process, the EPA conducted outreach and information 
meetings prior to the proposal in 2010. The EPA met with the Inter 
Tribal Environmental Council, which include many of the Region VI 
tribes, The Tribal leadership summit in Region X, and Tribal Energy 
Conference hosted by Ft. Belknap, and the National Tribal Forum.
    After the proposal was published, letters were sent to all tribal 
leaders offering to consult on a government-to-government basis on the 
rule. As part of the consultation process and in response to these 
letters, an outreach call was held on October 12, 2011. Tribes that 
participated on this call were: Fond du Lac Band of Lake Superior 
Chippewa, Fort Belknap Indian Community, Forest County Potawatomi 
Community, Southern Ute Indian Tribe, and Pueblo of Santa Clara.
    In this meeting the tribes were presented the information in the 
proposal. The tribes asked general clarifying questions but did not 
provide specific comments. Comments on the proposal were received from 
an affiliate of the Southern Ute Indian Tribe. The commenter expressed 
concern about the impacts of the rule on natural gas and oil production 
operations on the Southern Ute Indian reservation and requested 
additional time to evaluate the impacts. In response to this and other 
requests, the comment period was extended. More specific comments can 
be found in the docket.

G. Executive Order 13045: Protection of Children From Environmental 
Health Risks and Safety Risks

    This action is not subject to Executive Order 13045 (62 FR 19885, 
April 23, 1997) because the Agency does not believe the environmental 
health risks or safety risks addressed by this action present a 
disproportionate risk to children. This action would not relax the 
control measures on existing regulated sources. The EPA's risk 
assessments (included in the docket for this final rule) demonstrate 
that the existing regulations are associated with an acceptable level 
of risk and provide an ample margin of safety to protect public health.

H. Executive Order 13211: Actions Concerning Regulations That 
Significantly Affect Energy Supply, Distribution, or Use

    This action is not a ``significant energy action'' as defined in 
Executive Order 13211 (66 FR 28355, May 22, 2001), because it is not 
likely to have a significant adverse effect on the supply, 
distribution, or use of energy. These final rules will result in the 
addition of control equipment and monitoring systems for existing and 
new sources within the oil and natural gas industry. The final NESHAP 
amendments are unlikely to have a significant adverse effect on the 
supply, distribution, or use of energy. As such, the final NESHAP 
amendments are not ``significant energy actions'' as defined in 
Executive Order 13211, (66 FR 28355, May 22, 2001). The final NSPS is 
also unlikely to have a significant adverse effect on the supply, 
distribution, or use of energy. As such, the final NSPS is not a 
``significant energy action'' as defined in Executive Order 13211 (66 
FR 28355, May 22, 2001).
    The basis for these determinations is as follows. Emission controls 
for the NSPS capture VOC emissions that otherwise would be vented to 
the atmosphere. Since methane is co-emitted with VOC, a large 
proportion of the averted methane emissions can be directed into 
natural gas production streams and sold. One pollution control 
requirement of the final NSPS also captures saleable condensates. The 
revenues from additional natural gas and condensate recovery are 
expected to offset the costs of implementing the final rules.
    We use the NEMS to estimate the impacts of the combined final rules 
on

[[Page 49540]]

the United States energy system. The NEMS is a publically available 
model of the United States energy economy developed and maintained by 
the Energy Information Administration of the DOE and is used to produce 
the Annual Energy Outlook, a reference publication that provides 
detailed forecasts of the United States energy economy.
    Based on public comments and reports to EPA's Natural Gas STAR 
program, the EPA recognizes that some producers conduct well 
completions using REC techniques, which are required by the final NSPS 
for certain completions of hydraulically fractured and refractured 
natural gas wells, voluntarily based upon economic and environmental 
objectives. The baseline used for the energy system impacts analysis 
takes into account REC conducted pursuant to state regulations covering 
these operations and estimates of REC performed voluntarily. To account 
for REC performed in regulated states, the EPA subsumed emissions 
reductions and compliance costs in states where these completion-
related emissions are already controlled into the baseline. 
Additionally, based on public comments and reports to the EPA's Natural 
Gas STAR program, the EPA recognizes that some producers conduct well 
completions using REC techniques voluntarily for economic and/or 
environmental objectives as a normal part of business. To account for 
emissions reductions and costs arising from voluntary implementation of 
pollution controls, the EPA used information on total emission 
reductions reported to the EPA by partners of the EPA Natural Gas STAR. 
This estimate of this voluntary REC activity in the absence of 
regulation is also included in the baseline. More detailed discussion 
on the derivation of the baseline is presented in a technical 
memorandum in the docket, as well as in the RIA.
    The analysis of energy system impacts for the final NSPS under the 
primary baseline shows that domestic natural gas production is not 
likely to change in 2015, the year used in the RIA to analyze impacts. 
Average natural gas prices are also not estimated to change in response 
to the final rules. Domestic crude oil production is not expected to 
change, while average crude oil prices are estimated to decrease 
slightly (about $0.01/barrel or about 0.01 percent at the wellhead for 
onshore production in the lower 48 states). All prices are in 2008 
dollars. The NEMS-based analysis estimates in the year of analysis, 
2015, that net imports of natural gas and crude oil will not change.
    Additionally, the NSPS establishes several performance standards 
that give regulated entities flexibility in determining how to best 
comply with the regulation. In an industry that is geographically and 
economically heterogeneous, this flexibility is an important factor in 
reducing regulatory burden.
    For more information on the estimated energy effects, please refer 
to the economic impact analysis for this final rule. The analysis is 
available in the RIA, which is in the public docket.

I. National Technology Transfer and Advancement Act

    Section 12(d) of the National Technology Transfer and Advancement 
Act of 1995 (NTTAA), Public Law 104-113 (15 U.S.C. 272 note) directs 
the EPA to use voluntary consensus standards (VCS) in its regulatory 
activities, unless to do so would be inconsistent with applicable law 
or otherwise impractical. VCS are technical standards (e.g., materials 
specifications, test methods, sampling procedures and business 
practices) that are developed or adopted by VCS bodies. NTTAA directs 
the EPA to provide Congress, through OMB, explanations when the agency 
decides not to use available and applicable VCS.
    This final rulemaking involves technical standards. Three VCS were 
identified as applicable for the purpose of these rules. The VCS ASTM 
D6522-00 (2005), Standard Test Method for the Determination of Nitrogen 
Oxides, Carbon Monoxide, and Oxygen Concentrations in Emissions From 
Natural Gas-Fired Reciprocating Engines, Combustion Turbines, Boilers 
and Process Heaters Using Portable Analyzers, is an acceptable 
alternative to EPA Methods 3A and 10 for identifying nitrogen oxides, 
carbon monoxide, and oxygen concentrations when the fuel is natural 
gas. The VCS ASTM D6420-99 (2004), Test Method for Determination of 
Gaseous Organic Compounds by Direct Interface Gas Chromatography/Mass 
Spectrometry, is an acceptable alternative to EPA Method 18. The VCS 
ANSI/ASME PTC 19.10-1981 (Part 10, Instruments and Apparatus), Flue and 
Exhaust Gas Analyses is an acceptable alternative to EPA Methods 3B and 
16A manual portion only, not the instrumental portion.
    No potential VCS were identified for EPA Methods 1A, 2A, 2D, 21, 
and 22.
    During the search, if the title or abstract (if provided) of the 
VCS described technical sampling and analytical procedures that were 
similar to the EPA's reference method, the EPA ordered a copy of the 
standard and reviewed it as a potential equivalent method. All 
potential standards were reviewed to determine the practicality of the 
VCS for this action. This review requires significant method validation 
data that meet the requirements of EPA Method 301 for accepting 
alternative methods or scientific, engineering and policy equivalence 
to procedures in the EPA reference methods. The EPA may reconsider 
determinations of impracticality when additional information is 
available for particular VCS.
    The search identified 18 other VCS that were potentially applicable 
for these rules in lieu of the EPA reference methods. After reviewing 
the available standards, the EPA determined that 18 candidate VCS (ASTM 
D3154-00 (2006), ASTM D3464-96 (2007), ASTM D3796-90 (2004), ISO 
10780:1994, ASME B133.9-1994 (2001), ANSI/ASME PTC 19.10-1981 Part 10, 
ASTM D5835-95 (2007), ISO 10396:1993, ISO 12039:2001, ASTM D6522-00 
(2005), CAN/CSA Z223.2-M86 (1999), CAN/CSA Z223.21-M1978, ASTM D3162-94 
(2005), ASTM D4323-84 (2009), ASTM D6060-96 (2001), ISO 14965:2000(E), 
EN 12619 (1999), ASTM D4855-97 (2002)) identified for measuring 
emissions of pollutants or their surrogates subject to emission 
standards in the rules would not be practical due to lack of 
equivalency, documentation, validation data and other important 
technical and policy considerations. Refer to the memorandum in the 
docket for further details on the EPA's review of these VCS.

J. Executive Order 12898: Federal Actions to Address Environmental 
Justice in Minority Populations and Low-Income Populations

    Executive Order 12898 (59 FR 7629, February 16, 1994) establishes 
Federal executive policy on environmental justice. Its main provision 
directs Federal agencies, to the greatest extent practicable and 
permitted by law, to make environmental justice part of their mission 
by identifying and addressing, as appropriate, disproportionately high 
and adverse human health or environmental effects of their programs, 
policies and activities on minority populations and low income 
populations in the United States.
    The EPA has determined that this final rule will not have 
disproportionately high and adverse human health or environmental 
effects on minority or low-income populations because it increases the 
level of environmental protection for all affected populations without 
having any disproportionately high and adverse

[[Page 49541]]

human health or environmental effects on any population, including any 
minority, low-income, or indigenous populations.
    To examine the potential for any environmental justice issues that 
might be associated with each source category, we evaluated the 
percentages of various social, demographic, and economic groups within 
the at-risk population living near the facilities where these source 
categories are located and compared them to national averages. The 
development of demographic analyses to inform the consideration of 
environmental justice issues in the EPA rulemakings is an evolving 
science.
    The EPA conducted a demographic analysis, focusing on populations 
within 50 km of any facility in each of the source categories that are 
estimated to have HAP exposures which result in cancer risks of 1-in-1 
million or greater or non-cancer hazard indices of 1 or greater based 
on estimates of current HAP emissions. The results of this analysis are 
documented in the technical report: Risk and Technology Review--
Analysis of Socio-Economic Factors for Populations Living Near Oil & 
Natural Gas Production Facilities, located in the docket for this 
rulemaking.
    As described in the preamble, our risk assessments demonstrate that 
the regulations for the oil and natural gas production and natural gas 
transmission and storage source categories, are associated with an 
acceptable level of risk and that the proposed additional requirements 
will provide an ample margin of safety to protect public health. Our 
analyses also show that, for these source categories, there is no 
potential for an adverse environmental effect or human health multi-
pathway effects, and that acute and chronic non-cancer health impacts 
are unlikely. The EPA has determined that, although there may be an 
existing disparity in HAP risks from these sources between some 
demographic groups, no demographic group is exposed to an unacceptable 
level of risk.
    To promote meaningful involvement, the EPA conducted three public 
hearings on the proposal. The hearings were held in Pittsburgh, 
Pennsylvania, on September 27, 2011, Denver, Colorado, on September 28, 
2011, and Arlington, Texas, on September 29, 2011. A total of 261 
people spoke at the three hearings and 735 people attended the 
hearings. The attendees at the hearings included private citizens, 
community-based and environmental organizations, industry 
representatives, associations representing industry and local and state 
government officials.

K. Congressional Review Act

    The Congressional Review Act, 5 U.S.C. 801, et seq., as added by 
the Small Business Regulatory Enforcement Fairness Act of 1996, 
generally provides that before a rule may take effect, the agency 
promulgating the rule must submit a rule report, which includes a copy 
of the rule, to each House of the Congress and to the Comptroller 
General of the United States. The EPA will submit a report containing 
this final rule and other required information to the United States 
Senate, the United States House of Representatives, and the Comptroller 
General of the United States prior to publication of the final rule in 
the Federal Register. A major rule cannot take effect until 60 days 
after it is published in the Federal Register. This action is a ``major 
rule'' as defined by 5 U.S.C. 804(2). The final rules will be effective 
on October 15, 2012.

List of Subjects

40 CFR Part 60

    Environmental protection, Air pollution control, Incorporation by 
reference, Reporting and recordkeeping requirements, Volatile organic 
compounds.

40 CFR Part 63

    Environmental protection, Administrative practice and procedures, 
Air pollution control, Hazardous substances, Incorporation by 
reference, Reporting and recordkeeping requirements, Volatile organic 
compounds.

    Dated: April 17, 2012.
Lisa P. Jackson,
Administrator.

    For the reasons set out in the preamble, title 40, chapter I of the 
Code of Federal Regulations is amended as follows:

PART 60--[AMENDED]

0
1. The authority citation for part 60 continues to read as follows:

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


0
2. Section 60.17 is amended by:
0
a. Revising paragraph (a) introductory text, (a)(7), (a)(86), (a)(91), 
and (a)(92);
0
b. Adding paragraphs (a)(95), (a)(96), (a)(97), and (a)(98); and
0
c. Revising paragraph (h) introductory text and (h)(4) to read as 
follows:


Sec.  60.17  Incorporations by reference.

* * * * *
    (a) The following materials are available for purchase from at 
least one of the following addresses: American Society for Testing and 
Materials (ASTM), 100 Barr Harbor Drive, Post Office Box C700, West 
Conshohocken, PA 19428-2959, Telephone (610) 832-9585, and are also 
available at the following Web site: http://www.astm.org; or ProQuest, 
789 East Eisenhower Parkway, Ann Arbor, MI 48106-1346, Telephone (734) 
761-4700, and are also available at the following Web site: http://www.proquest.com.
* * * * *
    (7) ASTM D86-96, Standard Test Method for Distillation of Petroleum 
Products (Approved April 10, 1996), IBR approved for Sec. Sec.  60.562-
2(d), 60.593(d), 60.593a(d), 60.633(h) and 60.5401(f).
* * * * *
    (86) ASTM D6522-00 (Reapproved 2005), Standard Test Method for 
Determination of Nitrogen Oxides, Carbon Monoxide, and Oxygen 
Concentrations in Emissions from Natural Gas-Fired Reciprocating 
Engines, Combustion Turbines, Boilers, and Process Heaters Using 
Portable Analyzers (Approved October 1, 2005), IBR approved for table 2 
of subpart JJJJ of this part, and Sec. Sec.  60.5413(b) and (d).
* * * * *
    (91) ASTM E169-93, Standard Practices for General Techniques of 
Ultraviolet-Visible Quantitative Analysis (Approved May 15, 1993), IBR 
approved for Sec. Sec.  60.485a(d), 60.593(b), 60.593a(b), 60.632(f) 
and 60.5400(f).
    (92) ASTM E260-96, Standard Practice for Packed Column Gas 
Chromatography (Approved April 10, 1996), IBR approved for Sec. Sec.  
60.485a(d), 60.593(b), 60.593a(b), 60.632(f), 60.5400(f) and 
60.5406(b).
* * * * *
    (95) ASTM D3588-98 (Reapproved 2003) Standard Practice for 
Calculating Heat Value, Compressibility Factor, and Relative Density of 
Gaseous Fuels (Approved May 10, 2003), IBR approved for Sec.  
60.5413(d).
    (96) ASTM D4891-89 (Reapproved 2006) Standard Test Method for 
Heating Value of Gases in Natural Gas Range by Stoichiometric 
Combustion (Approved June 1, 2006), IBR approved for Sec.  60.5413(d).
    (97) ASTM D1945-03 (Reapproved 2010), Standard Test Method for 
Analysis of Natural Gas by Gas Chromatography (Approved January 1, 
2010), IBR approved for Sec.  60.5413(d).
    (98) ASTM D5504-08, Standard Test Method for Determination of 
Sulfur Compounds in Natural Gas and Gaseous Fuels by Gas Chromatography 
and Chemiluminescence (Approved June 15, 2008), IBR approved for Sec.  
60.5413(d).
* * * * *

[[Page 49542]]

    (h) The following material is available for purchase from the 
American Society of Mechanical Engineers (ASME), Three Park Avenue, New 
York, NY 10016-5990, Telephone (800) 843-2763, and are also available 
at the following Web site: http://www.asme.org.
* * * * *
    (4) ANSI/ASME PTC 19.10-1981, Flue and Exhaust Gas Analyses [Part 
10, Instruments and Apparatus] (Issued August 31, 1981), IBR approved 
for Sec. Sec.  60.56c(b), 60.63(f), 60.106(e), 60.104a(d), (h), (i) and 
(j), 60.105a(d), (f) and (g), 60.106a(a), 60.107a(a), (c) and (d), 
tables 1 and 3 of subpart EEEE, tables 2 and 4 of subpart FFFF, table 2 
of subpart JJJJ, Sec. Sec.  60.4415(a), 60.2145(s) and (t), 60.2710(s), 
(t) and (w), 60.2730(q), 60.4900(b) and 60.5220(b), tables 1 and 2 to 
subpart LLLL, tables 2 and 3 to subpart MMMM, Sec. Sec.  60.5406(c) and 
60.5413(b).
* * * * *

Subpart KKK--Standards of Performance for Equipment Leaks of VOC 
From Onshore Natural Gas Processing Plants for Which Construction, 
Reconstruction, or Modification Commenced After January 20, 1984, 
and on or Before August 23, 2011

0
3. The heading for Subpart KKK is revised to read as set forth above.

0
4. Section 60.630 is amended by revising paragraph (b) to read as 
follows:


Sec.  60.630  Applicability and designation of affected facility.

* * * * *
    (b) Any affected facility under paragraph (a) of this section that 
commences construction, reconstruction, or modification after January 
20, 1984, and on or before August 23, 2011, is subject to the 
requirements of this subpart.
* * * * *

Subpart LLL--Standards of Performance for SO2 Emissions 
From Onshore Natural Gas Processing for Which Construction, 
Reconstruction, or Modification Commenced After January 20, 1984, 
and on or Before August 23, 2011

0
5. The heading for Subpart LLL is revised to read as set forth above.

0
6. Section 60.640 is amended by revising paragraph (d) to read as 
follows:


Sec.  60.640  Applicability and designation of affected facilities.

* * * * *
    (d) The provisions of this subpart apply to each affected facility 
identified in paragraph (a) of this section which commences 
construction or modification after January 20, 1984, and on or before 
August 23, 2011.
* * * * *

0
7. Add subpart OOOO, consisting of 60.5360 through 60.5430, to part 60 
to read as follows:
Subpart OOOO--Standards of Performance for Crude Oil and Natural Gas 
Production, Transmission and Distribution
Sec.
60.5360 What is the purpose of this subpart?
60.5365 Am I subject to this subpart?
60.5370 When must I comply with this subpart?
60.5375 What standards apply to gas well affected facilities?
60.5380 What standards apply to centrifugal compressor affected 
facilities?
60.5385 What standards apply to reciprocating compressor affected 
facilities?
60.5390 What standards apply to pneumatic controller affected 
facilities?
60.5395 What standards apply to storage vessel affected facilities?
60.5400 What equipment leak standards apply to affected facilities 
at an onshore natural gas processing plant?
60.5401 What are the exceptions to the equipment leak standards for 
affected facilities at onshore natural gas processing plants?
60.5402 What are the alternative emission limitations for equipment 
leaks from onshore natural gas processing plants?
60.5405 What standards apply to sweetening units at onshore natural 
gas processing plants?
60.5406 What test methods and procedures must I use for my 
sweetening units affected facilities at onshore natural gas 
processing plants?
60.5407 What are the requirements for monitoring of emissions and 
operations from my sweetening unit affected facilities at onshore 
natural gas processing plants?
60.5408 What is an optional procedure for measuring hydrogen sulfide 
in acid gas--Tutwiler Procedure?
60.5410 How do I demonstrate initial compliance with the standards 
for my gas well affected facility, my centrifugal compressor 
affected facility, my reciprocating compressor affected facility, my 
pneumatic controller affected facility, my storage vessel affected 
facility, and my equipment leaks and sweetening unit affected 
facilities at onshore natural gas processing plants?
60.5411 What additional requirements must I meet to determine 
initial compliance for my closed vent systems routing emissions from 
storage vessels or centrifugal compressor wet seal fluid degassing 
systems?
60.5412 What additional requirements must I meet for determining 
initial compliance with control devices used to comply with the 
emission standards for my storage vessel or centrifugal compressor 
affected facility?
60.5413 What are the performance testing procedures for control 
devices used to demonstrate compliance at my storage vessel or 
centrifugal compressor affected facility?
60.5415 How do I demonstrate continuous compliance with the 
standards for my gas well affected facility, my centrifugal 
compressor affected facility, my stationary reciprocating compressor 
affected facility, my pneumatic controller affected facility, my 
storage vessel affected facility, and my affected facilities at 
onshore natural gas processing plants?
60.5416 What are the initial and continuous cover and closed vent 
system inspection and monitoring requirements for my storage vessel 
or centrifugal compressor affected facility?
60.5417 What are the continuous control device monitoring 
requirements for my storage vessel or centrifugal compressor 
affected facility?
60.5420 What are my notification, reporting, and recordkeeping 
requirements?
60.5421 What are my additional recordkeeping requirements for my 
affected facility subject to VOC requirements for onshore natural 
gas processing plants?
60.5422 What are my additional reporting requirements for my 
affected facility subject to VOC requirements for onshore natural 
gas processing plants?
60.5423 What additional recordkeeping and reporting requirements 
apply to my sweetening unit affected facilities at onshore natural 
gas processing plants?
60.5425 What parts of the General Provisions apply to me?
60.5430 What definitions apply to this subpart?
Table 1 to Subpart OOOO of Part 60--Required Minimum Initial 
SO2 Emission Reduction Efficiency (Zi)
Table 2 to Subpart OOOO of Part 60--Required Minimum SO2 
Emission Reduction Efficiency (Zc)
Table 3 to Subpart OOOO of Part 60--Applicability of General 
Provisions to Subpart OOOO

Subpart OOOO--Standards of Performance for Crude Oil and Natural 
Gas Production, Transmission and Distribution


Sec.  60.5360  What is the purpose of this subpart?

    This subpart establishes emission standards and compliance 
schedules for the control of volatile organic compounds (VOC) and 
sulfur dioxide (SO2) emissions from affected facilities that 
commence construction, modification or reconstruction after August 23, 
2011.

[[Page 49543]]

Sec.  60.5365  Am I subject to this subpart?

    You are subject to the applicable provisions of this subpart if you 
are the owner or operator of one or more of the onshore affected 
facilities listed in paragraphs (a) through (g) of this section for 
which you commence construction, modification or reconstruction after 
August 23, 2011.
    (a) Each gas well affected facility, which is a single natural gas 
well.
    (b) Each centrifugal compressor affected facility, which is a 
single centrifugal compressor using wet seals that is located between 
the wellhead and the point of custody transfer to the natural gas 
transmission and storage segment. A centrifugal compressor located at a 
well site, or an adjacent well site and servicing more than one well 
site, is not an affected facility under this subpart.
    (c) Each reciprocating compressor affected facility, which is a 
single reciprocating compressor located between the wellhead and the 
point of custody transfer to the natural gas transmission and storage 
segment. A reciprocating compressor located at a well site, or an 
adjacent well site and servicing more than one well site, is not an 
affected facility under this subpart.
    (d)(1) For the oil production segment (between the wellhead and the 
point of custody transfer to an oil pipeline), each pneumatic 
controller affected facility, which is a single continuous bleed 
natural gas-driven pneumatic controller operating at a natural gas 
bleed rate greater than 6 scfh.
    (2) For the natural gas production segment (between the wellhead 
and the point of custody transfer to the natural gas transmission and 
storage segment and not including natural gas processing plants), each 
pneumatic controller affected facility, which is a single continuous 
bleed natural gas-driven pneumatic controller operating at a natural 
gas bleed rate greater than 6 scfh.
    (3) For natural gas processing plants, each pneumatic controller 
affected facility, which is a single continuous bleed natural gas-
driven pneumatic controller.
    (e) Each storage vessel affected facility, which is a single 
storage vessel, located in the oil and natural gas production segment, 
natural gas processing segment or natural gas transmission and storage 
segment.
    (f) The group of all equipment, except compressors, within a 
process unit is an affected facility.
    (1) Addition or replacement of equipment for the purpose of process 
improvement that is accomplished without a capital expenditure shall 
not by itself be considered a modification under this subpart.
    (2) Equipment associated with a compressor station, dehydration 
unit, sweetening unit, underground storage vessel, field gas gathering 
system, or liquefied natural gas unit is covered by Sec. Sec.  60.5400, 
60.5401, 60.5402, 60.5421, and 60.5422 of this subpart if it is located 
at an onshore natural gas processing plant. Equipment not located at 
the onshore natural gas processing plant site is exempt from the 
provisions of Sec. Sec.  60.5400, 60.5401, 60.5402, 60.5421, and 
60.5422 of this subpart.
    (3) The equipment within a process unit of an affected facility 
located at onshore natural gas processing plants and described in 
paragraph (f) of this section are exempt from this subpart if they are 
subject to and controlled according to subparts VVa, GGG or GGGa of 
this part.
    (g) Sweetening units located at onshore natural gas processing 
plants that process natural gas produced from either onshore or 
offshore wells.
    (1) Each sweetening unit that processes natural gas is an affected 
facility; and
    (2) Each sweetening unit that processes natural gas followed by a 
sulfur recovery unit is an affected facility.
    (3) Facilities that have a design capacity less than 2 long tons 
per day (LT/D) of hydrogen sulfide (H2S) in the acid gas 
(expressed as sulfur) are required to comply with recordkeeping and 
reporting requirements specified in Sec.  60.5423(c) but are not 
required to comply with Sec. Sec.  60.5405 through 60.5407 and 
Sec. Sec.  60.5410(g) and 60.5415(g) of this subpart.
    (4) Sweetening facilities producing acid gas that is completely 
reinjected into oil-or-gas-bearing geologic strata or that is otherwise 
not released to the atmosphere are not subject to Sec. Sec.  60.5405 
through 60.5407, 60.5410(g), 60.5415(g), and 60.5423 of this subpart.
    (h) The following provisions apply to gas well facilities that are 
hydraulically refractured.
    (1) A gas well facility that conducts a well completion operation 
following hydraulic refracturing is not an affected facility, provided 
that the requirements of Sec.  60.5375 are met. For purposes of this 
provision, the dates specified in Sec.  60.5375(a) do not apply, and 
such facilities, as of October 15, 2012, must meet the requirements of 
Sec.  60.5375(a)(1) through (4).
    (2) A well completion operation following hydraulic refracturing at 
a gas well facility not conducted pursuant to Sec.  60.5375 is a 
modification to the gas well affected facility.
    (3) Refracturing of a gas well facility does not affect the 
modification status of other equipment, process units, storage vessels, 
compressors, or pneumatic controllers located at the well site.
    (4) Sources initially constructed after August 23, 2011, are 
considered affected sources regardless of this provision.


Sec.  60.5370  When must I comply with this subpart?

    (a) You must be in compliance with the standards of this subpart no 
later than October 15, 2012 or upon startup, whichever is later.
    (b) The provisions for exemption from compliance during periods of 
startup, shutdown and malfunctions provided for in 40 CFR 60.8(c) do 
not apply to this subpart.
    (c) You are exempt from the obligation to obtain a permit under 40 
CFR part 70 or 40 CFR part 71, provided you are not otherwise required 
by law to obtain a permit under 40 CFR 70.3(a) or 40 CFR 71.3(a). 
Notwithstanding the previous sentence, you must continue to comply with 
the provisions of this subpart.


Sec.  60.5375  What standards apply to gas well affected facilities?

    If you are the owner or operator of a gas well affected facility, 
you must comply with paragraphs (a) through (f) of this section.
    (a) Except as provided in paragraph (f) of this section, for each 
well completion operation with hydraulic fracturing begun prior to 
January 1, 2015, you must comply with the requirements of paragraphs 
(a)(3) and (4) of this section unless a more stringent state or local 
emission control requirement is applicable; optionally, you may comply 
with the requirements of paragraphs (a)(1) through (4) of this section. 
For each new well completion operation with hydraulic fracturing begun 
on or after January 1, 2015, you must comply with the requirements in 
paragraphs (a)(1) through (4) of this section.
    (1) For the duration of flowback, route the recovered liquids into 
one or more storage vessels or re-inject the recovered liquids into the 
well or another well, and route the recovered gas into a gas flow line 
or collection system, re-inject the recovered gas into the well or 
another well, use the recovered gas as an on-site fuel source, or use 
the recovered gas for another useful purpose that a purchased fuel or 
raw material would serve, with no direct release to the atmosphere. If 
this is infeasible, follow the requirements in paragraph (a)(3) of this 
section.
    (2) All salable quality gas must be routed to the gas flow line as 
soon as

[[Page 49544]]

practicable. In cases where flowback emissions cannot be directed to 
the flow line, you must follow the requirements in paragraph (a)(3) of 
this section.
    (3) You must capture and direct flowback emissions to a completion 
combustion device, except in conditions that may result in a fire 
hazard or explosion, or where high heat emissions from a completion 
combustion device may negatively impact tundra, permafrost or 
waterways. Completion combustion devices must be equipped with a 
reliable continuous ignition source over the duration of flowback.
    (4) You have a general duty to safely maximize resource recovery 
and minimize releases to the atmosphere during flowback and subsequent 
recovery.
    (b) You must maintain a log for each well completion operation at 
each gas well affected facility. The log must be completed on a daily 
basis for the duration of the well completion operation and must 
contain the records specified in Sec.  60.5420(c)(1)(iii).
    (c) You must demonstrate initial compliance with the standards that 
apply to gas well affected facilities as required by Sec.  60.5410.
    (d) You must demonstrate continuous compliance with the standards 
that apply to gas well affected facilities as required by Sec.  
60.5415.
    (e) You must perform the required notification, recordkeeping and 
reporting as required by Sec.  60.5420.
    (f)(1) For each gas well affected facility specified in paragraphs 
(f)(1)(i) and (ii) of this section, you must comply with the 
requirements of paragraphs (f)(2) and (3) of this section.
    (i) Each well completion operation with hydraulic fracturing at a 
gas well affected facility meeting the criteria for a wildcat or 
delineation well.
    (ii) Each well completion operation with hydraulic fracturing at a 
gas well affected facility meeting the criteria for a non-wildcat low 
pressure gas well or non-delineation low pressure gas well.
    (2) You must capture and direct flowback emissions to a completion 
combustion device, except in conditions that may result in a fire 
hazard or explosion, or where high heat emissions from a completion 
combustion device may negatively impact tundra, permafrost or 
waterways. Completion combustion devices must be equipped with a 
reliable continuous ignition source over the duration of flowback. You 
must also comply with paragraphs (a)(4) and (b) through (e) of this 
section.
    (3) You must maintain records specified in Sec.  60.5420(c)(1)(iii) 
for wildcat, delineation and low pressure gas wells.


Sec.  60.5380  What standards apply to centrifugal compressor affected 
facilities?

    You must comply with the standards in paragraphs (a) through (d) of 
this section for each centrifugal compressor affected facility.
    (a)(1) You must reduce VOC emissions from each centrifugal 
compressor wet seal fluid degassing system by 95.0 percent or greater.
    (2) If you use a control device to reduce emissions, you must equip 
the wet seal fluid degassing system with a cover that meets the 
requirements of Sec.  60.5411(b) and is connected through a closed vent 
system that meets the requirements of Sec.  60.5411(a) to a control 
device that meets the conditions specified in Sec.  60.5412.
    (b) You must demonstrate initial compliance with the standards that 
apply to centrifugal compressor affected facilities as required by 
Sec.  60.5410.
    (c) You must demonstrate continuous compliance with the standards 
that apply to centrifugal compressor affected facilities as required by 
Sec.  60.5415.
    (d) You must perform the required notification, recordkeeping, and 
reporting as required by Sec.  60.5420.


Sec.  60.5385  What standards apply to reciprocating compressor 
affected facilities?

    You must comply with the standards in paragraphs (a) through (d) of 
this section for each reciprocating compressor affected facility.
    (a) You must replace the reciprocating compressor rod packing 
according to either paragraph (a)(1) or (2) of this section.
    (1) Before the compressor has operated for 26,000 hours. The number 
of hours of operation must be continuously monitored beginning upon 
initial startup of your reciprocating compressor affected facility, or 
October 15, 2012, or the date of the most recent reciprocating 
compressor rod packing replacement, whichever is later.
    (2) Prior to 36 months from the date of the most recent rod packing 
replacement, or 36 months from the date of startup for a new 
reciprocating compressor for which the rod packing has not yet been 
replaced.
    (b) You must demonstrate initial compliance with standards that 
apply to reciprocating compressor affected facilities as required by 
Sec.  60.5410.
    (c) You must demonstrate continuous compliance with standards that 
apply to reciprocating compressor affected facilities as required by 
Sec.  60.5415.
    (d) You must perform the required notification, recordkeeping, and 
reporting as required by Sec.  60.5420.


Sec.  60.5390  What standards apply to pneumatic controller affected 
facilities?

    For each pneumatic controller affected facility you must comply 
with the VOC standards, based on natural gas as a surrogate for VOC, in 
either paragraph (b) or (c) of this section, as applicable. Pneumatic 
controllers meeting the conditions in paragraph (a) of this section are 
exempt from this requirement.
    (a) The requirements of paragraph (b) or (c) of this section are 
not required if you determine that the use of a pneumatic controller 
affected facility with a bleed rate greater than 6 standard cubic feet 
per hour is required based on functional needs, including but not 
limited to response time, safety and positive actuation.
    (b)(1) Each pneumatic controller affected facility at a natural gas 
processing plant must have a bleed rate of zero.
    (2) Each pneumatic controller affected facility at a natural gas 
processing plant must be tagged with the month and year of 
installation, reconstruction or modification, and identification 
information that allows traceability to the records for that pneumatic 
controller as required in Sec.  60.5420(c)(4)(iv).
    (c)(1) Each pneumatic controller affected facility constructed, 
modified or reconstructed on or after October 15, 2013 at a location 
between the wellhead and a natural gas processing plant must have a 
bleed rate less than or equal to 6 standard cubic feet per hour.
    (2) Each pneumatic controller affected facility at a location 
between the wellhead and a natural gas processing plant must be tagged 
with the month and year of installation, reconstruction or 
modification, and identification information that allows traceability 
to the records for that controller as required in Sec.  
60.5420(c)(4)(iii).
    (d) You must demonstrate initial compliance with standards that 
apply to pneumatic controller affected facilities as required by Sec.  
60.5410.
    (e) You must demonstrate continuous compliance with standards that 
apply to pneumatic controller affected facilities as required by Sec.  
60.5415.
    (f) You must perform the required notification, recordkeeping, and 
reporting as required by Sec.  60.5420, except that you are not 
required to submit the notifications specified in Sec.  60.5420(a).


Sec.  60.5395  What standards apply to storage vessel affected 
facilities?

    Except as provided in paragraph (d) of this section, you must 
comply with the standards in this section no later than October 15, 
2013 for each storage vessel

[[Page 49545]]

affected facility constructed, modified or reconstructed after August 
23, 2011, with VOC emissions equal to or greater than 6 tpy, as 
determined in paragraph (a) of this section.
    (a) Emissions determination--(1) Well sites with no other wells in 
production. For each storage vessel constructed, modified or 
reconstructed at a well site with no other wells in production, you 
must determine the VOC emission rate for each storage vessel affected 
facility using any generally accepted model or calculation methodology 
within 30 days after startup, and minimize emissions to the extent 
practicable during the 30-day period using good engineering practices. 
For each storage vessel affected facility emitting more than 6 tpy VOC, 
you must reduce VOC emissions by 95.0 percent or greater within 60 days 
after startup.
    (2) Well sites with one or more wells already in production. For 
each storage vessel constructed, modified or reconstructed at a well 
site with one or more wells already in production, you must determine 
the VOC emission rate for each storage vessel affected facility using 
any generally accepted model or calculation methodology upon startup. 
For each storage vessel affected facility emitting more than 6 tpy VOC, 
you must reduce VOC emissions by 95.0 percent or greater upon startup.
    (b) Control requirements. (1) If you use a control device (such as 
an enclosed combustion device or vapor recovery device) to reduce 
emissions, you must equip the storage vessel with a cover that meets 
the requirements of Sec.  60.5411(b) and is connected through a closed 
vent system that meets the requirements of Sec.  60.5411(a) to a 
control device that meets the conditions specified in Sec.  60.5412.
    (2) If you use a floating roof to reduce emissions, you must meet 
the requirements of Sec.  60.112b(a)(1) or (2) and the relevant 
monitoring, inspection, recordkeeping, and reporting requirements in 40 
CFR part 60, subpart Kb.
    (c) Compliance, notification, recordkeeping, and reporting. (1) You 
must demonstrate initial compliance with standards that apply to 
storage vessel affected facilities as required by Sec.  60.5410.
    (2) You must demonstrate continuous compliance with standards that 
apply to storage vessel affected facilities as required by Sec.  
60.5415.
    (3) You must perform the required notification, recordkeeping, and 
reporting as required by Sec.  60.5420.
    (d) Exemptions. This section does not apply to storage vessels 
subject to and controlled in accordance with the requirements for 
storage vessels in 40 CFR part 60, subpart Kb, or 40 CFR part 63, 
subparts G, CC, HH, WW, or HHH.


Sec.  60.5400  What equipment leak standards apply to affected 
facilities at an onshore natural gas processing plant?

    This section applies to the group of all equipment, except 
compressors, within a process unit.
    (a) You must comply with the requirements of Sec. Sec.  60.482-
1a(a), (b), and (d), 60.482-2a, and 60.482-4a through 60.482-11a, 
except as provided in Sec.  60.5401.
    (b) You may elect to comply with the requirements of Sec. Sec.  
60.483-1a and 60.483-2a, as an alternative.
    (c) You may apply to the Administrator for permission to use an 
alternative means of emission limitation that achieves a reduction in 
emissions of VOC at least equivalent to that achieved by the controls 
required in this subpart according to the requirements of Sec.  60.5402 
of this subpart.
    (d) You must comply with the provisions of Sec.  60.485a of this 
part except as provided in paragraph (f) of this section.
    (e) You must comply with the provisions of Sec. Sec.  60.486a and 
60.487a of this part except as provided in Sec. Sec.  60.5401, 60.5421, 
and 60.5422 of this part.
    (f) You must use the following provision instead of Sec.  
60.485a(d)(1): Each piece of equipment is presumed to be in VOC service 
or in wet gas service unless an owner or operator demonstrates that the 
piece of equipment is not in VOC service or in wet gas service. For a 
piece of equipment to be considered not in VOC service, it must be 
determined that the VOC content can be reasonably expected never to 
exceed 10.0 percent by weight. For a piece of equipment to be 
considered in wet gas service, it must be determined that it contains 
or contacts the field gas before the extraction step in the process. 
For purposes of determining the percent VOC content of the process 
fluid that is contained in or contacts a piece of equipment, procedures 
that conform to the methods described in ASTM E169-93, E168-92, or 
E260-96 (incorporated by reference as specified in Sec.  60.17) must be 
used.


Sec.  60.5401  What are the exceptions to the equipment leak standards 
for affected facilities at onshore natural gas processing plants?

    (a) You may comply with the following exceptions to the provisions 
of Sec.  60.5400(a) and (b).
    (b)(1) Each pressure relief device in gas/vapor service may be 
monitored quarterly and within 5 days after each pressure release to 
detect leaks by the methods specified in Sec.  60.485a(b) except as 
provided in Sec.  60.5400(c) and in paragraph (b)(4) of this section, 
and Sec.  60.482-4a(a) through (c) of subpart VVa.
    (2) If an instrument reading of 500 ppm or greater is measured, a 
leak is detected.
    (3)(i) When a leak is detected, it must be repaired as soon as 
practicable, but no later than 15 calendar days after it is detected, 
except as provided in Sec.  60.482-9a.
    (ii) A first attempt at repair must be made no later than 5 
calendar days after each leak is detected.
    (4)(i) Any pressure relief device that is located in a 
nonfractionating plant that is monitored only by non-plant personnel 
may be monitored after a pressure release the next time the monitoring 
personnel are on-site, instead of within 5 days as specified in 
paragraph (b)(1) of this section and Sec.  60.482-4a(b)(1) of subpart 
VVa.
    (ii) No pressure relief device described in paragraph (b)(4)(i) of 
this section must be allowed to operate for more than 30 days after a 
pressure release without monitoring.
    (c) Sampling connection systems are exempt from the requirements of 
Sec.  60.482-5a.
    (d) Pumps in light liquid service, valves in gas/vapor and light 
liquid service, and pressure relief devices in gas/vapor service that 
are located at a nonfractionating plant that does not have the design 
capacity to process 283,200 standard cubic meters per day (scmd) (10 
million standard cubic feet per day) or more of field gas are exempt 
from the routine monitoring requirements of Sec. Sec.  60.482-2a(a)(1) 
and 60.482-7a(a), and paragraph (b)(1) of this section.
    (e) Pumps in light liquid service, valves in gas/vapor and light 
liquid service, and pressure relief devices in gas/vapor service within 
a process unit that is located in the Alaskan North Slope are exempt 
from the routine monitoring requirements of Sec. Sec.  60.482-2a(a)(1), 
60.482-7a(a), and paragraph (b)(1) of this section.
    (f) An owner or operator may use the following provisions instead 
of Sec.  60.485a(e):
    (1) Equipment is in heavy liquid service if the weight percent 
evaporated is 10 percent or less at 150 [deg]C (302 [deg]F) as 
determined by ASTM Method D86-96 (incorporated by reference as 
specified in Sec.  60.17).
    (2) Equipment is in light liquid service if the weight percent 
evaporated is greater than 10 percent at 150 [deg]C (302 [deg]F) as 
determined by ASTM Method

[[Page 49546]]

D86-96 (incorporated by reference as specified in Sec.  60.17).
    (g) An owner or operator may use the following provisions instead 
of Sec.  60.485a(b)(2): A calibration drift assessment shall be 
performed, at a minimum, at the end of each monitoring day. Check the 
instrument using the same calibration gas(es) that were used to 
calibrate the instrument before use. Follow the procedures specified in 
Method 21 of appendix A-7 of this part, Section 10.1, except do not 
adjust the meter readout to correspond to the calibration gas value. 
Record the instrument reading for each scale used as specified in Sec.  
60.486a(e)(8). Divide these readings by the initial calibration values 
for each scale and multiply by 100 to express the calibration drift as 
a percentage. If any calibration drift assessment shows a negative 
drift of more than 10 percent from the initial calibration value, then 
all equipment monitored since the last calibration with instrument 
readings below the appropriate leak definition and above the leak 
definition multiplied by (100 minus the percent of negative drift/
divided by 100) must be re-monitored. If any calibration drift 
assessment shows a positive drift of more than 10 percent from the 
initial calibration value, then, at the owner/operator's discretion, 
all equipment since the last calibration with instrument readings above 
the appropriate leak definition and below the leak definition 
multiplied by (100 plus the percent of positive drift/divided by 100) 
may be re-monitored.


Sec.  60.5402  What are the alternative emission limitations for 
equipment leaks from onshore natural gas processing plants?

    (a) If, in the Administrator's judgment, an alternative means of 
emission limitation will achieve a reduction in VOC emissions at least 
equivalent to the reduction in VOC emissions achieved under any design, 
equipment, work practice or operational standard, the Administrator 
will publish, in the Federal Register, a notice permitting the use of 
that alternative means for the purpose of compliance with that 
standard. The notice may condition permission on requirements related 
to the operation and maintenance of the alternative means.
    (b) Any notice under paragraph (a) of this section must be 
published only after notice and an opportunity for a public hearing.
    (c) The Administrator will consider applications under this section 
from either owners or operators of affected facilities, or 
manufacturers of control equipment.
    (d) The Administrator will treat applications under this section 
according to the following criteria, except in cases where the 
Administrator concludes that other criteria are appropriate:
    (1) The applicant must collect, verify and submit test data, 
covering a period of at least 12 months, necessary to support the 
finding in paragraph (a) of this section.
    (2) If the applicant is an owner or operator of an affected 
facility, the applicant must commit in writing to operate and maintain 
the alternative means so as to achieve a reduction in VOC emissions at 
least equivalent to the reduction in VOC emissions achieved under the 
design, equipment, work practice or operational standard.


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

    (a) During the initial performance test required by Sec.  60.8(b), 
you must achieve at a minimum, an SO2 emission reduction 
efficiency (Zi) to be determined from Table 1 of this 
subpart based on the sulfur feed rate (X) and the sulfur content of the 
acid gas (Y) of the affected facility.
    (b) After demonstrating compliance with the provisions of paragraph 
(a) of this section, you must achieve at a minimum, an SO2 
emission reduction efficiency (Zc) to be determined from 
Table 2 of this subpart based on the sulfur feed rate (X) and the 
sulfur content of the acid gas (Y) of the affected facility.


60.5406  What test methods and procedures must I use for my sweetening 
units affected facilities at onshore natural gas processing plants?

    (a) In conducting the performance tests required in Sec.  60.8, you 
must use the test methods in appendix A of this part or other methods 
and procedures as specified in this section, except as provided in 
paragraph Sec.  60.8(b).
    (b) During a performance test required by Sec.  60.8, you must 
determine the minimum required reduction efficiencies (Z) of 
SO2 emissions as required in Sec.  60.5405(a) and (b) as 
follows:
    (1) The average sulfur feed rate (X) must be computed as follows:
    [GRAPHIC] [TIFF OMITTED] TR16AU12.000
    
Where:
X = average sulfur feed rate, Mg/D (LT/D).
Qa = average volumetric flow rate of acid gas from 
sweetening unit, dscm/day (dscf/day).
Y = average H2S concentration in acid gas feed from 
sweetening unit, percent by volume, expressed as a decimal.
K = (32 kg S/kg-mole)/((24.04 dscm/kg-mole)(1000 kg S/Mg)).
 = 1.331 x 10-3Mg/dscm, for metric units.
 = (32 lb S/lb-mole)/((385.36 dscf/lb-mole)(2240 lb S/long ton)).
 = 3.707 x 10-5 long ton/dscf, for English units.

    (2) You must use the continuous readings from the process flowmeter 
to determine the average volumetric flow rate (Qa) in dscm/
day (dscf/day) of the acid gas from the sweetening unit for each run.
    (3) You must use the Tutwiler procedure in Sec.  60.5408 or a 
chromatographic procedure following ASTM E260-96 (incorporated by 
reference as specified in Sec.  60.17) to determine the H2S 
concentration in the acid gas feed from the sweetening unit (Y). At 
least one sample per hour (at equally spaced intervals) must be taken 
during each 4-hour run. The arithmetic mean of all samples must be the 
average H2S concentration (Y) on a dry basis for the run. By 
multiplying the result from the Tutwiler procedure by 1.62 x 
10-3, the units gr/100 scf are converted to volume percent.
    (4) Using the information from paragraphs (b)(1) and (b)(3) of this 
section, Tables 1 and 2 of this subpart must be used to determine the 
required initial (Zi) and continuous (Zc) 
reduction efficiencies of SO2 emissions.
    (c) You must determine compliance with the SO2 standards 
in Sec.  60.5405(a) or (b) as follows:
    (1) You must compute the emission reduction efficiency (R) achieved 
by the sulfur recovery technology for each run using the following 
equation:
[GRAPHIC] [TIFF OMITTED] TR16AU12.001

    (2) You must use the level indicators or manual soundings to 
measure the liquid sulfur accumulation rate in the product storage 
vessels. You must use readings taken at the beginning and end of each 
run, the tank geometry, sulfur density at the storage temperature, and 
sample duration to determine the sulfur production rate (S) in kg/hr 
(lb/hr) for each run.
    (3) You must compute the emission rate of sulfur for each run as 
follows:
[GRAPHIC] [TIFF OMITTED] TR16AU12.002

Where:
E = emission rate of sulfur per run, kg/hr.
Ce = concentration of sulfur equivalent (SO\2+\ reduced 
sulfur), g/dscm (lb/dscf).
Qsd = volumetric flow rate of effluent gas, dscm/hr 
(dscf/hr).

[[Page 49547]]

K1 = conversion factor, 1000 g/kg (7000 gr/lb).

    (4) The concentration (Ce) of sulfur equivalent must be 
the sum of the SO2 and TRS concentrations, after being 
converted to sulfur equivalents. For each run and each of the test 
methods specified in this paragraph (c) of this section, you must use a 
sampling time of at least 4 hours. You must use Method 1 of appendix A 
to part 60 of this chapter to select the sampling site. The sampling 
point in the duct must be at the centroid of the cross-section if the 
area is less than 5 m\2\ (54 ft\2\) or at a point no closer to the 
walls than 1 m (39 in) if the cross-sectional area is 5 m\2\ or more, 
and the centroid is more than 1 m (39 in.) from the wall.
    (i) You must use Method 6 of appendix A to part 60 of this chapter 
to determine the SO2 concentration. You must take eight 
samples of 20 minutes each at 30-minute intervals. The arithmetic 
average must be the concentration for the run. The concentration must 
be multiplied by 0.5 x 10-3 to convert the results to sulfur 
equivalent.
    (ii) You must use Method 15 of appendix A to part 60 of this 
chapter to determine the TRS concentration from reduction-type devices 
or where the oxygen content of the effluent gas is less than 1.0 
percent by volume. The sampling rate must be at least 3 liters/min (0.1 
ft\3\/min) to insure minimum residence time in the sample line. You 
must take sixteen samples at 15-minute intervals. The arithmetic 
average of all the samples must be the concentration for the run. The 
concentration in ppm reduced sulfur as sulfur must be multiplied by 
1.333 x 10-3 to convert the results to sulfur equivalent.
    (iii) You must use Method 16A or Method 15 of appendix A to part 60 
of this chapter or ANSI/ASME PTC 19.10-1981, Part 10 (manual portion 
only) (incorporated by reference as specified in Sec.  60.17) to 
determine the reduced sulfur concentration from oxidation-type devices 
or where the oxygen content of the effluent gas is greater than 1.0 
percent by volume. You must take eight samples of 20 minutes each at 
30-minute intervals. The arithmetic average must be the concentration 
for the run. The concentration in ppm reduced sulfur as sulfur must be 
multiplied by 1.333 x 10-3 to convert the results to sulfur 
equivalent.
    (iv) You must use Method 2 of appendix A to part 60 of this chapter 
to determine the volumetric flow rate of the effluent gas. A velocity 
traverse must be conducted at the beginning and end of each run. The 
arithmetic average of the two measurements must be used to calculate 
the volumetric flow rate (Qsd) for the run. For the 
determination of the effluent gas molecular weight, a single integrated 
sample over the 4-hour period may be taken and analyzed or grab samples 
at 1-hour intervals may be taken, analyzed, and averaged. For the 
moisture content, you must take two samples of at least 0.10 dscm (3.5 
dscf) and 10 minutes at the beginning of the 4-hour run and near the 
end of the time period. The arithmetic average of the two runs must be 
the moisture content for the run.


60.5407   What are the requirements for monitoring of emissions and 
operations from my sweetening unit affected facilities at onshore 
natural gas processing plants?

    (a) If your sweetening unit affected facility is located at an 
onshore natural gas processing plant and is subject to the provisions 
of Sec.  60.5405(a) or (b) you must install, calibrate, maintain, and 
operate monitoring devices or perform measurements to determine the 
following operations information on a daily basis:
    (1) The accumulation of sulfur product over each 24-hour period. 
The monitoring method may incorporate the use of an instrument to 
measure and record the liquid sulfur production rate, or may be a 
procedure for measuring and recording the sulfur liquid levels in the 
storage vessels with a level indicator or by manual soundings, with 
subsequent calculation of the sulfur production rate based on the tank 
geometry, stored sulfur density, and elapsed time between readings. The 
method must be designed to be accurate within 2 percent of 
the 24-hour sulfur accumulation.
    (2) The H2S concentration in the acid gas from the sweetening unit 
for each 24-hour period. At least one sample per 24-hour period must be 
collected and analyzed using the equation specified in Sec.  
60.5406(b)(1). The Administrator may require you to demonstrate that 
the H2S concentration obtained from one or more samples over 
a 24-hour period is within 20 percent of the average of 12 
samples collected at equally spaced intervals during the 24-hour 
period. In instances where the H2S concentration of a single 
sample is not within 20 percent of the average of the 12 
equally spaced samples, the Administrator may require a more frequent 
sampling schedule.
    (3) The average acid gas flow rate from the sweetening unit. You 
must install and operate a monitoring device to continuously measure 
the flow rate of acid gas. The monitoring device reading must be 
recorded at least once per hour during each 24-hour period. The average 
acid gas flow rate must be computed from the individual readings.
    (4) The sulfur feed rate (X). For each 24-hour period, you must 
compute X using the equation specified in Sec.  60.5406(b)(1).
    (5) The required sulfur dioxide emission reduction efficiency for 
the 24-hour period. You must use the sulfur feed rate and the 
H2S concentration in the acid gas for the 24-hour period, as 
applicable, to determine the required reduction efficiency in 
accordance with the provisions of Sec.  60.5405(b).
    (b) Where compliance is achieved through the use of an oxidation 
control system or a reduction control system followed by a continually 
operated incineration device, you must install, calibrate, maintain, 
and operate monitoring devices and continuous emission monitors as 
follows:
    (1) A continuous monitoring system to measure the total sulfur 
emission rate (E) of SO2 in the gases discharged to the atmosphere. The 
SO2 emission rate must be expressed in terms of equivalent 
sulfur mass flow rates (kg/hr (lb/hr)). The span of this monitoring 
system must be set so that the equivalent emission limit of Sec.  
60.5405(b) will be between 30 percent and 70 percent of the measurement 
range of the instrument system.
    (2) Except as provided in paragraph (b)(3) of this section: A 
monitoring device to measure the temperature of the gas leaving the 
combustion zone of the incinerator, if compliance with Sec.  60.5405(a) 
is achieved through the use of an oxidation control system or a 
reduction control system followed by a continually operated 
incineration device. The monitoring device must be certified by the 
manufacturer to be accurate to within 1 percent of the 
temperature being measured.
    (3) When performance tests are conducted under the provision of 
Sec.  60.8 to demonstrate compliance with the standards under Sec.  
60.5405, the temperature of the gas leaving the incinerator combustion 
zone must be determined using the monitoring device. If the volumetric 
ratio of sulfur dioxide to sulfur dioxide plus total reduced sulfur 
(expressed as SO2) in the gas leaving the incinerator is 
equal to or less than 0.98, then temperature monitoring may be used to 
demonstrate that sulfur dioxide emission monitoring is sufficient to 
determine total sulfur emissions. At all times during the operation of 
the facility, you must maintain the average temperature of the gas 
leaving the combustion zone of the incinerator at or above the 
appropriate level determined during the most recent

[[Page 49548]]

performance test to ensure the sulfur compound oxidation criteria are 
met. Operation at lower average temperatures may be considered by the 
Administrator to be unacceptable operation and maintenance of the 
affected facility. You may request that the minimum incinerator 
temperature be reestablished by conducting new performance tests under 
Sec.  60.8.
    (4) Upon promulgation of a performance specification of continuous 
monitoring systems for total reduced sulfur compounds at sulfur 
recovery plants, you may, as an alternative to paragraph (b)(2) of this 
section, install, calibrate, maintain, and operate a continuous 
emission monitoring system for total reduced sulfur compounds as 
required in paragraph (d) of this section in addition to a sulfur 
dioxide emission monitoring system. The sum of the equivalent sulfur 
mass emission rates from the two monitoring systems must be used to 
compute the total sulfur emission rate (E).
    (c) Where compliance is achieved through the use of a reduction 
control system not followed by a continually operated incineration 
device, you must install, calibrate, maintain, and operate a continuous 
monitoring system to measure the emission rate of reduced sulfur 
compounds as SO2 equivalent in the gases discharged to the 
atmosphere. The SO2 equivalent compound emission rate must 
be expressed in terms of equivalent sulfur mass flow rates (kg/hr (lb/
hr)). The span of this monitoring system must be set so that the 
equivalent emission limit of Sec.  60.5405(b) will be between 30 and 70 
percent of the measurement range of the system. This requirement 
becomes effective upon promulgation of a performance specification for 
continuous monitoring systems for total reduced sulfur compounds at 
sulfur recovery plants.
    (d) For those sources required to comply with paragraph (b) or (c) 
of this section, you must calculate the average sulfur emission 
reduction efficiency achieved (R) for each 24-hour clock interval. The 
24-hour interval may begin and end at any selected clock time, but must 
be consistent. You must compute the 24-hour average reduction 
efficiency (R) based on the 24-hour average sulfur production rate (S) 
and sulfur emission rate (E), using the equation in Sec.  
60.5406(c)(1).
    (1) You must use data obtained from the sulfur production rate 
monitoring device specified in paragraph (a) of this section to 
determine S.
    (2) You must use data obtained from the sulfur emission rate 
monitoring systems specified in paragraphs (b) or (c) of this section 
to calculate a 24-hour average for the sulfur emission rate (E). The 
monitoring system must provide at least one data point in each 
successive 15-minute interval. You must use at least two data points to 
calculate each 1-hour average. You must use a minimum of 18 1-hour 
averages to compute each 24-hour average.
    (e) In lieu of complying with paragraphs (b) or (c) of this 
section, those sources with a design capacity of less than 152 Mg/D 
(150 LT/D) of H2S expressed as sulfur may calculate the 
sulfur emission reduction efficiency achieved for each 24-hour period 
by:
[GRAPHIC] [TIFF OMITTED] TR16AU12.003

Where:
R = The sulfur dioxide removal efficiency achieved during the 24-
hour period, percent.
K2 = Conversion factor, 0.02400 Mg/D per kg/hr (0.01071 
LT/D per lb/hr).
S = The sulfur production rate during the 24-hour period, kg/hr (lb/
hr).
X = The sulfur feed rate in the acid gas, Mg/D (LT/D).

    (f) The monitoring devices required in paragraphs (b)(1), (b)(3) 
and (c) of this section must be calibrated at least annually according 
to the manufacturer's specifications, as required by Sec.  60.13(b).
    (g) The continuous emission monitoring systems required in 
paragraphs (b)(1), (b)(3), and (c) of this section must be subject to 
the emission monitoring requirements of Sec.  60.13 of the General 
Provisions. For conducting the continuous emission monitoring system 
performance evaluation required by Sec.  60.13(c), Performance 
Specification 2 of appendix B to part 60 of this chapter must apply, 
and Method 6 must be used for systems required by paragraph (b) of this 
section.


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

    The Tutwiler procedure may be found in the Gas Engineers Handbook, 
Fuel Gas Engineering practices, The Industrial Press, 93 Worth Street, 
New York, NY, 1966, First Edition, Second Printing, page 6/25 (Docket 
A-80-20-A, Entry II-I-67).
    (a) When an instantaneous sample is desired and H2S 
concentration is ten grains per 1000 cubic foot or more, a 100 ml 
Tutwiler burette is used. For concentrations less than ten grains, a 
500 ml Tutwiler burette and more dilute solutions are used. In 
principle, this method consists of titrating hydrogen sulfide in a gas 
sample directly with a standard solution of iodine.
    (b) Apparatus. (See Figure 1 of this subpart) A 100 or 500 ml 
capacity Tutwiler burette, with two-way glass stopcock at bottom and 
three-way stopcock at top which connect either with inlet tubulature or 
glass-stoppered cylinder, 10 ml capacity, graduated in 0.1 ml 
subdivision; rubber tubing connecting burette with leveling bottle.
    (c) Reagents. (1) Iodine stock solution, 0.1N. Weight 12.7 g 
iodine, and 20 to 25 g cp potassium iodide for each liter of solution. 
Dissolve KI in as little water as necessary; dissolve iodine in 
concentrated KI solution, make up to proper volume, and store in glass-
stoppered brown glass bottle.
    (2) Standard iodine solution, 1 ml=0.001771 g I. Transfer 33.7 ml 
of above 0.1N stock solution into a 250 ml volumetric flask; add water 
to mark and mix well. Then, for 100 ml sample of gas, 1 ml of standard 
iodine solution is equivalent to 100 grains H2S per cubic 
feet of gas.
    (3) Starch solution. Rub into a thin paste about one teaspoonful of 
wheat starch with a little water; pour into about a pint of boiling 
water; stir; let cool and decant off clear solution. Make fresh 
solution every few days.
    (d) Procedure. Fill leveling bulb with starch solution. Raise (L), 
open cock (G), open (F) to (A), and close (F) when solutions starts to 
run out of gas inlet. Close (G). Purge gas sampling line and connect 
with (A). Lower (L) and open (F) and (G). When liquid level is several 
ml past the 100 ml mark, close (G) and (F), and disconnect sampling 
tube. Open (G) and bring starch solution to 100 ml mark by raising (L); 
then close (G). Open (F) momentarily, to bring gas in burette to 
atmospheric pressure, and close (F). Open (G), bring liquid level down 
to 10 ml mark by lowering (L). Close (G), clamp rubber tubing near (E) 
and disconnect it from burette. Rinse graduated cylinder with a 
standard iodine solution (0.00171 g I per ml); fill cylinder and record 
reading. Introduce successive small amounts of iodine thru (F); shake 
well after each addition; continue until a faint permanent blue color 
is obtained. Record reading; subtract from previous reading, and call 
difference D.
    (e) With every fresh stock of starch solution perform a blank test 
as follows: Introduce fresh starch solution into burette up to 100 ml 
mark. Close (F) and (G). Lower (L) and open (G). When liquid level 
reaches the 10 ml mark, close (G). With air in burette, titrate as 
during a test and up to same end point. Call ml of iodine used C. Then, 
Grains H2S per 100 cubic foot of gas = 100(D-C)

[[Page 49549]]

    (f) Greater sensitivity can be attained if a 500 ml capacity 
Tutwiler burette is used with a more dilute (0.001N) iodine solution. 
Concentrations less than 1.0 grains per 100 cubic foot can be 
determined in this way. Usually, the starch-iodine end point is much 
less distinct, and a blank determination of end point, with 
H2S-free gas or air, is required.
BILLING CODE 6560-50-P
[GRAPHIC] [TIFF OMITTED] TR16AU12.004


[[Page 49550]]


BILLING CODE 6560-50-C


Sec.  60.5410  How do I demonstrate initial compliance with the 
standards for my gas well affected facility, my centrifugal compressor 
affected facility, my reciprocating compressor affected facility, my 
pneumatic controller affected facility, my storage vessel affected 
facility, and my equipment leaks and sweetening unit affected 
facilities at onshore natural gas processing plants?

    You must determine initial compliance with the standards for each 
affected facility using the requirements in paragraphs (a) through (g) 
of this section. The initial compliance period begins on October 15, 
2012 or upon initial startup, whichever is later, and ends no later 
than one year after the initial startup date for your affected facility 
or no later than one year after October 15, 2012. The initial 
compliance period may be less than one full year.
    (a) To achieve initial compliance with the standards for each well 
completion operation conducted at your gas well affected facility you 
must comply with paragraphs (a)(1) through (a)(4) of this section.
    (1) You must submit the notification required in Sec.  
60.5420(a)(2).
    (2) You must submit the initial annual report for your well 
affected facility as required in Sec.  60.5420(b).
    (3) You must maintain a log of records as specified in Sec.  
60.5420(c)(1) for each well completion operation conducted during the 
initial compliance period.
    (4) For each gas well affected facility subject to both Sec.  
60.5375(a)(1) and (3), you must maintain records of one or more digital 
photographs with the date the photograph was taken and the latitude and 
longitude of the well site imbedded within or stored with the digital 
file showing the equipment for storing or re-injecting recovered 
liquid, equipment for routing recovered gas to the gas flow line and 
the completion combustion device (if applicable) connected to and 
operating at each gas well completion operation that occurred during 
the initial compliance period. As an alternative to imbedded latitude 
and longitude within the digital photograph, the digital photograph may 
consist of a photograph of the equipment connected and operating at 
each well completion operation with a photograph of a separately 
operating GIS device within the same digital picture, provided the 
latitude and longitude output of the GIS unit can be clearly read in 
the digital photograph.
    (b)(1) To achieve initial compliance with standards for your 
centrifugal compressor affected facility you must reduce VOC emissions 
from each centrifugal compressor wet seal fluid degassing system by 
95.0 percent or greater as required by Sec.  60.5380 and as 
demonstrated by the requirements of Sec.  60.5413.
    (2) If you use a control device to reduce emissions, you must equip 
the wet seal fluid degassing system with a cover that meets the 
requirements of Sec.  60.5411(b) and is connected through a closed vent 
system that meets the requirements of Sec.  60.5411(a) to a control 
device that meets the conditions specified in Sec.  60.5412.
    (3) You must conduct an initial performance test as required in 
Sec.  60.5413 within 180 days after initial startup or by October 15, 
2012, whichever is later, and you must comply with the continuous 
compliance requirements in Sec.  60.5415(b).
    (4) You must conduct the initial inspections required in Sec.  
60.5416.
    (5) You must install and operate the continuous parameter 
monitoring systems in accordance with Sec.  60.5417.
    (6) You must submit the notifications required in 60.7(a)(1), (3), 
and (4).
    (7) You must submit the initial annual report for your centrifugal 
compressor affected facility as required in Sec.  60.5420(b) for each 
centrifugal compressor affected facility
    (8) You must maintain the records as specified in Sec.  
60.5420(c)(3).
    (c) To achieve initial compliance with the standards for each 
reciprocating compressor affected facility you must comply with 
paragraphs (c)(1) through (4) of this section.
    (1) During the initial compliance period, you must continuously 
monitor the number of hours of operation or track the number of months 
since the last rod packing replacement.
    (2) You must submit the notifications required in 60.7(a)(1), (3), 
and (4).
    (3) You must submit the initial annual report for your 
reciprocating compressor as required in Sec.  60.5420(b).
    (4) You must maintain the records as specified in Sec.  
60.5420(c)(3) for each reciprocating compressor affected facility.
    (d) To achieve initial compliance with emission standards for your 
pneumatic controller affected facility you comply with the requirements 
specified in paragraphs (d)(1) through (6) of this section.
    (1) If applicable, you have demonstrated by maintaining records as 
specified in Sec.  60.5420(c)(4)(ii) of your determination that the use 
of a pneumatic controller affected facility with a bleed rate greater 
than 6 standard cubic feet of gas per hour is required as specified in 
Sec.  60.5390(a).
    (2) You own or operate a pneumatic controller affected facility 
located at a natural gas processing plant and your pneumatic controller 
is driven other than by use of natural gas and therefore emits zero 
natural gas.
    (3) You own or operate a pneumatic controller affected facility 
located between the wellhead and a natural gas processing plant and the 
manufacturer's design specifications indicate that the controller emits 
less than or equal to 6 standard cubic feet of gas per hour.
    (4) You must tag each new pneumatic controller affected facility 
according to the requirements of Sec.  60.5390(b)(2).
    (5) You must include the information in paragraph (d)(1) of this 
section and a listing of the pneumatic controller affected facilities 
specified in paragraphs (d)(2) and (3) of this section in the initial 
annual report submitted for your pneumatic controller affected 
facilities constructed, modified or reconstructed during the period 
covered by the annual report according to the requirements of Sec.  
60.5420(b).
    (6) You must maintain the records as specified in Sec.  
60.5420(c)(4) for each pneumatic controller affected facility.
    (e) To achieve initial compliance with the emission standards for 
your storage vessel affected facility you must comply with paragraphs 
(e)(1) through (9) of this section.
    (1) You have determined the VOC emission rate within 30 days after 
startup for storage vessels constructed, modified or reconstructed at 
well sites with no other wells in production, and you must use good 
engineering practices to minimize emissions during the 30-day period.
    (2) You must determine the VOC emission rate upon startup for 
storage vessels constructed, modified or reconstructed at well sites 
with one or more wells already in production.
    (3) For storage vessel affected facilities emitting more than 6 tpy 
VOC, you must reduce VOC emissions by 95.0 percent or greater within 60 
days after startup for storage vessels constructed, modified or 
reconstructed at well sites with no other wells in production, or upon 
startup for storage vessels constructed, modified or reconstructed at 
well sites with one or more wells already in production.
    (4) If you use a control device to reduce emissions, you must equip 
the storage vessel with a cover that meets the requirements of Sec.  
60.5411(b) and is connected through a closed vent system that meets the 
requirements of Sec.  60.5411(a) to a control device that meets the 
conditions specified in Sec.  60.5412 within 60 days after startup for 
storage vessels constructed, modified

[[Page 49551]]

or reconstructed at well sites with no other wells in production, or 
upon startup for storage vessels constructed, modified or reconstructed 
at well sites with one or more wells already in production.
    (5) You must conduct an initial performance test as required in 
Sec.  60.5413 within 180 days after initial startup or within 180 days 
of October 15, 2013, whichever is later, and must conduct the 
compliance demonstration in Sec.  60.5415(b).
    (6) You must conduct the initial inspections required in Sec.  
60.5416.
    (7) You must install and operate continuous parameter monitoring 
systems in accordance with Sec.  60.5417.
    (8) You must submit the information in paragraphs (e)(1) through 
(7) of this section in the initial annual report as required in Sec.  
60.5420(b).
    (9) You must maintain the records as specified in Sec.  
60.5420(c)(5) for each storage vessel affected facility.
    (f) For affected facilities at onshore natural gas processing 
plants, initial compliance with the VOC requirements is demonstrated if 
you are in compliance with the requirements of Sec.  60.5400.
    (g) For sweetening unit affected facilities at onshore natural gas 
processing plants, initial compliance is demonstrated according to 
paragraphs (g)(1) through (3) of this section.
    (1) To determine compliance with the standards for SO2 
specified in Sec.  60.5405(a), during the initial performance test as 
required by Sec.  60.8, the minimum required sulfur dioxide emission 
reduction efficiency (Zi) is compared to the emission 
reduction efficiency (R) achieved by the sulfur recovery technology as 
specified in paragraphs (g)(1)(i) and (ii) of this section.
    (i) If R >= Zi, your affected facility is in compliance.
    (ii) If R < Zi, your affected facility is not in 
compliance.
    (2) The emission reduction efficiency (R) achieved by the sulfur 
reduction technology must be determined using the procedures in Sec.  
60.5406(c)(1).
    (3) You have submitted the results of paragraphs (g)(1) and (2) of 
this section in the initial annual report submitted for your sweetening 
unit affected facilities at onshore natural gas processing plants.


Sec.  60.5411  What additional requirements must I meet to determine 
initial compliance for my closed vent systems routing materials from 
storage vessels and centrifugal compressor wet seal degassing systems?

    You must meet the applicable requirements of this section for each 
cover and closed vent system used to comply with the emission standards 
for your storage vessel or centrifugal compressor affected facility.
    (a) Closed vent system requirements. (1) You must design the closed 
vent system to route all gases, vapors, and fumes emitted from the 
material in the storage vessel or wet seal fluid degassing system to a 
control device that meets the requirements specified in Sec.  60.5412.
    (2) You must design and operate the closed vent system with no 
detectable emissions as demonstrated by Sec.  60.5416(b).
    (3) You must meet the requirements specified in paragraphs 
(a)(3)(i) and (ii) of this section if the closed vent system contains 
one or more bypass devices that could be used to divert all or a 
portion of the gases, vapors, or fumes from entering the control 
device.
    (i) Except as provided in paragraph (a)(3)(ii) of this section, you 
must comply with either paragraph (a)(3)(i)(A) or (B) of this section 
for each bypass device.
    (A) You must properly install, calibrate, maintain, and operate a 
flow indicator at the inlet to the bypass device that could divert the 
stream away from the control device to the atmosphere that is capable 
of taking periodic readings as specified in Sec.  60.5416(a)(4) and 
sounds an alarm when the bypass device is open such that the stream is 
being, or could be, diverted away from the control device to the 
atmosphere.
    (B) You must secure the bypass device valve installed at the inlet 
to the bypass device in the non-diverting position using a car-seal or 
a lock-and-key type configuration.
    (ii) Low leg drains, high point bleeds, analyzer vents, open-ended 
valves or lines, and safety devices are not subject to the requirements 
of paragraph (a)(3)(i) of this section.
    (b) Cover requirements. (1) The cover and all openings on the cover 
(e.g., access hatches, sampling ports, and gauge wells) shall form a 
continuous barrier over the entire surface area of the liquid in the 
storage vessel or wet seal fluid degassing system.
    (2) Each cover opening shall be secured in a closed, sealed 
position (e.g., covered by a gasketed lid or cap) whenever material is 
in the unit on which the cover is installed except during those times 
when it is necessary to use an opening as follows:
    (i) To add material to, or remove material from the unit (this 
includes openings necessary to equalize or balance the internal 
pressure of the unit following changes in the level of the material in 
the unit);
    (ii) To inspect or sample the material in the unit;
    (iii) To inspect, maintain, repair, or replace equipment located 
inside the unit; or
    (iv) To vent liquids, gases, or fumes from the unit through a 
closed-vent system to a control device designed and operated in 
accordance with the requirements of paragraph (a) of this section.


Sec.  60.5412  What additional requirements must I meet for determining 
initial compliance with control devices used to comply with the 
emission standards for my storage vessel or centrifugal compressor 
affected facility?

    You must meet the applicable requirements of this section for each 
control device used to comply with the emission standards for your 
storage vessel or centrifugal compressor affected facility.
    (a) If you use a control device to meet the emission reduction 
standard in Sec.  60.5380(a)(1) for your centrifugal compressor or 
Sec.  60.5395(a)(1) or (2) for your storage vessel, you must use one of 
the control devices specified in paragraphs (a)(1) through (3) of this 
section. You must demonstrate that the control device achieves the 
performance requirements using the performance test methods and 
procedures specified in Sec.  60.5413.
    (1) You must design and operate an enclosed combustion device 
(e.g., thermal vapor incinerator, catalytic vapor incinerator, boiler, 
or process heater) in accordance with one of the performance 
requirements specified in paragraphs (a)(1)(i) through (iv) of this 
section.
    (i) You must reduce the mass content of VOC in the gases vented to 
the device by 95.0 percent by weight or greater as determined in 
accordance with the requirements of Sec.  60.5413.
    (ii) You must reduce the concentration of TOC in the exhaust gases 
at the outlet to the device to a level equal to or less than 20 parts 
per million by volume on a dry basis corrected to 3 percent oxygen as 
determined in accordance with the requirements of Sec.  60.5413.
    (iii) You must operate at a minimum temperature of 760 [deg]C for a 
control device that can demonstrate a uniform combustion zone 
temperature during the performance test conducted under Sec.  60.5413.
    (iv) If a boiler or process heater is used as the control device, 
then you must introduce the vent stream into the flame zone of the 
boiler or process heater.

[[Page 49552]]

    (2) You must design and operate a vapor recovery device (e.g., 
carbon adsorption system or condenser) or other non-destructive control 
device to reduce the mass content of VOC in the gases vented to the 
device by 95.0 percent by weight or greater as determined in accordance 
with the requirements of Sec.  60.5413. The vapor recovery device must 
meet the design analysis requirements of Sec.  60.5413(c).
    (3) You must design and operate a flare in accordance with the 
requirements of Sec.  60.5413.
    (b) You must operate each control device in accordance with the 
requirements specified in paragraphs (b)(1) and (2) of this section.
    (1) You must operate each control device used to comply with this 
subpart at all times when gases, vapors, and fumes are vented from the 
storage vessel affected facility, as required under Sec.  60.5395, or 
wet seal fluid degassing system affected facility, as required under 
Sec.  60.5380, through the closed vent system to the control device. 
You may vent more than one affected facility to a control device used 
to comply with this subpart.
    (2) For each control device monitored in accordance with the 
requirements of Sec.  60.5417, you must demonstrate compliance 
according to the requirements of Sec.  60.5415(e)(2), as applicable.
    (c) For each carbon adsorption system used as a control device to 
meet the requirements of paragraph (a)(2) of this section, you must 
manage the carbon in accordance with the requirements specified in 
paragraphs (c)(1) or (2) of this section.
    (1) Following the initial startup of the control device, you must 
replace all carbon in the control device with fresh carbon on a 
regular, predetermined time interval that is no longer than the carbon 
service life established according to Sec.  60.5413(c)(2) or (3) for 
the carbon adsorption system. You must maintain records identifying the 
schedule for replacement and records of each carbon replacement as 
required in Sec.  60.5420(c)(6).
    (2) You must either regenerate, reactivate, or burn the spent 
carbon removed from the carbon adsorption system in one of the units 
specified in paragraphs (c)(2)(i) through (vii) of this section.
    (i) Regenerate or reactivate the spent carbon in a thermal 
treatment unit for which you have been issued a final permit under 40 
CFR part 270 that implements the requirements of 40 CFR part 264, 
subpart X.
    (ii) Regenerate or reactivate the spent carbon in a thermal 
treatment unit equipped with and operating air emission controls in 
accordance with this section.
    (iii) Regenerate or reactivate the spent carbon in a thermal 
treatment unit equipped with and operating organic air emission 
controls in accordance with an emissions standard for VOC under another 
subpart in 40 CFR part 60 or this part.
    (iv) Burn the spent carbon in a hazardous waste incinerator for 
which the owner or operator has been issued a final permit under 40 CFR 
part 270 that implements the requirements of 40 CFR part 264, subpart 
O.
    (v) Burn the spent carbon in a hazardous waste incinerator which 
you have designed and operated in accordance with the requirements of 
40 CFR part 265, subpart O.
    (vi) Burn the spent carbon in a boiler or industrial furnace for 
which you have been issued a final permit under 40 CFR part 270 that 
implements the requirements of 40 CFR part 266, subpart H.
    (vii) Burn the spent carbon in a boiler or industrial furnace that 
you have designed and operated in accordance with the interim status 
requirements of 40 CFR part 266, subpart H.


Sec.  60.5413  What are the performance testing procedures for control 
devices used to demonstrate compliance at my storage vessel or 
centrifugal compressor affected facility?

    This section applies to the performance testing of control devices 
used to demonstrate compliance with the emissions standards for your 
storage vessel or centrifugal compressor affected facility. You must 
demonstrate that a control device achieves the performance requirements 
of Sec.  60.5412(a) using the performance test methods and procedures 
specified in paragraph (b) of this section. For condensers, you may use 
a design analysis as specified in paragraph (c) of this section in lieu 
of complying with paragraph (b) of this section.
    (a) Performance test exemptions. You are exempt from the 
requirements to conduct performance tests and design analyses if you 
use any of the control devices described in paragraphs (a)(1) through 
(7) of this section.
    (1) A flare that is designed and operated in accordance with Sec.  
60.18(b). You must conduct the compliance determination using Method 22 
at 40 CFR part 60, appendix A-7, to determine visible emissions.
    (2) A boiler or process heater with a design heat input capacity of 
44 megawatts or greater.
    (3) A boiler or process heater into which the vent stream is 
introduced with the primary fuel or is used as the primary fuel.
    (4) A boiler or process heater burning hazardous waste for which 
you have either been issued a final permit under 40 CFR part 270 and 
comply with the requirements of 40 CFR part 266, subpart H; or you have 
certified compliance with the interim status requirements of 40 CFR 
part 266, subpart H.
    (5) A hazardous waste incinerator for which you have been issued a 
final permit under 40 CFR part 270 and comply with the requirements of 
40 CFR part 264, subpart O; or you have certified compliance with the 
interim status requirements of 40 CFR part 265, subpart O.
    (6) A performance test is waived in accordance with Sec.  60.8(b).
    (7) A control device that can be demonstrated to meet the 
performance requirements of Sec.  60.5412(a) through a performance test 
conducted by the manufacturer, as specified in paragraph (d) of this 
section.
    (b) Test methods and procedures. You must use the test methods and 
procedures specified in paragraphs (b)(1) through (5) of this section, 
as applicable, for each performance test conducted to demonstrate that 
a control device meets the requirements of Sec.  60.5412(a). You must 
conduct the initial and periodic performance tests according to the 
schedule specified in paragraph (b)(5) of this section.
    (1) You must use Method 1 or 1A at 40 CFR part 60, appendix A-1, as 
appropriate, to select the sampling sites specified in paragraphs 
(b)(1)(i) and (ii) of this section. Any references to particulate 
mentioned in Methods 1 and 1A do not apply to this section.
    (i) Sampling sites must be located at the inlet of the first 
control device, and at the outlet of the final control device, to 
determine compliance with the control device percent reduction 
requirement specified in Sec.  60.5412(a)(1)(i) or (a)(2).
    (ii) The sampling site must be located at the outlet of the 
combustion device to determine compliance with the enclosed combustion 
device total TOC concentration limit specified in Sec.  
60.5412(a)(1)(ii).
    (2) You must determine the gas volumetric flowrate using Method 2, 
2A, 2C, or 2D at 40 CFR part 60, appendix A-2, as appropriate.
    (3) To determine compliance with the control device percent 
reduction performance requirement in Sec.  60.5412(a)(1)(i) or (a)(2), 
you must use Method 25A at 40 CFR part 60, appendix A-7. You must use 
the procedures in paragraphs (b)(3)(i)

[[Page 49553]]

through (iv) of this section to calculate percent reduction efficiency.
    (i) For each run, you must take either an integrated sample or a 
minimum of four grab samples per hour. If grab sampling is used, then 
the samples must be taken at approximately equal intervals in time, 
such as 15-minute intervals during the run.
    (ii) You must compute the mass rate of TOC (minus methane and 
ethane) using the equations and procedures specified in paragraphs 
(b)(3)(ii)(A) and (B) of this section.
    (A) You must use the following equations:
    [GRAPHIC] [TIFF OMITTED] TR16AU12.005
    

Where:
Ei, Eo = Mass rate of TOC (minus methane and 
ethane) at the inlet and outlet of the control device, respectively, 
dry basis, kilogram per hour.
K2 = Constant, 2.494 x 10-6 (parts per 
million) (gram-mole per standard cubic meter) (kilogram/gram) 
(minute/hour), where standard temperature (gram-mole per standard 
cubic meter) is 20 [deg]C.
Cij, Coj = Concentration of sample component j 
of the gas stream at the inlet and outlet of the control device, 
respectively, dry basis, parts per million by volume.
Mij, Moj = Molecular weight of sample 
component j of the gas stream at the inlet and outlet of the control 
device, respectively, gram/gram-mole.
Qi, Qo = Flowrate of gas stream at the inlet 
and outlet of the control device, respectively, dry standard cubic 
meter per minute.
n = Number of components in sample.

    (B) When calculating the TOC mass rate, you must sum all organic 
compounds (minus methane and ethane) measured by Method 25A at 40 CFR 
part 60, appendix A-7 using the equations in paragraph (b)(3)(ii)(A) of 
this section.
    (iii) You must calculate the percent reduction in TOC (minus 
methane and ethane) as follows:
[GRAPHIC] [TIFF OMITTED] TR16AU12.006


Where:
Rcd = Control efficiency of control device, percent.
Ei = Mass rate of TOC (minus methane and ethane) at the 
inlet to the control device as calculated under paragraph (b)(3)(ii) 
of this section, kilograms TOC per hour or kilograms HAP per hour.
Eo = Mass rate of TOC (minus methane and ethane) at the 
outlet of the control device, as calculated under paragraph 
(b)(3)(ii) of this section, kilograms TOC per hour per hour.

    (iv) If the vent stream entering a boiler or process heater with a 
design capacity less than 44 megawatts is introduced with the 
combustion air or as a secondary fuel, you must determine the weight-
percent reduction of total TOC (minus methane and ethane) across the 
device by comparing the TOC (minus methane and ethane) in all combusted 
vent streams and primary and secondary fuels with the TOC (minus 
methane and ethane) exiting the device, respectively.
    (4) You must use Method 25A at 40 CFR part 60, appendix A-7 to 
measure TOC (minus methane and ethane) to determine compliance with the 
enclosed combustion device total VOC concentration limit specified in 
Sec.  60.5412(a)(1)(ii). You must calculate parts per million by volume 
concentration and correct to 3 percent oxygen, using the procedures in 
paragraphs (b)(4)(i) through (iii) of this section.
    (i) For each run, you must take either an integrated sample or a 
minimum of four grab samples per hour. If grab sampling is used, then 
the samples must be taken at approximately equal intervals in time, 
such as 15-minute intervals during the run.
    (ii) You must calculate the TOC concentration for each run as 
follows:
[GRAPHIC] [TIFF OMITTED] TR16AU12.007


Where:
CTOC = Concentration of total organic compounds minus 
methane and ethane, dry basis, parts per million by volume.
Cji = Concentration of sample component j of sample i, 
dry basis, parts per million by volume.
n = Number of components in the sample.
x = Number of samples in the sample run.

    (iii) You must correct the TOC concentration to 3 percent oxygen as 
specified in paragraphs (b)(4)(iii)(A) and (B) of this section.
    (A) You must use the emission rate correction factor for excess 
air, integrated sampling and analysis procedures of Method 3A or 3B at 
40 CFR part 60, appendix A, ASTM D6522-00 (Reapproved 2005), or ANSI/
ASME PTC 19.10-1981, Part 10 (manual portion only) (incorporated by 
reference as specified in Sec.  60.17) to determine the oxygen 
concentration. The samples must be taken during the same time that the 
samples are taken for determining TOC concentration.
    (B) You must correct the TOC concentration for percent oxygen as 
follows:
[GRAPHIC] [TIFF OMITTED] TR16AU12.008


Where:
Cc = TOC concentration corrected to 3 percent oxygen, dry 
basis, parts per million by volume.
Cm = TOC concentration, dry basis, parts per million by 
volume.
%O2d = Concentration of oxygen, dry basis, percent by 
volume.

    (5) You must conduct performance tests according to the schedule 
specified in paragraphs (b)(5)(i) and (ii) of this section.
    (i) You must conduct an initial performance test within 180 days 
after initial startup for your affected facility. You must submit the 
performance test results as required in Sec.  60.5420(b)(7).
    (ii) You must conduct periodic performance tests for all control 
devices required to conduct initial performance tests except as 
specified in paragraphs (b)(5)(ii)(A) and (B) of this section. You must 
conduct the first periodic performance test no later than 60 months 
after the initial performance test required in paragraph (b)(5)(i) of 
this section. You must conduct subsequent periodic performance tests at 
intervals no longer than 60 months following the previous periodic 
performance test or whenever you desire to establish a new operating 
limit. You must submit the periodic performance test results as 
specified in Sec.  60.5420(b)(7). Combustion control devices meeting 
the criteria in either paragraph (b)(5)(ii)(A) or (B) of this section 
are not required to conduct periodic performance tests.
    (A) A control device whose model is tested under, and meets the 
criteria of paragraph (d) of this section.
    (B) A combustion control device tested under paragraph (b) of this 
section that meets the outlet TOC performance level specified in Sec.  
60.5412(a)(1)(ii) and that establishes a correlation between firebox or 
combustion chamber temperature and the TOC performance level.
    (c) Control device design analysis to meet the requirements of 
Sec.  60.5412(a). (1) For a condenser, the design analysis must include 
an analysis of the vent stream composition, constituent concentrations, 
flowrate, relative humidity, and temperature, and must establish the 
design outlet organic compound concentration level, design average 
temperature of the condenser exhaust vent stream, and the design

[[Page 49554]]

average temperatures of the coolant fluid at the condenser inlet and 
outlet.
    (2) For a regenerable carbon adsorption system, the design analysis 
shall include the vent stream composition, constituent concentrations, 
flowrate, relative humidity, and temperature, and shall establish the 
design exhaust vent stream organic compound concentration level, 
adsorption cycle time, number and capacity of carbon beds, type and 
working capacity of activated carbon used for the carbon beds, design 
total regeneration stream flow over the period of each complete carbon 
bed regeneration cycle, design carbon bed temperature after 
regeneration, design carbon bed regeneration time, and design service 
life of the carbon.
    (3) For a nonregenerable carbon adsorption system, such as a carbon 
canister, the design analysis shall include the vent stream 
composition, constituent concentrations, flowrate, relative humidity, 
and temperature, and shall establish the design exhaust vent stream 
organic compound concentration level, capacity of the carbon bed, type 
and working capacity of activated carbon used for the carbon bed, and 
design carbon replacement interval based on the total carbon working 
capacity of the control device and source operating schedule. In 
addition, these systems will incorporate dual carbon canisters in case 
of emission breakthrough occurring in one canister.
    (4) If you and the Administrator do not agree on a demonstration of 
control device performance using a design analysis, then you must 
perform a performance test in accordance with the requirements of 
paragraph (b) of this section to resolve the disagreement. The 
Administrator may choose to have an authorized representative observe 
the performance test.
    (d) Performance testing for combustion control devices--
manufacturers' performance test. The manufacturer must demonstrate that 
a specific model of combustion control device achieves the performance 
requirements in paragraph (d)(1) of this section by conducting a 
performance test as specified in paragraphs (d)(2) through (8) of this 
section. You must submit a test report for each combustion control 
device in accordance with the requirements in paragraphs (d)(9) of this 
section.
    (1) The manufacturer must meet the performance test criteria in 
paragraphs (d)(1)(i) through (iii) of this section.
    (i) The control device model tested must meet the emission levels 
in paragraphs (d)(1)(i)(A) through (C) of this section.
    (A) Method 22 at 40 CFR part 60, appendix A-7, results under 
paragraph (d)(6)(iv) of this section with no indication of visible 
emissions.
    (B) Average Method 25A at 40 CFR part 60, appendix A-7, results 
under paragraph (d)(8) of this section equal to or less than 10.0 parts 
per million by volume-wet THC as propane corrected to 3.0 percent 
carbon dioxide, and
    (C) Average carbon monoxide emissions determined under paragraph 
(d)(6)(iii) of this section equal to or less than 10 parts per million 
by volume-dry, corrected to 3.0 percent carbon dioxide.
    (ii) The manufacturer must determine a maximum inlet gas flow rate, 
which must not be exceeded for each control device model to achieve the 
criteria in paragraph (d)(1)(i) of this section.
    (iii) A control device meeting the emission levels in paragraph 
(d)(1)(i)(A) through (C) of this section must demonstrate a minimum 
destruction efficiency of 95.0 percent for VOC regulated under this 
subpart.
    (2) Performance testing must consist of three one-hour (or longer) 
test runs for each of the four firing rate settings in paragraphs 
(d)(2)(i) through (iv) of this section, making a total of 12 test runs 
per test. The manufacturer must use propene (propylene) gas for the 
testing fuel. An independent third-party laboratory (not affiliated 
with the control device manufacturer or fuel supplier) must perform all 
fuel analyses.
    (i) 90-100 percent of maximum design rate (fixed rate).
    (ii) 70-100-70 percent (ramp up, ramp down). Begin the test at 70 
percent of the maximum design rate. Within the first 5 minutes, ramp up 
the firing rate to 100 percent of the maximum design rate. Hold at 100 
percent for 5 minutes. In the 10-15 minute time range, ramp back down 
to 70 percent of the maximum design rate. Repeat three more times for a 
total of 60 minutes of sampling.
    (iii) 30-70-30 percent (ramp up, ramp down). Begin the test at 30 
percent of the maximum design rate. Within the first 5 minutes, ramp up 
the firing rate to 70 percent of the maximum design rate. Hold at 70 
percent for 5 minutes. In the 10-15 minute time range, ramp back down 
to 30 percent of the maximum design rate. Repeat three more times for a 
total of 60 minutes of sampling.
    (iv) 0-30-0 percent (ramp up, ramp down). Begin the test at 0 
percent of the maximum design rate. Within the first 5 minutes, ramp up 
the firing rate to 100 percent of the maximum design rate. Hold at 30 
percent for 5 minutes. In the 10-15 minute time range, ramp back down 
to 0 percent of the maximum design rate. Repeat three more times for a 
total of 60 minutes of sampling.
    (3) The manufacturer must test all models employing multiple 
enclosures simultaneously and with all burners operational. The 
manufacturer must report results for each enclosure individually and 
for the average of the emissions from all interconnected combustion 
enclosures/chambers. Control device operating data must be collected 
continuously throughout the performance test using an electronic Data 
Acquisition System and strip chart. The manufacturer must submit data 
with the test report in accordance with paragraph (d)(9) of this 
section.
    (4) The manufacturer must conduct inlet testing as specified in 
paragraphs (d)(4)(i) through (iii) of this section.
    (i) The fuel flow metering system must be located in accordance 
with Method 2A at 40 CFR part 60, appendix A-1, (or other approved 
procedure) to measure fuel flow rate at the control device inlet 
location. You must position the fitting for filling fuel sample 
containers a minimum of eight pipe diameters upstream of any inlet fuel 
flow monitoring meter.
    (ii) The manufacturer must determine the inlet flow rate using 
Method 2A at 40 CFR part 60, appendix A-1. Record the start and stop 
reading for each 60-minute THC test. Record the gas pressure and 
temperature at 5-minute intervals throughout each 60-minute THC test.
    (iii) The manufacturer must conduct inlet fuel sampling in 
accordance with the criteria in paragraph (d)(5) of this section.
    (5) The manufacturer must conduct inlet fuel sampling as specified 
in paragraphs (d)(5)(i) and (ii) of this section.
    (i) At the inlet fuel sampling location, the manufacturer must 
securely connect a Silonite-coated stainless steel evacuated canister 
fitted with a flow controller sufficient to fill the canister over a 1 
hour period. Filling must be conducted as specified in paragraphs 
(d)(5)(i)(A) through (C) of this section.
    (A) Open the canister sampling valve at the beginning of the total 
hydrocarbon test, and close the canister at the end of the total 
hydrocarbon test.
    (B) Fill one canister for each total hydrocarbon test run.
    (C) Label the canisters individually and record on a chain of 
custody form.
    (ii) The manufacturer must analyze each fuel sample using the 
methods in paragraphs (d)(5)(ii)(A) through (D) of this section. You 
must include the results in the test report in paragraph (d)(9) of this 
section.

[[Page 49555]]

    (A) Hydrocarbon compounds containing between one and five atoms of 
carbon plus benzene using ASTM D1945-03 (Reapproved 2010) (incorporated 
by reference as specified in Sec.  60.17).
    (B) Hydrogen (H2), carbon monoxide (CO), carbon dioxide 
(CO2), nitrogen (N2), oxygen (O2) 
using ASTM D1945-03 (Reapproved 2010) (incorporated by reference as 
specified in Sec.  60.17).
    (C) Carbonyl sulfide, carbon disulfide plus mercaptans using ASTM 
D5504-08 (incorporated by reference as specified in Sec.  60.17).
    (D) Higher heating value using ASTM D3588-98 (Reapproved 2003) or 
ASTM D4891-89 (Reapproved 2006) (incorporated by reference as specified 
in Sec.  60.17).
    (6) The manufacturer must conduct outlet testing in accordance with 
the criteria in paragraphs (d)(6)(i) through (iv) and (d)(7) of this 
section.
    (i) The manufacturer must sample and measure flowrate in accordance 
with the following:
    (A) The manufacturer must position the outlet sampling location a 
minimum of four equivalent stack diameters downstream from the highest 
peak flame or any other flow disturbance, and a minimum of one 
equivalent stack diameter upstream of the exit or any other flow 
disturbance. A minimum of two sample ports must be used.
    (B) The manufacturer must measure flow rate using Method 1 at 40 
CFR part 60, appendix A-1 for determining flow measurement traverse 
point location, and Method 2 at 40 CFR part 60, appendix A-1 for 
measuring duct velocity. If low flow conditions are encountered (i.e., 
velocity pressure differentials less than 0.05 inches of water) during 
the performance test, a more sensitive manometer must be used to obtain 
an accurate flow profile.
    (ii) The manufacturer must determine molecular weight as specified 
in paragraph (d)(7) of this section.
    (iii) The manufacturer must determine carbon monoxide using Method 
10 at 40 CFR part 60, appendix A-4 or ASTM D6522-00 (Reapproved 2005) 
(incorporated by reference as specified in Sec.  60.17). The 
manufacturer must run the test at the same time and with the sample 
points used for the Method 25A at 40 CFR part 60, appendix A-7, 
testing. An instrument range of 0-10 parts per million by volume-dry 
(ppmvd) must be used.
    (iv) The manufacturer must determine visible emissions using Method 
22 at 40 CFR part 60, appendix A-7. The test must be performed 
continuously during each test run. A digital color photograph of the 
exhaust point, taken from the position of the observer and annotated 
with date and time, will be taken once per test run and the four photos 
included in the test report.
    (7) The manufacturer must determine molecular weight as specified 
in paragraphs (d)(7)(i) and (ii) of this section.
    (i) The manufacturer must collect an integrated bag sample during 
the Method 4 at 40 CFR part 60, appendix A-3, moisture test. The 
manufacturer must analyze the bag sample using a gas chromatograph-
thermal conductivity detector (GC-TCD) analysis meeting the criteria in 
paragraphs (d)(7)(i)(A) through (D) of this section.
    (A) Collect the integrated sample throughout the entire test, and 
collect representative volumes from each traverse location.
    (B) Purge the sampling line with stack gas before opening the valve 
and beginning to fill the bag.
    (C) Knead or otherwise vigorously mix the bag contents prior to the 
gas chromatograph analysis.
    (D) Modify the gas chromatograph-thermal conductivity detector 
calibration procedure in Method 3C at 40 CFR part 60, appendix A-2 by 
using EPA Alt-045 as follows: For the initial calibration, triplicate 
injections of any single concentration must agree within 5 percent of 
their mean to be valid. The calibration response factor for a single 
concentration re-check must be within 10 percent of the original 
calibration response factor for that concentration. If this criterion 
is not met, repeat the initial calibration using at least three 
concentration levels.
    (ii) The manufacturer must report the molecular weight of oxygen, 
carbon dioxide, methane, and nitrogen and include in the test report 
submitted under Sec.  60.5420(b)(7). The manufacturer must determine 
moisture using Method 4 at 40 CFR part 60, appendix A-3. Traverse both 
ports with the Method 4 at 40 CFR part 60, appendix A-3, sampling train 
during each test run. The manufacturer must not introduce ambient air 
into the Method 3C at 40 CFR part 60, appendix A-2, integrated bag 
sample during the port change.
    (8) The manufacturer must determine total hydrocarbons as specified 
by the criteria in paragraphs (d)(8)(i) through (vii) of this section.
    (i) Conduct THC sampling using Method 25A at 40 CFR part 60, 
appendix A-7, except the option for locating the probe in the center 10 
percent of the stack is not allowed. The THC probe must be traversed to 
16.7 percent, 50 percent, and 83.3 percent of the stack diameter during 
the testing.
    (ii) A valid test must consist of three Method 25A at 40 CFR part 
60, appendix A-7, tests, each no less than 60 minutes in duration.
    (iii) A 0-10 parts per million by volume-wet (ppmvw) (as propane) 
measurement range is preferred; as an alternative a 0-30 ppmvw (as 
carbon) measurement range may be used.
    (iv) Calibration gases will be propane in air and be certified 
through EPA Protocol 1--``EPA Traceability Protocol for Assay and 
Certification of Gaseous Calibration Standards,'' September 1997, as 
amended August 25, 1999, EPA-600/R-97/121.
    (v) THC measurements must be reported in terms of ppmvw as propane.
    (vi) THC results must be corrected to 3 percent CO2, as 
measured by Method 3C at 40 CFR part 60, appendix A-2.
    (vii) Subtraction of methane/ethane from the THC data is not 
allowed in determining results.
    (9) For each combustion control device model tested by the 
manufacturer under this section, you must maintain records of the 
information listed in paragraphs (d)(9)(i) through (vi) of this 
section.
    (i) A full schematic of the control device and dimensions of the 
device components.
    (ii) The design net heating value (minimum and maximum) of the 
device.
    (iii) The test fuel gas flow range (in both mass and volume). 
Include the minimum and maximum allowable inlet gas flow rate.
    (iv) The air/stream injection/assist ranges, if used.
    (v) The test parameter ranges listed in paragraphs (d)(9)(v)(A) 
through (O) of this section, as applicable for the tested model.
    (A) Fuel gas delivery pressure and temperature.
    (B) Fuel gas moisture range.
    (C) Purge gas usage range.
    (D) Condensate (liquid fuel) separation range.
    (E) Combustion zone temperature range. This is required for all 
devices that measure this parameter.
    (F) Excess combustion air range.
    (G) Flame arrestor(s).
    (H) Burner manifold pressure.
    (I) Pilot flame sensor.
    (J) Pilot flame design fuel and fuel usage.
    (K) Tip velocity range.
    (L) Momentum flux ratio.
    (M) Exit temperature range.
    (N) Exit flow rate.
    (O) Wind velocity and direction.
    (vi) You must include all calibration quality assurance/quality 
control data, calibration gas values, gas cylinder certification, and 
strip charts annotated

[[Page 49556]]

with test times and calibration values in the test report.


Sec.  60.5415  How do I demonstrate continuous compliance with the 
standards for my gas well affected facility, my centrifugal compressor 
affected facility, my stationary reciprocating compressor affected 
facility, my pneumatic controller affected facility, my storage vessel 
affected facility, and my affected facilities at onshore natural gas 
processing plants?

    (a) For each gas well affected facility, you must demonstrate 
continuous compliance by submitting the reports required by Sec.  
60.5420(b) and maintaining the records for each completion operation 
specified in Sec.  60.5420(c)(1).
    (b) For each centrifugal compressor affected facility, you must 
demonstrate continuous compliance according to paragraphs (b)(1) and 
(2) of this section.
    (1) You must reduce VOC emissions from the wet seal fluid degassing 
system by 95.0 percent or greater.
    (2) If you use a control device to reduce emissions, you must 
demonstrate continuous compliance according to paragraph (e)(2) of this 
section.
    (3) You must submit the annual report required by 60.5420(b) and 
maintain the records as specified in Sec.  60.5420(c)(2).
    (c) For each reciprocating compressor affected facility, you must 
demonstrate continuous compliance according to paragraphs (c)(1) 
through (3) of this section.
    (1) You must continuously monitor the number of hours of operation 
for each reciprocating compressor affected facility or track the number 
of months since initial startup, or October 15, 2012, or the date of 
the most recent reciprocating compressor rod packing replacement, 
whichever is later.
    (2) You must submit the annual report as required in Sec.  
60.5420(b) and maintain records as required in Sec.  60.5420(c)(3).
    (3) You must replace the reciprocating compressor rod packing 
before the total number of hours of operation reaches 26,000 hours or 
the number of months since the most recent rod packing replacement 
reaches 36 months.
    (d) For each pneumatic controller affected facility, you must 
demonstrate continuous compliance according to paragraphs (d)(1) 
through (3) of this section.
    (1) You must continuously operate the pneumatic controllers as 
required in Sec.  60.5390(a), (b), or (c).
    (2) You must submit the annual report as required in Sec.  
60.5420(b).
    (3) You must maintain records as required in Sec.  60.5420(c)(4).
    (e) For each storage vessel affected facility for which the VOC 
emissions are greater than 6 tpy, you must demonstrate continuous 
compliance according to paragraphs (e)(1) and (2) of this section.
    (1) You must reduce VOC emissions from each storage vessel are 
reduced by 95.0 percent or greater.
    (2) If you use a control device to reduce VOC emissions, you must 
demonstrate continuous compliance with the performance requirements of 
Sec.  60.5412(a)(2) using the procedure specified in paragraphs 
(e)(2)(i) through (vii) of this section. If you use a condenser as the 
control device to achieve the requirements specified in Sec.  
60.5412(a)(2), you may demonstrate compliance according to paragraph 
(e)(2)(viii) of this section. You may switch between compliance with 
paragraphs (e)(2)(i) through (vii) of this section and compliance with 
paragraph (e)(2)(viii) of this section only after at least 1 year of 
operation in compliance with the selected approach. You must provide 
notification of such a change in the compliance method in the next 
Annual Report, as required in Sec.  60.5420(b), following the change.
    (i) You must operate below (or above) the site specific maximum (or 
minimum) parameter value established according to the requirements of 
Sec.  60.5417(f)(1).
    (ii) You must calculate the daily average of the applicable 
monitored parameter in accordance with Sec.  60.5417(e) except that the 
inlet gas flow rate to the control device must not be averaged.
    (iii) Compliance with the operating parameter limit is achieved 
when the daily average of the monitoring parameter value calculated 
under paragraph (e)(2)(ii) of this section is either equal to or 
greater than the minimum monitoring value or equal to or less than the 
maximum monitoring value established under paragraph (e)(2)(i) of this 
section. When performance testing of a combustion control device is 
conducted by the device manufacturer as specified in Sec.  60.5413(d), 
compliance with the operating parameter limit is achieved when the 
inlet gas flow rate is equal to or less than the value established 
under Sec.  60.5413(d)(1)(ii).
    (iv) You must operate the continuous monitoring system required in 
Sec.  60.5417 at all times the affected source is operating, except for 
periods of monitoring system malfunctions, repairs associated with 
monitoring system malfunctions, and required monitoring system quality 
assurance or quality control activities (including, as applicable, 
system accuracy audits and required zero and span adjustments). A 
monitoring system malfunction is any sudden, infrequent, not reasonably 
preventable failure of the monitoring system to provide valid data. 
Monitoring system failures that are caused in part by poor maintenance 
or careless operation are not malfunctions. You are required to 
complete monitoring system repairs in response to monitoring system 
malfunctions and to return the monitoring system to operation as 
expeditiously as practicable.
    (v) You may not use data recorded during monitoring system 
malfunctions, repairs associated with monitoring system malfunctions, 
or required monitoring system quality assurance or control activities 
in calculations used to report emissions or operating levels. You must 
use all the data collected during all other required data collection 
periods to assess the operation of the control device and associated 
control system.
    (vi) Failure to collect required data is a deviation of the 
monitoring requirements, except for periods of monitoring system 
malfunctions, repairs associated with monitoring system malfunctions, 
and required quality monitoring system quality assurance or quality 
control activities (including, as applicable, system accuracy audits 
and required zero and span adjustments).
    (vii) If you use a combustion control device to meet the 
requirements of Sec.  60.5412(a), you must demonstrate compliance by 
installing a device tested under the provisions in Sec.  60.5413(d) and 
complying with the criteria in paragraphs (e)(2)(vii)(A) through (D) of 
this section.
    (A) The inlet gas flow rate must meet the range specified by the 
manufacturer. You must measure the flow rate as specified in Sec.  
60.5417(d)(1)(viii)(A).
    (B) A pilot flame must be present at all times of operation. You 
must monitor the pilot flame in accordance with Sec.  
60.5417(d)(1)(viii)(B).
    (C) You must operate the combustion control device with no visible 
emissions, except for periods not to exceed a total of 5 minutes during 
any 2 consecutive hours. You must perform a visible emissions test 
using Method 22 at 40 CFR part 60, appendix A-7 monthly. The 
observation period must be 2 hours and must follow Method 22.
    (D) Compliance with the operating parameter limit is achieved when 
the criteria in paragraphs (e)(2)(vii)(D)(1) through (5) are met.
    (1) The inlet gas flow rate monitored under paragraph 
(e)(2)(vii)(A) of this section is equal to or below the maximum 
established by the manufacturer.

[[Page 49557]]

    (2) The pilot flame is present at all times; and
    (3) During the visible emissions test performed under paragraph 
(e)(2)(vii)(C) of this section, the duration of visible emissions does 
not exceed a total of 5 minutes during the observation period. Devices 
failing the visible emissions test must follow the requirements in 
paragraphs (e)(2)(vii)(D)(4) and (5) of this section.
    (4) Following the first failure, you must replace the fuel 
nozzle(s) and burner tubes.
    (5) If, following replacement of the fuel nozzle(s) and burner 
tubes as specified in paragraph (e)(2)(vii)(D)(4) of this section, the 
visible emissions test is not passed in the next scheduled test, you 
must either conduct a performance test as specified in Sec.  60.5413, 
or replace the device with another control device whose model was 
tested and meets the requirements in Sec.  60.5413(d).
    (viii) If you use a condenser as the control device to achieve the 
percent reduction performance requirements specified in Sec.  
60.5412(a)(2), you must demonstrate compliance using the procedures in 
paragraphs (e)(2)(viii)(A) through (E) of this section.
    (A) You must establish a site-specific condenser performance curve 
according to Sec.  60.5417(f)(2).
    (B) You must calculate the daily average condenser outlet 
temperature in accordance with Sec.  60.5417(e).
    (C) You must determine the condenser efficiency for the current 
operating day using the daily average condenser outlet temperature 
calculated under paragraph (e)(2)(viii)(B) of this section and the 
condenser performance curve established under paragraph (e)(2)(viii)(A) 
of this section.
    (D) Except as provided in paragraphs (e)(2)(viii)(D)(1) and (2) of 
this section, at the end of each operating day, you must calculate the 
365-day rolling average TOC emission reduction, as appropriate, from 
the condenser efficiencies as determined in paragraph (e)(2)(viii)(C) 
of this section.
    (1) After the compliance dates specified in Sec.  60.5370, if you 
have less than 120 days of data for determining average TOC emission 
reduction, you must calculate the average TOC emission reduction for 
the first 120 days of operation after the compliance dates. You have 
demonstrated compliance with the overall 95.0 percent reduction 
requirement if the 120-day average TOC emission reduction is equal to 
or greater than 95.0 percent.
    (2) After 120 days and no more than 364 days of operation after the 
compliance date specified in Sec.  60.5370, you must calculate the 
average TOC emission reduction as the TOC emission reduction averaged 
over the number of days between the current day and the applicable 
compliance date. You have demonstrated compliance with the overall 95.0 
percent reduction requirement, if the average TOC emission reduction is 
equal to or greater than 95.0 percent.
    (E) If you have data for 365 days or more of operation, you have 
demonstrated compliance with the TOC emission reduction if the rolling 
365-day average TOC emission reduction calculated in paragraph 
(e)(2)(viii)(D) of this section is equal to or greater than 95.0 
percent.
    (f) For affected facilities at onshore natural gas processing 
plants, continuous compliance with VOC requirements is demonstrated if 
you are in compliance with the requirements of Sec.  60.5400.
    (g) For each sweetening unit affected facility at onshore natural 
gas processing plants, you must demonstrate continuous compliance with 
the standards for SO2 specified in Sec.  60.5405(b) 
according to paragraphs (g)(1) and (2) of this section.
    (1) The minimum required SO2 emission reduction 
efficiency (Zc) is compared to the emission reduction 
efficiency (R) achieved by the sulfur recovery technology.
    (i) If R >= Zc, your affected facility is in compliance.
    (ii) If R < Zc, your affected facility is not in 
compliance.
    (2) The emission reduction efficiency (R) achieved by the sulfur 
reduction technology must be determined using the procedures in Sec.  
60.5406(c)(1).
    (h) Affirmative defense for violations of emission standards during 
malfunction. In response to an action to enforce the standards set 
forth in Sec. Sec.  60.5375, 60.5380, 60.5385, 60.5390, 60.5395, 
60.5400, and 60.5405, you may assert an affirmative defense to a claim 
for civil penalties for violations of such standards that are caused by 
malfunction, as defined at Sec.  60.2. Appropriate penalties may be 
assessed, however, if you fail to meet your burden of proving all of 
the requirements in the affirmative defense. The affirmative defense 
shall not be available for claims for injunctive relief.
    (1) To establish the affirmative defense in any action to enforce 
such a standard, you must timely meet the reporting requirements in 
Sec.  60.5420(a), and must prove by a preponderance of evidence that:
    (i) The violation:
    (A) Was caused by a sudden, infrequent, and unavoidable failure of 
air pollution control equipment, process equipment, or a process to 
operate in a normal or usual manner; and
    (B) Could not have been prevented through careful planning, proper 
design or better operation and maintenance practices; and
    (C) Did not stem from any activity or event that could have been 
foreseen and avoided, or planned for; and
    (D) Was not part of a recurring pattern indicative of inadequate 
design, operation, or maintenance; and
    (ii) Repairs were made as expeditiously as possible when a 
violation occurred. Off-shift and overtime labor were used, to the 
extent practicable to make these repairs; and
    (iii) The frequency, amount and duration of the violation 
(including any bypass) were minimized to the maximum extent 
practicable; and
    (iv) If the violation resulted from a bypass of control equipment 
or a process, then the bypass was unavoidable to prevent loss of life, 
personal injury, or severe property damage; and
    (v) All possible steps were taken to minimize the impact of the 
violation on ambient air quality, the environment and human health; and
    (vi) All emissions monitoring and control systems were kept in 
operation if at all possible, consistent with safety and good air 
pollution control practices; and
    (vii) All of the actions in response to the violation were 
documented by properly signed, contemporaneous operating logs; and
    (viii) At all times, the affected source was operated in a manner 
consistent with good practices for minimizing emissions; and
    (ix) A written root cause analysis has been prepared, the purpose 
of which is to determine, correct, and eliminate the primary causes of 
the malfunction and the violation resulting from the malfunction event 
at issue. The analysis shall also specify, using best monitoring 
methods and engineering judgment, the amount of any emissions that were 
the result of the malfunction.
    (2) Report. The owner or operator seeking to assert an affirmative 
defense shall submit a written report to the Administrator with all 
necessary supporting documentation, that it has met the requirements 
set forth in paragraph (h)(1) of this section. This affirmative defense 
report shall be included in the first periodic compliance, deviation 
report or excess emission report otherwise required after the initial 
occurrence of the violation of the relevant standard (which may be the 
end of any applicable averaging period). If such compliance, deviation 
report or

[[Page 49558]]

excess emission report is due less than 45 days after the initial 
occurrence of the violation, the affirmative defense report may be 
included in the second compliance, deviation report or excess emission 
report due after the initial occurrence of the violation of the 
relevant standard.


Sec.  60.5416  What are the initial and continuous cover and closed 
vent system inspection and monitoring requirements for my storage 
vessel and centrifugal compressor affected facility?

    For each closed vent system or cover at your storage vessel or 
centrifugal compressor affected facility, you must comply with the 
requirements of paragraphs (a) through (g) of this section.
    (a) Inspections. Except as provided in paragraphs (e) and (f) of 
this section, you must inspect each closed vent system according to the 
procedures and schedule specified in paragraphs (a)(1) and (2) of this 
section, inspect each cover according to the procedures and schedule 
specified in paragraph (a)(3) of this section, and inspect each bypass 
device according to the procedures of paragraph (a)(4) of this section.
    (1) For each closed vent system joint, seam, or other connection 
that is permanently or semi-permanently sealed (e.g., a welded joint 
between two sections of hard piping or a bolted and gasketed ducting 
flange), you must meet the requirements specified in paragraphs 
(a)(1)(i) and (ii) of this section.
    (i) Conduct an initial inspection according to the test methods and 
procedures specified in paragraph (b) of this section to demonstrate 
that the closed vent system operates with no detectable emissions. You 
must maintain records of the inspection results as specified in Sec.  
60.5420(c)(6).
    (ii) Conduct annual visual inspections for defects that could 
result in air emissions. Defects include, but are not limited to, 
visible cracks, holes, or gaps in piping; loose connections; or broken 
or missing caps or other closure devices. You must monitor a component 
or connection using the test methods and procedures in paragraph (b) of 
this section to demonstrate that it operates with no detectable 
emissions following any time the component is repaired or replaced or 
the connection is unsealed. You must maintain records of the inspection 
results as specified in Sec.  60.5420(c)(6).
    (2) For closed vent system components other than those specified in 
paragraph (a)(1) of this section, you must meet the requirements of 
paragraphs (a)(2)(i) through (iii) of this section.
    (i) Conduct an initial inspection according to the test methods and 
procedures specified in paragraph (b) of this section to demonstrate 
that the closed vent system operates with no detectable emissions. You 
must maintain records of the inspection results as specified in Sec.  
60.5420(c)(6).
    (ii) Conduct annual inspections according to the test methods and 
procedures specified in paragraph (b) of this section to demonstrate 
that the components or connections operate with no detectable 
emissions. You must maintain records of the inspection results as 
specified in Sec.  60.5420(c)(6).
    (iii) Conduct annual visual inspections for defects that could 
result in air emissions. Defects include, but are not limited to, 
visible cracks, holes, or gaps in ductwork; loose connections; or 
broken or missing caps or other closure devices. You must maintain 
records of the inspection results as specified in Sec.  60.5420(c)(6).
    (3) For each cover, you must meet the requirements in paragraphs 
(a)(3)(i) and (ii) of this section.
    (i) Conduct visual inspections for defects that could result in air 
emissions. Defects include, but are not limited to, visible cracks, 
holes, or gaps in the cover, or between the cover and the separator 
wall; broken, cracked, or otherwise damaged seals or gaskets on closure 
devices; and broken or missing hatches, access covers, caps, or other 
closure devices. In the case where the storage vessel is buried 
partially or entirely underground, you must inspect only those portions 
of the cover that extend to or above the ground surface, and those 
connections that are on such portions of the cover (e.g., fill ports, 
access hatches, gauge wells, etc.) and can be opened to the atmosphere.
    (ii) You must initially conduct the inspections specified in 
paragraph (a)(3)(i) of this section following the installation of the 
cover. Thereafter, you must perform the inspection at least once every 
calendar year, except as provided in paragraphs (e) and (f) of this 
section. You must maintain records of the inspection results as 
specified in Sec.  60.5420(c)(7).
    (4) For each bypass device, except as provided for in Sec.  
60.5411, you must meet the requirements of paragraphs (a)(4)(i) or (ii) 
of this section.
    (i) Set the flow indicator to take a reading at least once every 15 
minutes at the inlet to the bypass device that could divert the steam 
away from the control device to the atmosphere.
    (ii) If the bypass device valve installed at the inlet to the 
bypass device is secured in the non-diverting position using a car-seal 
or a lock-and-key type configuration, visually inspect the seal or 
closure mechanism at least once every month to verify that the valve is 
maintained in the non-diverting position and the vent stream is not 
diverted through the bypass device. You must maintain records of the 
inspections according to Sec.  60.5420(c)(8).
    (b) No detectable emissions test methods and procedures. If you are 
required to conduct an inspection of a closed vent system or cover at 
your storage vessel or centrifugal compressor affected facility as 
specified in paragraphs (a)(1), (2), or (3) of this section, you must 
meet the requirements of paragraphs (b)(1) through (13) of this 
section.
    (1) You must conduct the no detectable emissions test procedure in 
accordance with Method 21 at 40 CFR part 60, appendix A-7.
    (2) The detection instrument must meet the performance criteria of 
Method 21 at 40 CFR part 60, appendix A-7, except that the instrument 
response factor criteria in section 3.1.2(a) of Method 21 must be for 
the average composition of the fluid and not for each individual 
organic compound in the stream.
    (3) You must calibrate the detection instrument before use on each 
day of its use by the procedures specified in Method 21 at 40 CFR part 
60, appendix A-7.
    (4) Calibration gases must be as specified in paragraphs (b)(4)(i) 
and (ii) of this section.
    (i) Zero air (less than 10 parts per million by volume hydrocarbon 
in air).
    (ii) A mixture of methane in air at a concentration less than 
10,000 parts per million by volume.
    (5) You may choose to adjust or not adjust the detection instrument 
readings to account for the background organic concentration level. If 
you choose to adjust the instrument readings for the background level, 
you must determine the background level value according to the 
procedures in Method 21 at 40 CFR part 60, appendix A-7.
    (6) Your detection instrument must meet the performance criteria 
specified in paragraphs (b)(6)(i) and (ii) of this section.
    (i) Except as provided in paragraph (b)(6)(ii) of this section, the 
detection instrument must meet the performance criteria of Method 21 at 
40 CFR part 60, appendix A-7, except the instrument response factor 
criteria in section 3.1.2(a) of Method 21 must be for the average 
composition of the process fluid, not each individual volatile organic 
compound in the stream. For

[[Page 49559]]

process streams that contain nitrogen, air, or other inerts that are 
not organic hazardous air pollutants or volatile organic compounds, you 
must calculate the average stream response factor on an inert-free 
basis.
    (ii) If no instrument is available that will meet the performance 
criteria specified in paragraph (b)(6)(i) of this section, you may 
adjust the instrument readings by multiplying by the average response 
factor of the process fluid, calculated on an inert-free basis, as 
described in paragraph (b)(6)(i) of this section.
    (7) You must determine if a potential leak interface operates with 
no detectable emissions using the applicable procedure specified in 
paragraph (b)(7)(i) or (ii) of this section.
    (i) If you choose not to adjust the detection instrument readings 
for the background organic concentration level, then you must directly 
compare the maximum organic concentration value measured by the 
detection instrument to the applicable value for the potential leak 
interface as specified in paragraph (b)(8) of this section.
    (ii) If you choose to adjust the detection instrument readings for 
the background organic concentration level, you must compare the value 
of the arithmetic difference between the maximum organic concentration 
value measured by the instrument and the background organic 
concentration value as determined in paragraph (b)(5) of this section 
with the applicable value for the potential leak interface as specified 
in paragraph (b)(8) of this section.
    (8) A potential leak interface is determined to operate with no 
detectable organic emissions if the organic concentration value 
determined in paragraph (b)(7) of this section is less than 500 parts 
per million by volume.
    (9) Repairs. In the event that a leak or defect is detected, you 
must repair the leak or defect as soon as practicable according to the 
requirements of paragraphs (b)(9)(i) and (ii) of this section, except 
as provided in paragraph (d) of this section.
    (i) A first attempt at repair must be made no later than 5 calendar 
days after the leak is detected.
    (ii) Repair must be completed no later than 15 calendar days after 
the leak is detected.
    (10) Delay of repair. Delay of repair of a closed vent system or 
cover for which leaks or defects have been detected is allowed if the 
repair is technically infeasible without a shutdown, or if you 
determine that emissions resulting from immediate repair would be 
greater than the fugitive emissions likely to result from delay of 
repair. You must complete repair of such equipment by the end of the 
next shutdown.
    (11) Unsafe to inspect requirements. You may designate any parts of 
the closed vent system or cover as unsafe to inspect if the 
requirements in paragraphs (e)(1) and (2) of this section are met. 
Unsafe to inspect parts are exempt from the inspection requirements of 
paragraphs (a)(1) through (3) of this section.
    (A) You determine that the equipment is unsafe to inspect because 
inspecting personnel would be exposed to an imminent or potential 
danger as a consequence of complying with paragraphs (a)(1), (2), or 
(3) of this section.
    (B) You have a written plan that requires inspection of the 
equipment as frequently as practicable during safe-to-inspect times.
    (12) Difficult to inspect requirements. You may designate any parts 
of the closed vent system or cover as difficult to inspect, if the 
requirements in paragraphs (b)(12)(i) and (ii) of this section are met. 
Difficult to inspect parts are exempt from the inspection requirements 
of paragraphs (a)(1) through (3) of this section.
    (i) You determine that the equipment cannot be inspected without 
elevating the inspecting personnel more than 2 meters above a support 
surface.
    (ii) You have a written plan that requires inspection of the 
equipment at least once every 5 years.
    (13) Records. Records shall be maintained as specified in this 
section and in Sec.  60.5420(c)(9).


Sec.  60.5417  What are the continuous control device monitoring 
requirements for my storage vessel or centrifugal compressor affected 
facility?

    You must meet the applicable requirements of this section to 
demonstrate continuous compliance for each control device used to meet 
emission standards for your storage vessel or centrifugal compressor 
affected facility.
    (a) You must install and operate a continuous parameter monitoring 
system for each control device as specified in paragraphs (c) through 
(j) of this section, except as provided for in paragraph (b) of this 
section. If you install and operate a flare in accordance with Sec.  
60.5412(a)(3), you are exempt from the requirements of paragraphs (e) 
and (f) of this section.
    (b) You are exempt from the monitoring requirements specified in 
paragraphs (c) through (j) of this section for the control devices 
listed in paragraphs (b)(1) and (2) of this section.
    (1) A boiler or process heater in which all vent streams are 
introduced with the primary fuel or is used as the primary fuel.
    (2) A boiler or process heater with a design heat input capacity 
equal to or greater than 44 megawatts.
    (c) You must design and operate the continuous monitoring system so 
that a determination can be made on whether the control device is 
achieving the applicable performance requirements of Sec.  60.5412. For 
each continuous parameter monitoring system, you must meet the 
specifications and requirements in paragraphs (c)(1) through (4) of 
this section.
    (1) Each continuous parameter monitoring system must measure data 
values at least once every hour and record the parameters in paragraphs 
(c)(1)(i) or (ii) of this section.
    (i) Each measured data value.
    (ii) Each block average value for each 1-hour period or shorter 
periods calculated from all measured data values during each period. If 
values are measured more frequently than once per minute, a single 
value for each minute may be used to calculate the hourly (or shorter 
period) block average instead of all measured values.
    (2) You must prepare a site-specific monitoring plan that addresses 
the monitoring system design, data collection, and the quality 
assurance and quality control elements outlined in paragraphs (c)(2)(i) 
through (v) of this section. You must install, calibrate, operate, and 
maintain each continuous parameter monitoring system in accordance with 
the procedures in your approved site-specific monitoring plan.
    (i) The performance criteria and design specifications for the 
monitoring system equipment, including the sample interface, detector 
signal analyzer, and data acquisition and calculations.
    (ii) Sampling interface (e.g., thermocouple) location such that the 
monitoring system will provide representative measurements.
    (iii) Equipment performance checks, system accuracy audits, or 
other audit procedures.
    (iv) Ongoing operation and maintenance procedures in accordance 
with provisions in Sec.  60.13(b).
    (v) Ongoing reporting and recordkeeping procedures in accordance 
with provisions in Sec.  60.7(c), (d), and (f).
    (3) You must conduct the continuous parameter monitoring system 
equipment performance checks, system accuracy audits, or other audit 
procedures specified in the site-specific monitoring plan at least once 
every 12 months.
    (4) You must conduct a performance evaluation of each continuous 
parameter monitoring system in

[[Page 49560]]

accordance with the site-specific monitoring plan.
    (d) You must install, calibrate, operate, and maintain a device 
equipped with a continuous recorder to measure the values of operating 
parameters appropriate for the control device as specified in either 
paragraph (d)(1), (2), or (3) of this section.
    (1) A continuous monitoring system that measures the operating 
parameters in paragraphs (d)(1)(i) through (viii) of this section, as 
applicable.
    (i) For a thermal vapor incinerator that demonstrates during the 
performance test conducted under Sec.  60.5413 that combustion zone 
temperature is an accurate indicator of performance, a temperature 
monitoring device equipped with a continuous recorder. The monitoring 
device must have a minimum accuracy of 1 percent of the 
temperature being monitored in [deg]C, or 2.5 [deg]C, 
whichever value is greater. You must install the temperature sensor at 
a location representative of the combustion zone temperature.
    (ii) For a catalytic vapor incinerator, a temperature monitoring 
device equipped with a continuous recorder. The device must be capable 
of monitoring temperature at two locations and have a minimum accuracy 
of 1 percent of the temperature being monitored in [deg]C, 
or 2.5 [deg]C, whichever value is greater. You must install 
one temperature sensor in the vent stream at the nearest feasible point 
to the catalyst bed inlet, and you must install a second temperature 
sensor in the vent stream at the nearest feasible point to the catalyst 
bed outlet.
    (iii) For a flare, a heat sensing monitoring device equipped with a 
continuous recorder that indicates the continuous ignition of the pilot 
flame.
    (iv) For a boiler or process heater, a temperature monitoring 
device equipped with a continuous recorder. The temperature monitoring 
device must have a minimum accuracy of 1 percent of the 
temperature being monitored in [deg]C, or 2.5 [deg]C, 
whichever value is greater. You must install the temperature sensor at 
a location representative of the combustion zone temperature.
    (v) For a condenser, a temperature monitoring device equipped with 
a continuous recorder. The temperature monitoring device must have a 
minimum accuracy of 1 percent of the temperature being 
monitored in [deg]C, or 2.8 [deg]C, whichever value is 
greater. You must install the temperature sensor at a location in the 
exhaust vent stream from the condenser.
    (vi) For a regenerative-type carbon adsorption system, a continuous 
monitoring system that meets the specifications in paragraphs 
(d)(1)(vi)(A) and (B) of this section.
    (A) The continuous parameter monitoring system must measure and 
record the average total regeneration stream mass flow or volumetric 
flow during each carbon bed regeneration cycle. The flow sensor must 
have a measurement sensitivity of 5 percent of the flow rate or 10 
cubic feet per minute, whichever is greater. You must check the 
mechanical connections for leakage at least every month, and you must 
perform a visual inspection at least every 3 months of all components 
of the flow continuous parameter monitoring system for physical and 
operational integrity and all electrical connections for oxidation and 
galvanic corrosion if your flow continuous parameter monitoring system 
is not equipped with a redundant flow sensor; and
    (B) The continuous parameter monitoring system must measure and 
record the average carbon bed temperature for the duration of the 
carbon bed steaming cycle and measure the actual carbon bed temperature 
after regeneration and within 15 minutes of completing the cooling 
cycle. The temperature monitoring device must have a minimum accuracy 
of 1 percent of the temperature being monitored in [deg]C, 
or 2.5 [deg]C, whichever value is greater.
    (vii) For a nonregenerative-type carbon adsorption system, you must 
monitor the design carbon replacement interval established using a 
performance test performed as specified in Sec.  60.5413(b). The design 
carbon replacement interval must be based on the total carbon working 
capacity of the control device and source operating schedule.
    (viii) For a combustion control device whose model is tested under 
Sec.  60.5413(d), a continuous monitoring system meeting the 
requirements of paragraphs (d)(1)(viii)(A) and (B) of this section.
    (A) The continuous monitoring system must measure gas flow rate at 
the inlet to the control device. The monitoring instrument must have an 
accuracy of 2 percent or better.
    (B) A heat sensing monitoring device equipped with a continuous 
recorder that indicates the continuous ignition of the pilot flame.
    (2) A continuous monitoring system that measures the concentration 
level of organic compounds in the exhaust vent stream from the control 
device using an organic monitoring device equipped with a continuous 
recorder. The monitor must meet the requirements of Performance 
Specification 8 or 9 of 40 CFR part 60, appendix B. You must install, 
calibrate, and maintain the monitor according to the manufacturer's 
specifications.
    (3) A continuous monitoring system that measures operating 
parameters other than those specified in paragraph (d)(1) or (2) of 
this section, upon approval of the Administrator as specified in Sec.  
60.13(i).
    (e) You must calculate the daily average value for each monitored 
operating parameter for each operating day, using the data recorded by 
the monitoring system, except for inlet gas flow rate. If the emissions 
unit operation is continuous, the operating day is a 24-hour period. If 
the emissions unit operation is not continuous, the operating day is 
the total number of hours of control device operation per 24-hour 
period. Valid data points must be available for 75 percent of the 
operating hours in an operating day to compute the daily average.
    (f) For each operating parameter monitor installed in accordance 
with the requirements of paragraph (d) of this section, you must comply 
with paragraph (f)(1) of this section for all control devices. When 
condensers are installed, you must also comply with paragraph (f)(2) of 
this section.
    (1) You must establish a minimum operating parameter value or a 
maximum operating parameter value, as appropriate for the control 
device, to define the conditions at which the control device must be 
operated to continuously achieve the applicable performance 
requirements of Sec.  60.5412(a). You must establish each minimum or 
maximum operating parameter value as specified in paragraphs (f)(1)(i) 
through (iii) of this section.
    (i) If you conduct performance tests in accordance with the 
requirements of Sec.  60.5413(b) to demonstrate that the control device 
achieves the applicable performance requirements specified in Sec.  
60.5412(a), then you must establish the minimum operating parameter 
value or the maximum operating parameter value based on values measured 
during the performance test and supplemented, as necessary, by a 
condenser design analysis or control device manufacturer 
recommendations or a combination of both.
    (ii) If you use a condenser design analysis in accordance with the 
requirements of Sec.  60.5413(c) to demonstrate that the control device 
achieves the applicable performance requirements specified in Sec.  
60.5412(a), then you must establish the minimum

[[Page 49561]]

operating parameter value or the maximum operating parameter value 
based on the condenser design analysis and supplemented, as necessary, 
by the condenser manufacturer's recommendations.
    (iii) If you operate a control device where the performance test 
requirement was met under Sec.  60.5413(d) to demonstrate that the 
control device achieves the applicable performance requirements 
specified in Sec.  60.5412(a), then you must establish the maximum 
inlet gas flow rate based on the performance test and supplemented, as 
necessary, by the manufacturer recommendations.
    (2) If you use a condenser as specified in paragraph (d)(1)(v) of 
this section, you must establish a condenser performance curve showing 
the relationship between condenser outlet temperature and condenser 
control efficiency, according to the requirements of paragraphs 
(f)(2)(i) and (ii) of this section.
    (i) If you conduct a performance test in accordance with the 
requirements of Sec.  60.5413(b) to demonstrate that the condenser 
achieves the applicable performance requirements in Sec.  60.5412(a), 
then the condenser performance curve must be based on values measured 
during the performance test and supplemented as necessary by control 
device design analysis, or control device manufacturer's 
recommendations, or a combination or both.
    (ii) If you use a control device design analysis in accordance with 
the requirements of Sec.  60.5413(c)(1) to demonstrate that the 
condenser achieves the applicable performance requirements specified in 
Sec.  60.5412(a), then the condenser performance curve must be based on 
the condenser design analysis and supplemented, as necessary, by the 
control device manufacturer's recommendations.
    (g) A deviation for a given control device is determined to have 
occurred when the monitoring data or lack of monitoring data result in 
any one of the criteria specified in paragraphs (g)(1) through (g)(6) 
of this section being met. If you monitor multiple operating parameters 
for the same control device during the same operating day and more than 
one of these operating parameters meets a deviation criterion specified 
in paragraphs (g)(1) through (6) of this section, then a single 
excursion is determined to have occurred for the control device for 
that operating day.
    (1) A deviation occurs when the daily average value of a monitored 
operating parameter is less than the minimum operating parameter limit 
(or, if applicable, greater than the maximum operating parameter limit) 
established in paragraph (f)(1) of this section.
    (2) If you meet Sec.  60.5412(a)(2), a deviation occurs when the 
365-day average condenser efficiency calculated according to the 
requirements specified in Sec.  60.5415(e)(8)(iv) is less than 95.0 
percent.
    (3) If you meet Sec.  60.5412(a)(2) and you have less than 365 days 
of data, a deviation occurs when the average condenser efficiency 
calculated according to the procedures specified in Sec.  
60.5415(e)(8)(iv)(A) or (B) is less than 90.0 percent.
    (4) A deviation occurs when the monitoring data are not available 
for at least 75 percent of the operating hours in a day.
    (5) If the closed vent system contains one or more bypass devices 
that could be used to divert all or a portion of the gases, vapors, or 
fumes from entering the control device, a deviation occurs when the 
requirements of paragraphs (g)(5)(i) and (ii) of this section are met.
    (i) For each bypass line subject to Sec.  60.5411(a)(3)(i)(A), the 
flow indicator indicates that flow has been detected and that the 
stream has been diverted away from the control device to the 
atmosphere.
    (ii) For each bypass line subject to Sec.  60.5411(a)(3)(i)(B), if 
the seal or closure mechanism has been broken, the bypass line valve 
position has changed, the key for the lock-and-key type lock has been 
checked out, or the car-seal has broken.
    (6) For a combustion control device whose model is tested under 
Sec.  60.5413(d), a deviation occurs when the conditions of paragraphs 
(g)(6)(i) or (ii) are met.
    (i) The inlet gas flow rate exceeds the maximum established during 
the test conducted under Sec.  60.5413(d).
    (ii) Failure of the monthly visible emissions test conducted under 
Sec.  60.5415(e)(7)(iii) occurs.


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

    (a) You must submit the notifications required in Sec.  60.7(a)(1) 
and (4), and according to paragraphs (a)(1) and (2) of this section, if 
you own or operate one or more of the affected facilities specified in 
Sec.  60.5365 that was constructed, modified, or reconstructed during 
the reporting period.
    (1) If you own or operate a gas well, pneumatic controller or 
storage vessel affected facility you are not required to submit the 
notifications required in Sec.  60.7(a)(1), (3), and (4).
    (2)(i) If you own or operate a gas well affected facility, you must 
submit a notification to the Administrator no later than 2 days prior 
to the commencement of each well completion operation listing the 
anticipated date of the well completion operation. The notification 
shall include contact information for the owner or operator; the API 
well number, the latitude and longitude coordinates for each well in 
decimal degrees to an accuracy and precision of five (5) decimals of a 
degree using the North American Datum of 1983; and the planned date of 
the beginning of flowback. You may submit the notification in writing 
or in electronic format.
    (ii) If you are subject to state regulations that require advance 
notification of well completions and you have met those notification 
requirements, then you are considered to have met the advance 
notification requirements of paragraph (a)(2)(i) of this section.
    (b) Reporting requirements. You must submit annual reports 
containing the information specified in paragraphs (b)(1) through (6) 
of this section to the Administrator and performance test reports as 
specified in paragraph (b)(7) of this section. The initial annual 
report is due 30 days after the end of the initial compliance period as 
determined according to Sec.  60.5410. Subsequent annual reports are 
due on the same date each year as the initial annual report. If you own 
or operate more than one affected facility, you may submit one report 
for multiple affected facilities provided the report contains all of 
the information required as specified in paragraphs (b)(1) through (6) 
of this section. Annual reports may coincide with title V reports as 
long as all the required elements of the annual report are included. 
You may arrange with the Administrator a common schedule on which 
reports required by this part may be submitted as long as the schedule 
does not extend the reporting period.
    (1) The general information specified in paragraphs (b)(1)(i) 
through (iv) of this section.
    (i) The company name and address of the affected facility.
    (ii) An identification of each affected facility being included in 
the annual report.
    (iii) Beginning and ending dates of the reporting period.
    (iv) A certification by a responsible official of truth, accuracy, 
and completeness. This certification shall state that, based on 
information and belief formed after reasonable inquiry, the statements 
and information in the document are true, accurate, and complete.

[[Page 49562]]

    (2) For each gas well affected facility, the information in 
paragraphs (b)(2)(i) through (ii) of this section.
    (i) Records of each well completion operation as specified in 
paragraph (c)(1)(i) through (iv) of this section for each gas well 
affected facility conducted during the reporting period. In lieu of 
submitting the records specified in paragraph (c)(1)(i) through (iv), 
the owner or operator may submit a list of the well completions with 
hydraulic fracturing completed during the reporting period and the 
records required by paragraph (c)(1)(v) of this section for each well 
completion.
    (ii) Records of deviations specified in paragraph (c)(1)(ii) of 
this section that occurred during the reporting period.
    (3) For each centrifugal compressor affected facility, the 
information specified in paragraphs (b)(3)(i) and (ii) of this section.
    (i) An identification of each centrifugal compressor using a wet 
seal system constructed, modified or reconstructed during the reporting 
period.
    (ii) Records of deviations specified in paragraph (c)(2) of this 
section that occurred during the reporting period.
    (iii) If required to comply with Sec.  60.5380(a)(1), the records 
of closed vent system and cover inspections specified in paragraph 
(c)(6) of this section.
    (4) For each reciprocating compressor affected facility, the 
information specified in paragraphs (b)(4)(i) through (ii) of this 
section.
    (i) The cumulative number of hours or operation or the number of 
months since initial startup, October 15, 2012, or since the previous 
reciprocating compressor rod packing replacement, whichever is later.
    (ii) Records of deviations specified in paragraph (c)(3)(iii) of 
this section that occurred during the reporting period.
    (5) For each pneumatic controller affected facility, the 
information specified in paragraphs (b)(5)(i) through (v) of this 
section.
    (i) An identification of each pneumatic controller constructed, 
modified or reconstructed during the reporting period, including the 
identification information specified in Sec.  60.5390(c)(2).
    (ii) If applicable, documentation that the use of pneumatic 
controller affected facilities with a natural gas bleed rate greater 
than 6 standard cubic feet per hour are required and the reasons why.
    (iii) Records of deviations specified in paragraph (c)(4)(v) of 
this section that occurred during the reporting period.
    (6) For each storage vessel affected facility, the information in 
paragraphs (b)(6)(i) through (iii) of this section.
    (i) An identification of each storage vessel with VOC emissions 
greater than 6 tpy constructed, modified or reconstructed during the 
reporting period.
    (ii) Documentation that the VOC emission rate is less than 6 tpy 
for meeting the requirements in Sec.  60.5395(a).
    (iii) Records of deviations specified in paragraph (c)(5)(iii) of 
this section that occurred during the reporting period.
    (7)(i) Within 60 days after the date of completing each performance 
test (see Sec.  60.8 of this part) as required by this subpart you must 
submit the results of the performance tests required by this subpart to 
EPA's WebFIRE database by using the Compliance and Emissions Data 
Reporting Interface (CEDRI) that is accessed through EPA's Central Data 
Exchange (CDX) (www.epa.gov/cdx). Performance test data must be 
submitted in the file format generated through use of EPA's Electronic 
Reporting Tool (ERT) (see http://www.epa.gov/ttn/chief/ert/index.html). 
Only data collected using test methods on the ERT Web site are subject 
to this requirement for submitting reports electronically to WebFIRE. 
Owners or operators who claim that some of the information being 
submitted for performance tests is confidential business information 
(CBI) must submit a complete ERT file including information claimed to 
be CBI on a compact disk or other commonly used electronic storage 
media (including, but not limited to, flash drives) to EPA. The 
electronic media must be clearly marked as CBI and mailed to U.S. EPA/
OAPQS/CORE CBI Office, Attention: WebFIRE Administrator, MD C404-02, 
4930 Old Page Rd., Durham, NC 27703. The same ERT file with the CBI 
omitted must be submitted to EPA via CDX as described earlier in this 
paragraph. At the discretion of the delegated authority, you must also 
submit these reports, including the confidential business information, 
to the delegated authority in the format specified by the delegated 
authority.
    (ii) All reports required by this subpart not subject to the 
requirements in paragraph (a)(2)(i) of this section must be sent to the 
Administrator at the appropriate address listed in Sec.  63.13 of this 
part. The Administrator or the delegated authority may request a report 
in any form suitable for the specific case (e.g., by commonly used 
electronic media such as Excel spreadsheet, on CD or hard copy). The 
Administrator retains the right to require submittal of reports subject 
to paragraph (a)(2)(i) and (ii) of this section in paper format.
    (c) Recordkeeping requirements. You must maintain the records 
identified as specified in Sec.  60.7(f) and in paragraphs (c)(1) 
through (10) of this section. All records must be maintained for at 
least 5 years.
    (1) The records for each gas well affected facility as specified in 
paragraphs (c)(1)(i) through (v) of this section.
    (i) Records identifying each well completion operation for each gas 
well affected facility;
    (ii) Records of deviations in cases where well completion 
operations with hydraulic fracturing were not performed in compliance 
with the requirements specified in Sec.  60.5375.
    (iii) Records required in Sec.  60.5375(b) or (f) for each well 
completion operation conducted for each gas well affected facility that 
occurred during the reporting period. You must maintain the records 
specified in paragraphs (c)(1)(iii)(A) and (B) of this section.
    (A) For each gas well affected facility required to comply with the 
requirements of Sec.  60.5375(a), you must record: The location of the 
well; the API well number; the duration of flowback; duration of 
recovery to the flow line; duration of combustion; duration of venting; 
and specific reasons for venting in lieu of capture or combustion. The 
duration must be specified in hours of time.
    (B) For each gas well affected facility required to comply with the 
requirements of Sec.  60.5375(f), you must maintain the records 
specified in paragraph (c)(1)(iii)(A) of this section except that you 
do not have to record the duration of recovery to the flow line.
    (iv) For each gas well facility for which you claim an exception 
under Sec.  60.5375(a)(3), you must record: The location of the well; 
the API well number; the specific exception claimed; the starting date 
and ending date for the period the well operated under the exception; 
and an explanation of why the well meets the claimed exception.
    (v) For each gas well affected facility required to comply with 
both Sec.  60.5375(a)(1) and (3), records of the digital photograph as 
specified in Sec.  60.5410(a)(4).
    (2) For each centrifugal compressor affected facility, you must 
maintain records of deviations in cases where the centrifugal 
compressor was not operated in compliance with the requirements 
specified in Sec.  60.5380.
    (3) For each reciprocating compressors affected facility, you must 
maintain the records in paragraphs (c)(3)(i) through (iii) of this 
section.

[[Page 49563]]

    (i) Records of the cumulative number of hours of operation or 
number of months since initial startup or October 15, 2012, or the 
previous replacement of the reciprocating compressor rod packing, 
whichever is later.
    (ii) Records of the date and time of each reciprocating compressor 
rod packing replacement.
    (iii) Records of deviations in cases where the reciprocating 
compressor was not operated in compliance with the requirements 
specified in Sec.  60.5385.
    (4) For each pneumatic controller affected facility, you must 
maintain the records identified in paragraphs (c)(4)(i) through (v) of 
this section.
    (i) Records of the date, location and manufacturer specifications 
for each pneumatic controller constructed, modified or reconstructed.
    (ii) Records of the demonstration that the use of pneumatic 
controller affected facilities with a natural gas bleed rate greater 
than 6 standard cubic feet per hour are required and the reasons why.
    (iii) If the pneumatic controller is not located at a natural gas 
processing plant, records of the manufacturer's specifications 
indicating that the controller is designed such that natural gas bleed 
rate is less than or equal to 6 standard cubic feet per hour.
    (iv) If the pneumatic controller is located at a natural gas 
processing plant, records of the documentation that the natural gas 
bleed rate is zero.
    (v) Records of deviations in cases where the pneumatic controller 
was not operated in compliance with the requirements specified in Sec.  
60.5390.
    (5) For each storage vessel affected facility, you must maintain 
the records identified in paragraphs (c)(5)(i) through (iv) of this 
section.
    (i) If required to reduce emissions by complying with Sec.  
60.5395, the records specified in Sec.  60.5416 of this subpart.
    (ii) Records of the determination that the VOC emission rate is 
less than 6 tpy per storage vessel for the exemption under Sec.  
60.5395(a), including identification of the model or calculation 
methodology used to calculate the VOC emission rate.
    (iii) Records of deviations in cases where the storage vessel was 
not operated in compliance with the requirements specified in 
Sec. Sec.  60.5395, 60.5411, 60.5412, and 60.5413.
    (iv) For vessels that are skid-mounted or permanently attached to 
something that is mobile (such as trucks, railcars, barges or ships), 
records indicating the number of consecutive days that the vessel is 
located at a site in the oil and natural gas production segment, 
natural gas processing segment or natural gas transmission and storage 
segment. If a vessel is removed from a site and, within 30 days, is 
either returned to or replaced by another vessel at the site to serve 
the same or similar function, then the entire period since the original 
vessel was first located at the site, including the days when the 
storage vessel was removed, will be added to the count towards the 
number of consecutive days.
    (6) For each storage vessel or centrifugal compressor subject to 
the closed vent system inspection requirements of Sec.  60.5416(a)(1) 
and (2), records of each inspection.
    (7) For each storage vessel or centrifugal compressor subject to 
the cover requirements of Sec.  60.5416(a)(3), a record of each 
inspection.
    (8) For each storage vessel or centrifugal compressor subject to 
the bypass requirements of Sec.  60.5416(a)(4), a record of each 
inspection or a record each time the key is checked out or a record of 
each time the alarm is sounded.
    (9) For each closed vent system used to comply with this subpart 
that must operate with no detectable emissions, a record of the 
monitoring conducted in accordance with Sec.  60.5416(b)(13).
    (10) Records of the schedule for carbon replacement (as determined 
by the design analysis requirements of Sec.  60.5413(c)(2) or (3)) and 
records of each carbon replacement as specified in Sec.  60.5412(c)(1).
    (11) For each storage vessel or centrifugal compressor subject to 
the control device requirements of Sec.  60.5412, records of minimum 
and maximum operating parameter values, continuous parameter monitoring 
system data, calculated averages of continuous parameter monitoring 
system data, results of all compliance calculations, and results of all 
inspections.


Sec.  60.5421  What are my additional recordkeeping requirements for my 
affected facility subject to VOC requirements for onshore natural gas 
processing plants?

    (a) You must comply with the requirements of paragraph (b) of this 
section in addition to the requirements of Sec.  60.486a.
    (b) The following recordkeeping requirements apply to pressure 
relief devices subject to the requirements of Sec.  60.5401(b)(1) of 
this subpart.
    (1) When each leak is detected as specified in Sec.  60.5401(b)(2), 
a weatherproof and readily visible identification, marked with the 
equipment identification number, must be attached to the leaking 
equipment. The identification on the pressure relief device may be 
removed after it has been repaired.
    (2) When each leak is detected as specified in Sec.  60.5401(b)(2), 
the following information must be recorded in a log and shall be kept 
for 2 years in a readily accessible location:
    (i) The instrument and operator identification numbers and the 
equipment identification number.
    (ii) The date the leak was detected and the dates of each attempt 
to repair the leak.
    (iii) Repair methods applied in each attempt to repair the leak.
    (iv) ``Above 500 ppm'' if the maximum instrument reading measured 
by the methods specified in paragraph (a) of this section after each 
repair attempt is 500 ppm or greater.
    (v) ``Repair delayed'' and the reason for the delay if a leak is 
not repaired within 15 calendar days after discovery of the leak.
    (vi) The signature of the owner or operator (or designate) whose 
decision it was that repair could not be effected without a process 
shutdown.
    (vii) The expected date of successful repair of the leak if a leak 
is not repaired within 15 days.
    (viii) Dates of process unit shutdowns that occur while the 
equipment is unrepaired.
    (ix) The date of successful repair of the leak.
    (x) A list of identification numbers for equipment that are 
designated for no detectable emissions under the provisions of Sec.  
60.482-4a(a). The designation of equipment subject to the provisions of 
Sec.  60.482-4a(a) must be signed by the owner or operator.


Sec.  60.5422  What are my additional reporting requirements for my 
affected facility subject to VOC requirements for onshore natural gas 
processing plants?

    (a) You must comply with the requirements of paragraphs (b) and (c) 
of this section in addition to the requirements of Sec.  60.487a(a), 
(b), (c)(2)(i) through (iv), and (c)(2)(vii) through (viii).
    (b) An owner or operator must include the following information in 
the initial semiannual report in addition to the information required 
in Sec.  60.487a(b)(1) through (4): Number of pressure relief devices 
subject to the requirements of Sec.  60.5401(b) except for those 
pressure relief devices designated for no detectable emissions under 
the provisions of Sec.  60.482-4a(a) and those pressure relief devices 
complying with Sec.  60.482-4a(c).
    (c) An owner or operator must include the following information in 
all semiannual reports in addition to the information required in Sec.  
60.487a(c)(2)(i) through (vi):

[[Page 49564]]

    (1) Number of pressure relief devices for which leaks were detected 
as required in Sec.  60.5401(b)(2); and
    (2) Number of pressure relief devices for which leaks were not 
repaired as required in Sec.  60.5401(b)(3).


Sec.  60.5423  What additional recordkeeping and reporting requirements 
apply to my sweetening unit affected facilities at onshore natural gas 
processing plants?

    (a) You must retain records of the calculations and measurements 
required in Sec.  60.5405(a) and (b) and Sec.  60.5407(a) through (g) 
for at least 2 years following the date of the measurements. This 
requirement is included under Sec.  60.7(d) of the General Provisions.
    (b) You must submit a report of excess emissions to the 
Administrator in your annual report if you had excess emissions during 
the reporting period. For the purpose of these reports, excess 
emissions are defined as:
    (1) Any 24-hour period (at consistent intervals) during which the 
average sulfur emission reduction efficiency (R) is less than the 
minimum required efficiency (Z).
    (2) For any affected facility electing to comply with the 
provisions of Sec.  60.5407(b)(2), any 24-hour period during which the 
average temperature of the gases leaving the combustion zone of an 
incinerator is less than the appropriate operating temperature as 
determined during the most recent performance test in accordance with 
the provisions of Sec.  60.5407(b)(2). Each 24-hour period must consist 
of at least 96 temperature measurements equally spaced over the 24 
hours.
    (c) To certify that a facility is exempt from the control 
requirements of these standards, for each facility with a design 
capacity less that 2 LT/D of H2S in the acid gas (expressed 
as sulfur) you must keep, for the life of the facility, an analysis 
demonstrating that the facility's design capacity is less than 2 LT/D 
of H2S expressed as sulfur.
    (d) If you elect to comply with Sec.  60.5407(e) you must keep, for 
the life of the facility, a record demonstrating that the facility's 
design capacity is less than 150 LT/D of H2S expressed as 
sulfur.
    (e) The requirements of paragraph (b) of this section remain in 
force until and unless the EPA, in delegating enforcement authority to 
a state under section 111(c) of the Act, approves reporting 
requirements or an alternative means of compliance surveillance adopted 
by such state. In that event, affected sources within the state will be 
relieved of obligation to comply with paragraph (b) of this section, 
provided that they comply with the requirements established by the 
state.


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

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


Sec.  60.5430  What definitions apply to this subpart?

    As used in this subpart, all terms not defined herein shall have 
the meaning given them in the Act, in subpart A or subpart VVa of part 
60; and the following terms shall have the specific meanings given 
them.
    Acid gas means a gas stream of hydrogen sulfide (H2S) 
and carbon dioxide (CO2) that has been separated from sour 
natural gas by a sweetening unit.
    Affirmative defense means, in the context of an enforcement 
proceeding, a response or defense put forward by a defendant, regarding 
which the defendant has the burden of proof, and the merits of which 
are independently and objectively evaluated in a judicial or 
administrative proceeding.
    Alaskan North Slope means the approximately 69,000 square-mile area 
extending from the Brooks Range to the Arctic Ocean.
    API Gravity means the weight per unit volume of hydrocarbon liquids 
as measured by a system recommended by the American Petroleum Institute 
(API) and is expressed in degrees.
    Bleed rate means the rate in standard cubic feet per hour at which 
natural gas is continuously vented (bleeds) from a pneumatic 
controller.
    Centrifugal compressor means any machine for raising the pressure 
of a natural gas by drawing in low pressure natural gas and discharging 
significantly higher pressure natural gas by means of mechanical 
rotating vanes or impellers. Screw, sliding vane, and liquid ring 
compressors are not centrifugal compressors for the purposes of this 
subpart.
    City gate means the delivery point at which natural gas is 
transferred from a transmission pipeline to the local gas utility.
    Completion combustion device means any ignition device, installed 
horizontally or vertically, used in exploration and production 
operations to combust otherwise vented emissions from completions.
    Compressor station means any permanent combination of one or more 
compressors that move natural gas at increased pressure from fields, in 
transmission pipelines, or into storage.
    Continuous bleed means a continuous flow of pneumatic supply 
natural gas to the process control device (e.g., level control, 
temperature control, pressure control) where the supply gas pressure is 
modulated by the process condition, and then flows to the valve 
controller where the signal is compared with the process set-point to 
adjust gas pressure in the valve actuator.
    Custody transfer means the transfer of natural gas after processing 
and/or treatment in the producing operations, or from storage vessels 
or automatic transfer facilities or other such equipment, including 
product loading racks, to pipelines or any other forms of 
transportation.
    Dehydrator means a device in which an absorbent directly contacts a 
natural gas stream and absorbs water in a contact tower or absorption 
column (absorber).
    Deviation means any instance in which an affected source subject to 
this subpart, or an owner or operator of such a source:
    (1) Fails to meet any requirement or obligation established by this 
subpart including, but not limited to, any emission limit, operating 
limit, or work practice standard;
    (2) Fails to meet any term or condition that is adopted to 
implement an applicable requirement in this subpart and that is 
included in the operating permit for any affected source required to 
obtain such a permit; or
    (3) Fails to meet any emission limit, operating limit, or work 
practice standard in this subpart during startup, shutdown, or 
malfunction, regardless of whether or not such failure is permitted by 
this subpart.
    Delineation well means a well drilled in order to determine the 
boundary of a field or producing reservoir.
    Equipment means each pump, pressure relief device, open-ended valve 
or line, valve, and flange or other connector that is in VOC service or 
in wet gas service, and any device or system required by this subpart.
    Field gas means feedstock gas entering the natural gas processing 
plant.
    Field gas gathering means the system used transport field gas from 
a field to the main pipeline in the area.
    Flare means a thermal oxidation system using an open (without 
enclosure) flame. Completion combustion devices as defined in this 
section are not considered flares.
    Flow line means a pipeline used to transport oil and/or gas from 
the well to a processing facility, a mainline pipeline, re-injection, 
or other useful purpose.
    Flowback means the process of allowing fluids to flow from a 
natural

[[Page 49565]]

gas well following a treatment, either in preparation for a subsequent 
phase of treatment or in preparation for cleanup and returning the well 
to production. The flowback period begins when material introduced into 
the well during the treatment returns to the surface immediately 
following hydraulic fracturing or refracturing. The flowback period 
ends with either well shut in or when the well is producing 
continuously to the flow line or to a storage vessel for collection, 
whichever occurs first.
    Gas processing plant process unit means equipment assembled for the 
extraction of natural gas liquids from field gas, the fractionation of 
the liquids into natural gas products, or other operations associated 
with the processing of natural gas products. A process unit can operate 
independently if supplied with sufficient feed or raw materials and 
sufficient storage facilities for the products.
    Gas well or natural gas well means an onshore well drilled 
principally for production of natural gas.
    Hydraulic fracturing or refracturing means the process of directing 
pressurized fluids containing any combination of water, proppant, and 
any added chemicals to penetrate tight formations, such as shale or 
coal formations, that subsequently require high rate, extended flowback 
to expel fracture fluids and solids during completions.
    Hydraulic refracturing means conducting a subsequent hydraulic 
fracturing operation at a well that has previously undergone a 
hydraulic fracturing operation.
    In light liquid service means that the piece of equipment contains 
a liquid that meets the conditions specified in Sec.  60.485a(e) or 
Sec.  60.5401(g)(2) of this part.
    In wet gas service means that a compressor or piece of equipment 
contains or contacts the field gas before the extraction step at a gas 
processing plant process unit.
    Intermittent/snap-action pneumatic controller means a pneumatic 
controller that vents non-continuously.
    Liquefied natural gas unit means a unit used to cool natural gas to 
the point at which it is condensed into a liquid which is colorless, 
odorless, non-corrosive and non-toxic.
    Low pressure gas well means a well with reservoir pressure and 
vertical well depth such that 0.445 times the reservoir pressure (in 
psia) minus 0.038 times the vertical well depth (in feet) minus 67.578 
psia is less than the flow line pressure at the sales meter.
    Natural gas-driven pneumatic controller means a pneumatic 
controller powered by pressurized natural gas.
    Natural gas liquids means the hydrocarbons, such as ethane, 
propane, butane, and pentane that are extracted from field gas.
    Natural gas processing plant (gas plant) means any processing site 
engaged in the extraction of natural gas liquids from field gas, 
fractionation of mixed natural gas liquids to natural gas products, or 
both. A Joule-Thompson valve, a dew point depression valve, or an 
isolated or standalone Joule-Thompson skid is not a natural gas 
processing plant.
    Natural gas transmission means the pipelines used for the long 
distance transport of natural gas (excluding processing). Specific 
equipment used in natural gas transmission includes the land, mains, 
valves, meters, boosters, regulators, storage vessels, dehydrators, 
compressors, and their driving units and appurtenances, and equipment 
used for transporting gas from a production plant, delivery point of 
purchased gas, gathering system, storage area, or other wholesale 
source of gas to one or more distribution area(s).
    Nonfractionating plant means any gas plant that does not 
fractionate mixed natural gas liquids into natural gas products.
    Non-natural gas-driven pneumatic controller means an instrument 
that is actuated using other sources of power than pressurized natural 
gas; examples include solar, electric, and instrument air.
    Onshore means all facilities except those that are located in the 
territorial seas or on the outer continental shelf.
    Pneumatic controller means an automated instrument used for 
maintaining a process condition such as liquid level, pressure, delta-
pressure and temperature.
    Pressure vessel means a storage vessel that is used to store 
liquids or gases and is designed not to vent to the atmosphere as a 
result of compression of the vapor headspace in the pressure vessel 
during filling of the pressure vessel to its design capacity.
    Process unit means components assembled for the extraction of 
natural gas liquids from field gas, the fractionation of the liquids 
into natural gas products, or other operations associated with the 
processing of natural gas products. A process unit can operate 
independently if supplied with sufficient feed or raw materials and 
sufficient storage facilities for the products.
    Reciprocating compressor means a piece of equipment that increases 
the pressure of a process gas by positive displacement, employing 
linear movement of the driveshaft.
    Reciprocating compressor rod packing means a series of flexible 
rings in machined metal cups that fit around the reciprocating 
compressor piston rod to create a seal limiting the amount of 
compressed natural gas that escapes to the atmosphere.
    Reduced emissions completion means a well completion following 
fracturing or refracturing where gas flowback that is otherwise vented 
is captured, cleaned, and routed to the flow line or collection system, 
re-injected into the well or another well, used as an on-site fuel 
source, or used for other useful purpose that a purchased fuel or raw 
material would serve, with no direct release to the atmosphere.
    Reduced sulfur compounds means H2S, carbonyl sulfide 
(COS), and carbon disulfide (CS2).
    Responsible official means one of the following:
    (1) For a corporation: A president, secretary, treasurer, or vice-
president of the corporation in charge of a principal business 
function, or any other person who performs similar policy or decision-
making functions for the corporation, or a duly authorized 
representative of such person if the representative is responsible for 
the overall operation of one or more manufacturing, production, or 
operating facilities applying for or subject to a permit and either:
    (i) The facilities employ more than 250 persons or have gross 
annual sales or expenditures exceeding $25 million (in second quarter 
1980 dollars); or
    (ii) The delegation of authority to such representatives is 
approved in advance by the permitting authority;
    (2) For a partnership or sole proprietorship: A general partner or 
the proprietor, respectively;
    (3) For a municipality, State, Federal, or other public agency: 
Either a principal executive officer or ranking elected official. For 
the purposes of this part, a principal executive officer of a Federal 
agency includes the chief executive officer having responsibility for 
the overall operations of a principal geographic unit of the agency 
(e.g., a Regional Administrator of EPA); or
    (4) For affected facilities:
    (i) The designated representative in so far as actions, standards, 
requirements, or prohibitions under title IV of the Clean Air Act or 
the regulations promulgated thereunder are concerned; or
    (ii) The designated representative for any other purposes under 
part 60.

[[Page 49566]]

    Routed to a process or route to a process means the emissions are 
conveyed via a closed vent system to any enclosed portion of a process 
unit where the emissions are predominantly recycled and/or consumed in 
the same manner as a material that fulfills the same function in the 
process and/or transformed by chemical reaction into materials that are 
not regulated materials and/or incorporated into a product; and/or 
recovered.
    Salable quality gas means natural gas that meets the composition, 
moisture, or other limits set by the purchaser of the natural gas, 
regardless of whether such gas is sold.
    Storage vessel means a unit that is constructed primarily of 
nonearthen materials (such as wood, concrete, steel, fiberglass, or 
plastic) which provides structural support and is designed to contain 
an accumulation of liquids or other materials. The following are not 
considered storage vessels:
    (1) Vessels that are skid-mounted or permanently attached to 
something that is mobile (such as trucks, railcars, barges or ships), 
and are intended to be located at a site for less than 180 consecutive 
days. If you do not keep or are not able to produce records, as 
required by Sec.  60.5420(c)(5)(iv), showing that the vessel has been 
located at a site for less than 180 consecutive days, the vessel 
described herein is considered to be a storage vessel since the 
original vessel was first located at the site.
    (2) Process vessels such as surge control vessels, bottoms 
receivers or knockout vessels.
    (3) Pressure vessels designed to operate in excess of 204.9 
kilopascals and without emissions to the atmosphere.
    Sulfur production rate means the rate of liquid sulfur accumulation 
from the sulfur recovery unit.
    Sulfur recovery unit means a process device that recovers element 
sulfur from acid gas.
    Surface site means any combination of one or more graded pad sites, 
gravel pad sites, foundations, platforms, or the immediate physical 
location upon which equipment is physically affixed.
    Sweetening unit means a process device that removes hydrogen 
sulfide and/or carbon dioxide from the sour natural gas stream.
    Total Reduced Sulfur (TRS) means the sum of the sulfur compounds 
hydrogen sulfide, methyl mercaptan, dimethyl sulfide, and dimethyl 
disulfide as measured by Method 16 of appendix A to part 60 of this 
chapter.
    Total SO2 equivalents means the sum of volumetric or mass 
concentrations of the sulfur compounds obtained by adding the quantity 
existing as SO2 to the quantity of SO2 that would 
be obtained if all reduced sulfur compounds were converted to 
SO2 (ppmv or kg/dscm (lb/dscf)).
    Underground storage vessel means a storage vessel stored below 
ground.
    Well means an oil or gas well, a hole drilled for the purpose of 
producing oil or gas, or a well into which fluids are injected.
    Well completion means the process that allows for the flowback of 
petroleum or natural gas from newly drilled wells to expel drilling and 
reservoir fluids and tests the reservoir flow characteristics, which 
may vent produced hydrocarbons to the atmosphere via an open pit or 
tank.
    Well completion operation means any well completion with hydraulic 
fracturing or refracturing occurring at a gas well affected facility.
    Well site means one or more areas that are directly disturbed 
during the drilling and subsequent operation of, or affected by, 
production facilities directly associated with any oil well, gas well, 
or injection well and its associated well pad.
    Wellhead means the piping, casing, tubing and connected valves 
protruding above the earth's surface for an oil and/or natural gas 
well. The wellhead ends where the flow line connects to a wellhead 
valve. The wellhead does not include other equipment at the well site 
except for any conveyance through which gas is vented to the 
atmosphere.
    Wildcat well means a well outside known fields or the first well 
drilled in an oil or gas field where no other oil and gas production 
exists.

       Table 1 to Subpart OOOO of Part 60--Required Minimum Initial SO2 Emission Reduction Efficiency (Zi)
----------------------------------------------------------------------------------------------------------------
                                                               Sulfur feed rate (X), LT/D
                                       -------------------------------------------------------------------------
    H2S content of acid gas (Y), %        2.0 <= X <=                               15.0 < X <=
                                              5.0            5.0 < X <= 15.0           300.0         X > 300.0
----------------------------------------------------------------------------------------------------------------
Y >= 50...............................            79.0   88.51X\0.0101\Y\0.0125\ or 99.9, whichever is smaller.
                                                       ---------------------------------------------------------
20 <= Y < 50..........................            79.0       88.5X\0.0101\Y\0.0125\ or 97.9,                97.9
                                                                  whichever is smaller.
                                                       ------------------------------------------
10 <= Y < 20..........................            79.0  88.5X\0.0101\Y\0.0125\              93.5            93.5
                                                         or 97.9, whichever is
                                                         smaller.
Y < 10................................            79.0  79.0....................            79.0            79.0
----------------------------------------------------------------------------------------------------------------


           Table 2 to Subpart OOOO of Part 60--Required Minimum SO2 Emission Reduction Efficiency (Zc)
----------------------------------------------------------------------------------------------------------------
                                                               Sulfur feed rate (X), LT/D
                                       -------------------------------------------------------------------------
    H2S content of acid gas (Y), %        2.0 <= X <=                               15.0 < X <=
                                              5.0            5.0 < X <= 15.0           300.0         X > 300.0
----------------------------------------------------------------------------------------------------------------
Y >= 50...............................            74.0   85.35X\0.0144\Y\0.0128\ or 99.9, whichever is smaller.
                                                       ---------------------------------------------------------
20 <= Y < 50..........................            74.0      85.35X\0.0144\Y\0.0128\ or 97.9,                97.5
                                                                  whichever is smaller.
                                                       ---------------------------------------------------------
10 <= Y < 20..........................            74.0      85.35X\0.0144\Y\0.0128\ or 90.8,                90.8
                                                                  whichever is smaller.
                                                       ---------------------------------------------------------
Y < 10................................            74.0  74.0....................            74.0            74.0
----------------------------------------------------------------------------------------------------------------
E = The sulfur emission rate expressed as elemental sulfur, kilograms per hour (kg/hr) [pounds per hour (lb/
  hr)], rounded to one decimal place.
R = The sulfur emission reduction efficiency achieved in percent, carried to one decimal place.
S = The sulfur production rate, kilograms per hour (kg/hr) [pounds per hour (lb/hr)], rounded to one decimal
  place.

[[Page 49567]]

 
X = The sulfur feed rate from the sweetening unit (i.e., the H2S in the acid gas), expressed as sulfur, Mg/D(LT/
  D), rounded to one decimal place.
Y = The sulfur content of the acid gas from the sweetening unit, expressed as mole percent H2S (dry basis)
  rounded to one decimal place.
Z = The minimum required sulfur dioxide (SO2) emission reduction efficiency, expressed as percent carried to one
  decimal place. Zi refers to the reduction efficiency required at the initial performance test. Zc refers to
  the reduction efficiency required on a continuous basis after compliance with Zi has been demonstrated.

    As stated in Sec.  60.5425, you must comply with the following 
applicable General Provisions:

             Table 3 to Subpart OOOO of Part 60--Applicability of General Provisions to Subpart OOOO
----------------------------------------------------------------------------------------------------------------
General  provisions  citation     Subject of citation         Applies to  subpart?             Explanation
----------------------------------------------------------------------------------------------------------------
Sec.   60.1..................  General applicability of  Yes.                           ........................
                                the General Provisions.
Sec.   60.2..................  Definitions.............  Yes..........................  Additional terms defined
                                                                                         in Sec.   60.5430.
Sec.   60.3..................  Units and abbreviations.  Yes.                           ........................
Sec.   60.4..................  Address.................  Yes.                           ........................
Sec.   60.5..................  Determination of          Yes.                           ........................
                                construction or
                                modification.
Sec.   60.6..................  Review of plans.........  Yes.                           ........................
Sec.   60.7..................  Notification and record   Yes..........................  Except that Sec.   60.7
                                keeping.                                                 only applies as
                                                                                         specified in Sec.
                                                                                         60.5420(a).
Sec.   60.8..................  Performance tests.......  Yes..........................  Performance testing is
                                                                                         required for control
                                                                                         devices used on storage
                                                                                         vessels and centrifugal
                                                                                         compressors.
Sec.   60.9..................  Availability of           Yes.                           ........................
                                information.
Sec.   60.10.................  State authority.........  Yes.                           ........................
Sec.   60.11.................  Compliance with           No...........................  Requirements are
                                standards and                                            specified in subpart
                                maintenance                                              OOOO.
                                requirements.
Sec.   60.12.................  Circumvention...........  Yes.                           ........................
Sec.   60.13.................  Monitoring requirements.  Yes..........................  Continuous monitors are
                                                                                         required for storage
                                                                                         vessels.
Sec.   60.14.................  Modification............  Yes.                           ........................
Sec.   60.15.................  Reconstruction..........  Yes.                           ........................
Sec.   60.16.................  Priority list...........  Yes.                           ........................
Sec.   60.17.................  Incorporations by         Yes.                           ........................
                                reference.
Sec.   60.18.................  General control device    Yes..........................  Except that Sec.   60.18
                                requirements.                                            does not apply to
                                                                                         flares.
Sec.   60.19.................  General notification and  Yes.                           ........................
                                reporting requirement.
----------------------------------------------------------------------------------------------------------------

PART 63--NATIONAL EMISSION STANDARDS FOR HAZARDOUS AIR POLLUTANTS 
FOR SOURCE CATEGORIES

0
8. The authority citation for part 63 continues to read as follows:

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


0
9. Section 63.14 is amended by:
0
a. Revising paragraphs (b) introductory text, (b)(28), and (b)(64);
0
b. Adding paragraphs (b)(73), (74), and (75); and
0
c. Revising paragraphs (i) introductory text and (i)(1) to read as 
follows:


Sec.  63.14  Incorporations by reference.

* * * * *
    (b) The following materials are available for purchase from at 
least one of the following addresses: American Society for Testing and 
Materials (ASTM), 100 Barr Harbor Drive, Post Office Box C700, West 
Conshohocken, PA 19428-2959, Telephone (610) 832-9585, and are also 
available at the following Web site: http://www.astm.org; or ProQuest, 
789 East Eisenhower Parkway, Ann Arbor, MI 48106-1346, Telephone (734) 
761-4700, and are also available at the following Web site: http://www.proquest.com.
* * * * *
    (28) ASTM D6420-99 (Reapproved 2004), Standard Test Method for 
Determination of Gaseous Organic Compounds by Direct Interface Gas 
Chromatography-Mass Spectrometry (Approved October 1, 2004), IBR 
approved for Sec. Sec.  60.485(g), 60.485a(g), 63.772(a), 63.772(e), 
63.1282(a), 63.1282(d), 63.2351(b), 63.2354(b) and table 8 to subpart 
HHHHHHH of this part.
* * * * *
    (64) ASTM D6522-00 (Reapproved 2005), Standard Test Method for 
Determination of Nitrogen Oxides, Carbon Monoxide, and Oxygen 
Concentrations in Emissions from Natural Gas Fired Reciprocating 
Engines, Combustion Turbines, Boilers, and Process Heaters Using 
Portable Analyzers, approved October 1, 2005, IBR approved for table 4 
to subpart ZZZZ of this part, table 5 to subpart DDDDD of this part, 
table 4 to subpart JJJJJJ of this part and Sec. Sec.  63.772(e), 
63.772(h), 63.1282(d) and 63.1282(g).
* * * * *
    (73) ASTM D1945-03 (Reapproved 2010) Standard Test Method for 
Analysis of Natural Gas by Gas Chromatography (Approved January 1, 
2010), IBR approved for Sec. Sec.  63.772(h) and 63.1282(g).
    (74) ASTM D3588-98 (Reapproved 2003) Standard Practice for 
Calculating Heat Value, Compressibility Factor, and Relative Density of 
Gaseous Fuels (Approved May 10, 2003), IBR approved for Sec. Sec.  
63.772(h) and 63.1282(g).
    (75) ASTM D4891-89 (Reapproved 2006) Standard Test Method for 
Heating Value of Gases in Natural Gas Range by Stoichiometric 
Combustion (Approved June 1, 2006), IBR approved for Sec. Sec.  
63.772(h) and 63.1282(g).
* * * * *
    (i) The following material is available for purchase from at least 
one of the following addresses: American Society of Mechanical 
Engineers (ASME), Three Park Avenue, New York, NY 10016-

[[Page 49568]]

5990, Telephone (800) 843-2763, and are also available at the following 
Web site: http://www.asme.org; or HIS, Incorporated, 15 Inverness Way 
East, Englewood, CO 80112, Telephone (877) 413-5184, and are also 
available at the following Web site: http://global.ihs.com.
    (1) ANSI/ASME PTC 19.10-1981, Flue and Exhaust Gas Analyses [Part 
10, Instruments and Apparatus], issued August 31, 1981 IBR approved for 
Sec. Sec.  63.309(k), 63.772(e), 63.772(h), 63.865(b), 63.1282(d), 
63.1282(g), 63.3166(a), 63.3360(e), 63.3545(a), 63.3555(a), 63.4166(a), 
63.4362(a), 63.4766(a), 63.4965(a), 63.5160(d), 63.9307(c), 63.9323(a), 
63.11148(e), 63.11155(e), 63.11162(f), 63.11163(g), 63.11410(j), 
63.11551(a) and 63.11646(a), 63.11945, table 5 to subpart DDDDD of this 
part, table 4 to subpart JJJJJ of this part, table 5 to subpart UUUUU 
of this part and table 1 to subpart ZZZZZ of this part.
* * * * *

Subpart HH--[Amended]

0
10. Section 63.760 is amended by:
0
a. Revising paragraph (a)(1) introductory text;
0
b. Revising paragraph (a)(1)(i);
0
c. Revising paragraph (a)(1)(iii);
0
d. Revising paragraph (a)(2);
0
e. Revising paragraph (b)(1)(i);
0
f. Adding paragraph (c);
0
g. Revising paragraph (f) introductory text;
0
h. Revising paragraph (f)(1);
0
i. Revising paragraph (f)(2);
0
j. Adding paragraphs (f)(7), (f)(8), and (f)(9); and
0
k. Removing and reserving paragraph (g)(1).
    The revisions and additions read as follows:


Sec.  63.760  Applicability and designation of affected source.

    (a) * * *
    (1) Facilities that are major or area sources of hazardous air 
pollutants (HAP) as defined in Sec.  63.761. Emissions for major source 
determination purposes can be estimated using the maximum natural gas 
or hydrocarbon liquid throughput, as appropriate, calculated in 
paragraphs (a)(1)(i) through (iii) of this section. As an alternative 
to calculating the maximum natural gas or hydrocarbon liquid 
throughput, the owner or operator of a new or existing source may use 
the facility's design maximum natural gas or hydrocarbon liquid 
throughput to estimate the maximum potential emissions. Other means to 
determine the facility's major source status are allowed, provided the 
information is documented and recorded to the Administrator's 
satisfaction in accordance with Sec.  63.10(b)(3). A facility that is 
determined to be an area source, but subsequently increases its 
emissions or its potential to emit above the major source levels, and 
becomes a major source, must comply thereafter with all provisions of 
this subpart applicable to a major source starting on the applicable 
compliance date specified in paragraph (f) of this section. Nothing in 
this paragraph is intended to preclude a source from limiting its 
potential to emit through other appropriate mechanisms that may be 
available through the permitting authority.
    (i) If the owner or operator documents, to the Administrator's 
satisfaction, a decline in annual natural gas or hydrocarbon liquid 
throughput, as appropriate, each year for the 5 years prior to October 
15, 2012, the owner or operator shall calculate the maximum natural gas 
or hydrocarbon liquid throughput used to determine maximum potential 
emissions according to the requirements specified in paragraph 
(a)(1)(i)(A) of this section. In all other circumstances, the owner or 
operator shall calculate the maximum throughput used to determine 
whether a facility is a major source in accordance with the 
requirements specified in paragraph (a)(1)(i)(B) of this section.
    (A) The maximum natural gas or hydrocarbon liquid throughput is the 
average of the annual natural gas or hydrocarbon liquid throughput for 
the 3 years prior to October 15, 2012, multiplied by a factor of 1.2.
    (B) The maximum natural gas or hydrocarbon liquid throughput is the 
highest annual natural gas or hydrocarbon liquid throughput over the 5 
years prior to October 15, 2012, multiplied by a factor of 1.2.
* * * * *
    (iii) The owner or operator shall determine the maximum values for 
other parameters used to calculate emissions as the maximum for the 
period over which the maximum natural gas or hydrocarbon liquid 
throughput is determined in accordance with paragraph (a)(1)(i)(A) or 
(B) of this section. Parameters, other than glycol circulation rate, 
shall be based on either highest measured values or annual average. For 
estimating maximum potential emissions from glycol dehydration units, 
the glycol circulation rate used in the calculation shall be the unit's 
maximum rate under its physical and operational design consistent with 
the definition of potential to emit in Sec.  63.2.
    (2) Facilities that process, upgrade, or store hydrocarbon liquids.
* * * * *
    (b) * * *
    (1) * * *
    (i) Each glycol dehydration unit as specified in paragraphs 
(b)(1)(i)(A) through (C) of this section.
    (A) Each large glycol dehydration unit;
    (B) Each small glycol dehydration unit for which construction 
commenced on or before August 23, 2011, is an existing small glycol 
dehydration unit; and
    (C) Each small glycol dehydration unit for which construction 
commenced after August 23, 2011, is a new small glycol dehydration 
unit.
* * * * *
    (c) Any source that determines it is not a major source but has 
actual emissions of 5 tons per year or more of a single HAP, or 12.5 
tons per year or more of a combination of HAP (i.e., 50 percent of the 
major source thresholds), shall update its major source determination 
within 1 year of the prior determination or October 15, 2012, whichever 
is later, and each year thereafter, using gas composition data measured 
during the preceding 12 months.
* * * * *
    (f) The owner or operator of an affected major source shall achieve 
compliance with the provisions of this subpart by the dates specified 
in paragraphs (f)(1), (2), and (f)(7) through (9) of this section. The 
owner or operator of an affected area source shall achieve compliance 
with the provisions of this subpart by the dates specified in 
paragraphs (f)(3) through (6) of this section.
    (1) Except as specified in paragraphs (f)(7) through (9) of this 
section, the owner or operator of an affected major source, the 
construction or reconstruction of which commenced before February 6, 
1998, shall achieve compliance with the applicable provisions of this 
subpart no later than June 17, 2002, except as provided for in Sec.  
63.6(i). The owner or operator of an area source, the construction or 
reconstruction of which commenced before February 6, 1998, that 
increases its emissions of (or its potential to emit) HAP such that the 
source becomes a major source that is subject to this subpart shall 
comply with this subpart 3 years after becoming a major source.
    (2) Except as specified in paragraphs (f)(7) through (9) of this 
section, the owner or operator of an affected major source, the 
construction or reconstruction of which commences on

[[Page 49569]]

or after February 6, 1998, shall achieve compliance with the applicable 
provisions of this subpart immediately upon initial startup or June 17, 
1999, whichever date is later. Area sources, other than production 
field facilities identified in (f)(9) of this section, the construction 
or reconstruction of which commences on or after February 6, 1998, that 
become major sources shall comply with the provisions of this standard 
immediately upon becoming a major source.
* * * * *
    (7) Each affected existing small glycol dehydration unit, as 
defined in Sec.  63.761, located at a major source, that commenced 
construction before August 23, 2011, must achieve compliance no later 
than October 15, 2015, except as provided in Sec.  63.6(i).
    (8) Each affected new small glycol dehydration unit, as defined in 
Sec.  63.761, located at a major source, that commenced construction on 
or after August 23, 2011, must achieve compliance immediately upon 
initial startup or October 15, 2012, whichever is later.
    (9) A production field facility, as defined in Sec.  63.761, 
constructed on or before August 23, 2011, that was previously 
determined to be an area source but becomes a major source (as defined 
in paragraph 3 of the major source definition in Sec.  63.761) on the 
October 15, 2012 must achieve compliance no later than October 15, 
2015, except as provided in Sec.  63.6(i).
* * * * *

0
11. Section 63.761 is amended by:
0
a. Adding, in alphabetical order, definitions for the terms 
``affirmative defense,'' ``BTEX,'' ``flare,'' ``large glycol 
dehydration unit,'' ``responsible official'' and ``small glycol 
dehydration unit'';
0
b. Revising the definitions for ``associated equipment,'' ``glycol 
dehydration unit baseline operations,'' and ``storage vessel''; and
0
c. Revising paragraph (3) of the definition for ``major source'' to 
read as follows:


Sec.  63.761  Definitions.

* * * * *
    Affirmative defense means, in the context of an enforcement 
proceeding, a response or defense put forward by a defendant, regarding 
which the defendant has the burden of proof, and the merits of which 
are independently and objectively evaluated in a judicial or 
administrative proceeding.
* * * * *
    Associated equipment, as used in this subpart and as referred to in 
section 112(n)(4) of the Act, means equipment associated with an oil or 
natural gas exploration or production well, and includes all equipment 
from the wellbore to the point of custody transfer, except glycol 
dehydration units and storage vessels.
* * * * *
    BTEX means benzene, toluene, ethyl benzene and xylene.
* * * * *
    Flare means a thermal oxidation system using an open flame (i.e., 
without enclosure).
* * * * *
    Glycol dehydration unit baseline operations means operations 
representative of the large glycol dehydration unit operations as of 
June 17, 1999 and the small glycol dehydrator unit operations as of 
August 23, 2011. For the purposes of this subpart, for determining the 
percentage of overall HAP emission reduction attributable to process 
modifications, baseline operations shall be parameter values 
(including, but not limited to, glycol circulation rate or glycol-HAP 
absorbency) that represent actual long-term conditions (i.e., at least 
1 year). Glycol dehydration units in operation for less than 1 year 
shall document that the parameter values represent expected long-term 
operating conditions had process modifications not been made.
* * * * *
    Large glycol dehydration unit means a glycol dehydration unit with 
an actual annual average natural gas flowrate equal to or greater than 
85 thousand standard cubic meters per day and actual annual average 
benzene emissions equal to or greater than 0.90 Mg/yr, determined 
according to Sec.  63.772(b). A glycol dehydration unit complying with 
the 0.9 Mg/yr control option under Sec.  63.765(b)(1)(ii) is considered 
to be a large dehydrator.
    Major source * * *
    (3) For facilities that are production field facilities, only HAP 
emissions from glycol dehydration units and storage vessels shall be 
aggregated for a major source determination. For facilities that are 
not production field facilities, HAP emissions from all HAP emission 
units shall be aggregated for a major source determination.
* * * * *
    Responsible official means one of the following:
    (1) For a corporation: A president, secretary, treasurer, or vice-
president of the corporation in charge of a principal business 
function, or any other person who performs similar policy or decision-
making functions for the corporation, or a duly authorized 
representative of such person if the representative is responsible for 
the overall operation of one or more manufacturing, production, or 
operating facilities applying for or subject to a permit and either:
    (i) The facilities employ more than 250 persons or have gross 
annual sales or expenditures exceeding $25 million (in second quarter 
1980 dollars); or
    (ii) The delegation of authority to such representatives is 
approved in advance by the permitting authority;
    (2) For a partnership or sole proprietorship: a general partner or 
the proprietor, respectively;
    (3) For a municipality, State, Federal, or other public agency: 
Either a principal executive officer or ranking elected official. For 
the purposes of this part, a principal executive officer of a Federal 
agency includes the chief executive officer having responsibility for 
the overall operations of a principal geographic unit of the agency 
(e.g., a Regional Administrator of EPA); or
    (4) For affected sources:
    (i) The designated representative in so far as actions, standards, 
requirements, or prohibitions under title IV of the Act or the 
regulations promulgated thereunder are concerned; and
    (ii) The designated representative for any other purposes under 
part 70.
* * * * *
    Small glycol dehydration unit means a glycol dehydration unit, 
located at a major source, with an actual annual average natural gas 
flowrate less than 85 thousand standard cubic meters per day or actual 
annual average benzene emissions less than 0.90 Mg/yr, determined 
according to Sec.  63.772(b).
* * * * *
    Storage vessel means a tank or other vessel that is designed to 
contain an accumulation of crude oil, condensate, intermediate 
hydrocarbon liquids, or produced water and that is constructed 
primarily of non-earthen materials (e.g., wood, concrete, steel, 
plastic) that provide structural support. The following process units 
are not considered storage vessels: Surge control vessels and knockout 
vessels.
* * * * *

0
12. Section 63.762 is revised to read as follows:


Sec.  63.762  Affirmative defense for violations of emission standards 
during malfunction.

    (a) The provisions set forth in this subpart shall apply at all 
times.
    (b) [Reserved]
    (c) [Reserved]
    (d) In response to an action to enforce the standards set forth in 
this subpart, you may assert an affirmative defense to

[[Page 49570]]

a claim for civil penalties for violations of such standards that are 
caused by malfunction, as defined in 40 CFR 63.2. Appropriate penalties 
may be assessed; however, if you fail to meet your burden of proving 
all of the requirements in the affirmative defense, the affirmative 
defense shall not be available for claims for injunctive relief.
    (1) To establish the affirmative defense in any action to enforce 
such a standard, you must timely meet the reporting requirements in 
paragraph (d)(2) of this section, and must prove by a preponderance of 
evidence that:
    (i) The violation:
    (A) Was caused by a sudden, infrequent, and unavoidable failure of 
air pollution control equipment, process equipment, or a process to 
operate in a normal or usual manner; and
    (B) Could not have been prevented through careful planning, proper 
design or better operation and maintenance practices; and
    (C) Did not stem from any activity or event that could have been 
foreseen and avoided, or planned for; and
    (D) Was not part of a recurring pattern indicative of inadequate 
design, operation, or maintenance; and
    (ii) Repairs were made as expeditiously as possible when a 
violation occurred. Off-shift and overtime labor were used, to the 
extent practicable to make these repairs; and
    (iii) The frequency, amount and duration of the violation 
(including any bypass) were minimized to the maximum extent 
practicable; and
    (iv) If the violation resulted from a bypass of control equipment 
or a process, then the bypass was unavoidable to prevent loss of life, 
personal injury, or severe property damage; and
    (v) All possible steps were taken to minimize the impact of the 
violation on ambient air quality, the environment, and human health; 
and
    (vi) All emissions monitoring and control systems were kept in 
operation if at all possible, consistent with safety and good air 
pollution control practices; and
    (vii) All of the actions in response to the violation were 
documented by properly signed, contemporaneous operating logs; and
    (viii) At all times, the affected source was operated in a manner 
consistent with good practices for minimizing emissions; and
    (ix) A written root cause analysis has been prepared, the purpose 
of which is to determine, correct, and eliminate the primary causes of 
the malfunction and the violation resulting from the malfunction event 
at issue. The analysis shall also specify, using best monitoring 
methods and engineering judgment, the amount of any emissions that were 
the result of the malfunction.
    (2) Report. The owner or operator seeking to assert an affirmative 
defense shall submit a written report to the Administrator with all 
necessary supporting documentation, that it has met the requirements 
set forth in paragraph (d)(1) of this section. This affirmative defense 
report shall be included in the first periodic compliance, deviation 
report or excess emission report otherwise required after the initial 
occurrence of the violation of the relevant standard (which may be the 
end of any applicable averaging period). If such compliance, deviation 
report or excess emission report is due less than 45 days after the 
initial occurrence of the violation, the affirmative defense report may 
be included in the second compliance, deviation report or excess 
emission report due after the initial occurrence of the violation of 
the relevant standard.

0
13. Section 63.764 is amended by:
0
a. Revising paragraph (e)(1) introductory text;
0
b. Revising paragraph (i); and
0
c. Adding paragraph (j).
    The revisions and addition read as follows:


Sec.  63.764  General standards.

* * * * *
    (e) Exemptions. (1) The owner or operator of an area source is 
exempt from the requirements of paragraph (d) of this section if the 
criteria listed in paragraph (e)(1)(i) or (ii) of this section are met, 
except that the records of the determination of these criteria must be 
maintained as required in Sec.  63.774(d)(1).
* * * * *
    (i) In all cases where the provisions of this subpart require an 
owner or operator to repair leaks by a specified time after the leak is 
detected, it is a violation of this standard to fail to take action to 
repair the leak(s) within the specified time. If action is taken to 
repair the leak(s) within the specified time, failure of that action to 
successfully repair the leak(s) is not a violation of this standard. 
However, if the repairs are unsuccessful, and a leak is detected, the 
owner or operator shall take further action as required by the 
applicable provisions of this subpart.
    (j) At all times the owner or operator must operate and maintain 
any affected source, including associated air pollution control 
equipment and monitoring equipment, in a manner consistent with safety 
and good air pollution control practices for minimizing emissions. 
Determination of whether such operation and maintenance procedures are 
being used will be based on information available to the Administrator 
which may include, but is not limited to, monitoring results, review of 
operation and maintenance procedures, review of operation and 
maintenance records, and inspection of the source.

0
14. Section 63.765 is amended by:
0
a. Revising paragraph (a);
0
b. Revising paragraph (b)(1);
0
c. Revising paragraph (c)(2); and
0
d. Revising paragraph (c)(3).
    The revisions read as follows:


Sec.  63.765  Glycol dehydration unit process vent standards.

    (a) This section applies to each glycol dehydration unit subject to 
this subpart that must be controlled for air emissions as specified in 
either paragraph (c)(1)(i) or paragraph (d)(1)(i) of Sec.  63.764.
    (b) * * *
    (1) For each glycol dehydration unit process vent, the owner or 
operator shall control air emissions by either paragraph (b)(1)(i), 
(ii), or (iii) of this section.
    (i) The owner or operator of a large glycol dehydration unit, as 
defined in Sec.  63.761, shall connect the process vent to a control 
device or a combination of control devices through a closed-vent 
system. The closed-vent system shall be designed and operated in 
accordance with the requirements of Sec.  63.771(c). The control 
device(s) shall be designed and operated in accordance with the 
requirements of Sec.  63.771(d).
    (ii) The owner or operator of a large glycol dehydration unit shall 
connect the process vent to a control device or combination of control 
devices through a closed-vent system and the outlet benzene emissions 
from the control device(s) shall be reduced to a level less than 0.90 
megagrams per year. The closed-vent system shall be designed and 
operated in accordance with the requirements of Sec.  63.771(c). The 
control device(s) shall be designed and operated in accordance with the 
requirements of Sec.  63.771(d), except that the performance levels 
specified in Sec.  63.771(d)(1)(i) and (ii) do not apply.
    (iii) You must limit BTEX emissions from each existing small glycol 
dehydration unit process vent, as defined in Sec.  63.761, to the limit 
determined in Equation 1 of this section. You must limit BTEX emissions 
from each new small glycol dehydration unit process vent, as defined in 
Sec.  63.761, to the limit determined in Equation 2 of this section. 
The limits determined using Equation 1 or Equation 2 must be met in 
accordance

[[Page 49571]]

with one of the alternatives specified in paragraphs (b)(1)(iii)(A) 
through (D) of this section.
[GRAPHIC] [TIFF OMITTED] TR16AU12.009

    Equation 1

Where:

ELBTEX = Unit-specific BTEX emission limit, megagrams per 
year;
3.28 x 10-4 = BTEX emission limit, grams BTEX/standard 
cubic meter-ppmv;
Throughput = Annual average daily natural gas throughput, standard 
cubic meters per day.
Ci,BTEX = average annual BTEX concentration of the 
natural gas at the inlet to the glycol dehydration unit, ppmv.

[GRAPHIC] [TIFF OMITTED] TR16AU12.010


Where:

ELBTEX = Unit-specific BTEX emission limit, megagrams per 
year;
4.66 x 10-6 = BTEX emission limit, grams BTEX/standard 
cubic meter-ppmv;
Throughput = Annual average daily natural gas throughput, standard 
cubic meters per day.
Ci,BTEX = average annual BTEX concentration of the 
natural gas at the inlet to the glycol dehydration unit, ppmv.

    (A) Connect the process vent to a control device or combination of 
control devices through a closed-vent system. The closed vent system 
shall be designed and operated in accordance with the requirements of 
Sec.  63.771(c). The control device(s) shall be designed and operated 
in accordance with the requirements of Sec.  63.771(f).
    (B) Meet the emissions limit through process modifications in 
accordance with the requirements specified in Sec.  63.771(e).
    (C) Meet the emissions limit for each small glycol dehydration unit 
using a combination of process modifications and one or more control 
devices through the requirements specified in paragraphs (b)(1)(iii)(A) 
and (B) of this section.
    (D) Demonstrate that the emissions limit is met through actual 
uncontrolled operation of the small glycol dehydration unit. Document 
operational parameters in accordance with the requirements specified in 
Sec.  63.771(e) and emissions in accordance with the requirements 
specified in Sec.  63.772(b)(2).
* * * * *
    (c) * * *
    (2) The owner or operator shall demonstrate, to the Administrator's 
satisfaction, that the total HAP emissions to the atmosphere from the 
large glycol dehydration unit process vent are reduced by 95.0 percent 
through process modifications, or a combination of process 
modifications and one or more control devices, in accordance with the 
requirements specified in Sec.  63.771(e).
    (3) Control of HAP emissions from a GCG separator (flash tank) vent 
is not required if the owner or operator demonstrates, to the 
Administrator's satisfaction, that total emissions to the atmosphere 
from the glycol dehydration unit process vent are reduced by one of the 
levels specified in paragraph (c)(3)(i) through (iv) of this section, 
through the installation and operation of controls as specified in 
paragraph (b)(1) of this section.
    (i) For any large glycol dehydration unit, HAP emissions are 
reduced by 95.0 percent or more.
    (ii) For any large glycol dehydration unit, benzene emissions are 
reduced to a level less than 0.90 megagrams per year.
    (iii) For each existing small glycol dehydration unit, BTEX 
emissions are reduced to a level less than the limit calculated by 
Equation 1 of paragraph (b)(1)(iii) of this section.
    (iv) For each new small glycol dehydration unit, BTEX emissions are 
reduced to a level less than the limit calculated by Equation 2 of 
paragraph (b)(1)(iii) of this section.

0
15. Section 63.766 is amended by:
0
a. Adding paragraph (b)(3); and
0
b. Revising paragraph (d) to read as follows:


Sec.  63.766  Storage vessel standards.

* * * * *
    (b) * * *
    (3) The owner or operator shall control air emissions by connecting 
the cover, through a closed-vent system that meets the conditions 
specified in Sec.  63.771(c), to a process natural gas line.
* * * * *
    (d) This section does not apply to storage vessels for which the 
owner or operator is subject to and controlled under the requirements 
specified in 40 CFR part 60, subparts Kb or OOOO; or is subject to and 
controlled under the requirements specified under 40 CFR part 63 
subparts G or CC. Storage vessels subject to and controlled under 40 
CFR part 60, subpart OOOO shall submit the periodic reports specified 
in Sec.  63.775(e).

0
16. Section 63.769 is amended by:
0
a. Revising paragraph (b);
0
b. Revising paragraph (c) introductory text; and
0
c. Revising paragraph (c)(8).

The revisions read as follows:


Sec.  63.769  Equipment leak standards.

* * * * *
    (b) This section does not apply to ancillary equipment and 
compressors for which the owner or operator is subject to and 
controlled under the requirements specified in subpart H of this part; 
or is subject to and controlled under the requirements specified in 40 
CFR part 60, subpart OOOO. Ancillary equipment and compressors subject 
to and controlled under 40 CFR part 60, subpart OOOO shall submit the 
periodic reports specified in Sec.  63.775(e).
    (c) For each piece of ancillary equipment and each compressor 
subject to this section located at an existing or new source, the owner 
or operator shall meet the requirements specified in 40 CFR part 61, 
subpart V, Sec. Sec.  61.241 through 61.247, except as specified in 
paragraphs (c)(1) through (8) of this section, except that for valves 
subject to Sec.  61.242-7(b) or Sec.  61.243-1, a leak is detected if 
an instrument reading of 500 ppm or greater is measured. A leak 
detected from a valve at a source constructed on or before August 23, 
2011 shall be repaired in accordance with the schedule in Sec.  61.242-
7(d), or by October 15, 2013, whichever is later. A leak detected from 
a valve at a source constructed after August 23, 2011 shall be repaired 
in accordance with the schedule in Sec.  61.242-7(d), or by October 15, 
2012, whichever is later.
* * * * *

[[Page 49572]]

    (8) Flares, as defined in Sec.  63.761, used to comply with this 
subpart shall comply with the requirements of Sec.  63.11(b).

0
17. Section 63.771 is amended by:
0
a. Revising paragraph (c)(1);
0
b. Revising the heading of paragraph (d);
0
c. Adding paragraph (d) introductory text;
0
d. Revising paragraph (d)(1)(i)(C);
0
e. Revising paragraph (d)(1)(ii);
0
f. Revising paragraph (d)(1)(iii);
0
g. Revising paragraph (d)(4)(i);
0
h. Revising paragraph (d)(5)(i);
0
i. Revising paragraph (e)(2);
0
j. Revising paragraph (e)(3) introductory text;
0
k. Revising paragraph (e)(3)(ii); and
0
l. Adding paragraph (f).

    The revisions and additions read as follows:


Sec.  63.771  Control equipment requirements.

* * * * *
    (c) Closed-vent system requirements. (1) The closed-vent system 
shall route all gases, vapors, and fumes emitted from the material in 
an emissions unit to a control device that meets the requirements 
specified in paragraph (d) of this section.
* * * * *
    (d) Control device requirements for sources except small glycol 
dehydration units. Owners and operators of small glycol dehydration 
units, shall comply with the control device requirements in paragraph 
(f) of this section.
    (1) * * *
    (i) * * *
    (C) Operates at a minimum temperature of 760 degrees C, provided 
the control device has demonstrated, under Sec.  63.772(e), that 
combustion zone temperature is an indicator of destruction efficiency.
* * * * *
    (ii) A vapor recovery device (e.g., carbon adsorption system or 
condenser) or other non-destructive control device that is designed and 
operated to reduce the mass content of either TOC or total HAP in the 
gases vented to the device by 95.0 percent by weight or greater as 
determined in accordance with the requirements of Sec.  63.772(e).
    (iii) A flare, as defined in Sec.  63.761, that is designed and 
operated in accordance with the requirements of Sec.  63.11(b).
* * * * *
    (4) * * *
    (i) Each control device used to comply with this subpart shall be 
operating at all times when gases, vapors, and fumes are vented from 
the HAP emissions unit or units through the closed-vent system to the 
control device, as required under Sec.  63.765, Sec.  63.766, and Sec.  
63.769. An owner or operator may vent more than one unit to a control 
device used to comply with this subpart.
* * * * *
    (5) * * *
    (i) Following the initial startup of the control device, all carbon 
in the control device shall be replaced with fresh carbon on a regular, 
predetermined time interval that is no longer than the carbon service 
life established for the carbon adsorption system. Records identifying 
the schedule for replacement and records of each carbon replacement 
shall be maintained as required in Sec.  63.774(b)(7)(ix). The schedule 
for replacement shall be submitted with the Notification of Compliance 
Status Report as specified in Sec.  63.775(d)(5)(iv). Each carbon 
replacement must be reported in the Periodic Reports as specified in 
Sec.  63.772(e)(2)(xii).
* * * * *
    (e) * * *
    (2) The owner or operator shall document, to the Administrator's 
satisfaction, the conditions for which glycol dehydration unit baseline 
operations shall be modified to achieve the 95.0 percent overall HAP 
emission reduction, or BTEX limit determined in Sec.  
63.765(b)(1)(iii), as applicable, either through process modifications 
or through a combination of process modifications and one or more 
control devices. If a combination of process modifications and one or 
more control devices are used, the owner or operator shall also 
establish the emission reduction to be achieved by the control device 
to achieve an overall HAP emission reduction of 95.0 percent for the 
glycol dehydration unit process vent or, if applicable, the BTEX limit 
determined in Sec.  63.765(b)(1)(iii) for the small glycol dehydration 
unit process vent. Only modifications in glycol dehydration unit 
operations directly related to process changes, including but not 
limited to changes in glycol circulation rate or glycol-HAP absorbency, 
shall be allowed. Changes in the inlet gas characteristics or natural 
gas throughput rate shall not be considered in determining the overall 
emission reduction due to process modifications.
    (3) The owner or operator that achieves a 95.0 percent HAP emission 
reduction or meets the BTEX limit determined in Sec.  
63.765(b)(1)(iii), as applicable, using process modifications alone 
shall comply with paragraph (e)(3)(i) of this section. The owner or 
operator that achieves a 95.0 percent HAP emission reduction or meets 
the BTEX limit determined in Sec.  63.765(b)(1)(iii), as applicable, 
using a combination of process modifications and one or more control 
devices shall comply with paragraphs (e)(3)(i) and (ii) of this 
section.
* * * * *
    (ii) The owner or operator shall comply with the control device 
requirements specified in paragraph (d) or (f) of this section, as 
applicable, except that the emission reduction or limit achieved shall 
be the emission reduction or limit specified for the control device(s) 
in paragraph (e)(2) of this section.
    (f) Control device requirements for small glycol dehydration units. 
(1) The control device used to meet BTEX the emission limit calculated 
in Sec.  63.765(b)(1)(iii) shall be one of the control devices 
specified in paragraphs (f)(1)(i) through (iii) of this section.
    (i) An enclosed combustion device (e.g., thermal vapor incinerator, 
catalytic vapor incinerator, boiler, or process heater) that is 
designed and operated to meet the levels specified in paragraphs 
(f)(1)(i)(A) or (B) of this section. If a boiler or process heater is 
used as the control device, then the vent stream shall be introduced 
into the flame zone of the boiler or process heater.
    (A) The mass content of BTEX in the gases vented to the device is 
reduced as determined in accordance with the requirements of Sec.  
63.772(e).
    (B) The concentration of either TOC or total HAP in the exhaust 
gases at the outlet of the device is reduced to a level equal to or 
less than 20 parts per million by volume on a dry basis corrected to 3 
percent oxygen as determined in accordance with the requirements of 
Sec.  63.772(e).
    (ii) A vapor recovery device (e.g., carbon adsorption system or 
condenser) or other non-destructive control device that is designed and 
operated to reduce the mass content of BTEX in the gases vented to the 
device as determined in accordance with the requirements of Sec.  
63.772(e).
    (iii) A flare, as defined in Sec.  63.761, that is designed and 
operated in accordance with the requirements of Sec.  63.11(b).
    (2) The owner or operator shall operate each control device in 
accordance with the requirements specified in paragraphs (f)(2)(i) and 
(ii) of this section.
    (i) Each control device used to comply with this subpart shall be 
operating at all times. An owner or operator may vent more than one 
unit to a control device used to comply with this subpart.

[[Page 49573]]

    (ii) For each control device monitored in accordance with the 
requirements of Sec.  63.773(d), the owner or operator shall 
demonstrate compliance according to the requirements of either Sec.  
63.772(f) or (h).
    (3) For each carbon adsorption system used as a control device to 
meet the requirements of paragraph (f)(1)(ii) of this section, the 
owner or operator shall manage the carbon as required under (d)(5)(i) 
and (ii) of this section.

0
18. Section 63.772 is amended by:
0
a. Revising paragraph (b) introductory text;
0
b. Revising paragraph (b)(1)(ii);
0
c. Revising paragraph (b)(2);
0
d. Revising paragraph (c)(6)(i);
0
e. Adding paragraph (d);
0
f. Revising paragraph (e) introductory text;
0
g. Revising paragraphs (e)(1)(i) through (v);
0
h. Revising paragraph (e)(2);
0
i. Revising paragraph (e)(3) introductory text;
0
j. Revising paragraph (e)(3)(i)(B);
0
k. Revising paragraph (e)(3)(iv)(C)(1);
0
l. Adding paragraphs (e)(3)(v) and (vi);
0
m. Revising paragraph (e)(4) introductory text;
0
n. Revising paragraph (e)(4)(i);
0
o. Revising paragraph (e)(5);
0
p. Revising paragraph (f) introductory text;
0
q. Revising paragraphs (f)(2) and (3);
0
r. Adding paragraphs (f)(4) through (6);
0
s. Revising paragraph (g) introductory text;
0
t. Revising paragraph (g)(1) and paragraph (g)(2) introductory text;
0
u. Revising paragraph (g)(2)(iii);
0
v. Revising paragraph (g)(3);
0
w. Adding paragraph (h); and
0
x. Adding paragraph (i).

The revisions and additions read as follows:


Sec.  63.772  Test methods, compliance procedures, and compliance 
demonstrations.

* * * * *
    (b) Determination of glycol dehydration unit flowrate, benzene 
emissions, or BTEX emissions. The procedures of this paragraph shall be 
used by an owner or operator to determine glycol dehydration unit 
natural gas flowrate, benzene emissions, or BTEX emissions.
    (1) * * *
    (ii) The owner or operator shall document, to the Administrator's 
satisfaction, the actual annual average natural gas flowrate to the 
glycol dehydration unit.
    (2) The determination of actual average benzene or BTEX emissions 
from a glycol dehydration unit shall be made using the procedures of 
either paragraph (b)(2)(i) or (ii) of this section. Emissions shall be 
determined either uncontrolled, or with federally enforceable controls 
in place.
    (i) The owner or operator shall determine actual average benzene or 
BTEX emissions using the model GRI-GLYCalcTM, Version 3.0 or 
higher, and the procedures presented in the associated GRI-
GLYCalcTM Technical Reference Manual. Inputs to the model 
shall be representative of actual operating conditions of the glycol 
dehydration unit and may be determined using the procedures documented 
in the Gas Research Institute (GRI) report entitled ``Atmospheric Rich/
Lean Method for Determining Glycol Dehydrator Emissions'' (GRI-95/
0368.1); or
    (ii) The owner or operator shall determine an average mass rate of 
benzene or BTEX emissions in kilograms per hour through direct 
measurement using the methods in Sec.  63.772(a)(1)(i) or (ii), or an 
alternative method according to Sec.  63.7(f). Annual emissions in 
kilograms per year shall be determined by multiplying the mass rate by 
the number of hours the unit is operated per year. This result shall be 
converted to megagrams per year.
    (c) * * *
    (6) * * *
    (i) Except as provided in paragraph (c)(6)(ii) of this section, the 
detection instrument shall meet the performance criteria of Method 21 
of 40 CFR part 60, appendix A, except the instrument response factor 
criteria in section 3.1.2(a) of Method 21 shall be for the average 
composition of the process fluid, not each individual volatile organic 
compound in the stream. For process streams that contain nitrogen, air, 
or other inert gases that are not organic hazardous air pollutants or 
volatile organic compounds, the average stream response factor shall be 
calculated on an inert-free basis.
* * * * *
    (d) Test procedures and compliance demonstrations for small glycol 
dehydration units. This paragraph applies to the test procedures for 
small dehydration units.
    (1) If the owner or operator is using a control device to comply 
with the emission limit in Sec.  63.765(b)(1)(iii), the requirements of 
paragraph (e) of this section apply. Compliance is demonstrated using 
the methods specified in paragraph (f) of this section.
    (2) If no control device is used to comply with the emission limit 
in Sec.  63.765(b)(1)(iii), the owner or operator must determine the 
glycol dehydration unit BTEX emissions as specified in paragraphs 
(d)(2)(i) through (iii) of this section. Compliance is demonstrated if 
the BTEX emissions determined as specified in paragraphs (d)(2)(i) 
through (iii) are less than the emission limit calculated using the 
equation in Sec.  63.765(b)(1)(iii).
    (i) Method 1 or 1A, 40 CFR part 60, appendix A, as appropriate, 
shall be used for selection of the sampling sites at the outlet of the 
glycol dehydration unit process vent. Any references to particulate 
mentioned in Methods 1 and 1A do not apply to this section.
    (ii) The gas volumetric flowrate shall be determined using Method 
2, 2A, 2C, or 2D, 40 CFR part 60, appendix A, as appropriate.
    (iii) The BTEX emissions from the outlet of the glycol dehydration 
unit process vent shall be determined using the procedures specified in 
paragraph (e)(3)(v) of this section. As an alternative, the mass rate 
of BTEX at the outlet of the glycol dehydration unit process vent may 
be calculated using the model GRI-GLYCalcTM, Version 3.0 or 
higher, and the procedures presented in the associated GRI-
GLYCalcTM Technical Reference Manual. Inputs to the model 
shall be representative of actual operating conditions of the glycol 
dehydration unit and shall be determined using the procedures 
documented in the Gas Research Institute (GRI) report entitled 
``Atmospheric Rich/Lean Method for Determining Glycol Dehydrator 
Emissions'' (GRI-95/0368.1). When the BTEX mass rate is calculated for 
glycol dehydration units using the model GRI-GLYCalcTM, all 
BTEX measured by Method 18, 40 CFR part 60, appendix A, shall be 
summed.
    (e) Control device performance test procedures. This paragraph 
applies to the performance testing of control devices. The owners or 
operators shall demonstrate that a control device achieves the 
performance requirements of Sec.  63.771(d)(1), (e)(3)(ii) or (f)(1) 
using a performance test as specified in paragraph (e)(3) of this 
section. Owners or operators using a condenser have the option to use a 
design analysis as specified in paragraph (e)(4) of this section. The 
owner or operator may elect to use the alternative procedures in 
paragraph (e)(5) of this section for performance testing of a condenser 
used to control emissions from a glycol dehydration unit process vent. 
Flares shall meet the provisions in paragraph (e)(2) of this section. 
As an alternative to conducting a performance test under this section 
for combustion control devices, a control device that can be

[[Page 49574]]

demonstrated to meet the performance requirements of Sec.  
63.771(d)(1), (e)(3)(ii) or (f)(1) through a performance test conducted 
by the manufacturer, as specified in paragraph (h) of this section, can 
be used.
    (1) * * *
    (i) Except as specified in paragraph (e)(2) of this section, a 
flare, as defined in Sec.  63.761, that is designed and operated in 
accordance with Sec.  63.11(b);
    (ii) Except for control devices used for small glycol dehydration 
units, a boiler or process heater with a design heat input capacity of 
44 megawatts or greater;
    (iii) Except for control devices used for small glycol dehydration 
units, a boiler or process heater into which the vent stream is 
introduced with the primary fuel or is used as the primary fuel;
    (iv) Except for control devices used for small glycol dehydration 
units, a boiler or process heater burning hazardous waste for which the 
owner or operator has either been issued a final permit under 40 CFR 
part 270 and complies with the requirements of 40 CFR part 266, subpart 
H; or has certified compliance with the interim status requirements of 
40 CFR part 266, subpart H;
    (v) Except for control devices used for small glycol dehydration 
units, a hazardous waste incinerator for which the owner or operator 
has been issued a final permit under 40 CFR part 270 and complies with 
the requirements of 40 CFR part 264, subpart O; or has certified 
compliance with the interim status requirements of 40 CFR part 265, 
subpart O.
* * * * *
    (2) An owner or operator shall design and operate each flare, as 
defined in Sec.  63.761, in accordance with the requirements specified 
in Sec.  63.11(b) and the compliance determination shall be conducted 
using Method 22 of 40 CFR part 60, appendix A, to determine visible 
emissions.
    (3) For a performance test conducted to demonstrate that a control 
device meets the requirements of Sec.  63.771(d)(1), (e)(3)(ii) or 
(f)(1), the owner or operator shall use the test methods and procedures 
specified in paragraphs (e)(3)(i) through (v) of this section. The 
initial and periodic performance tests shall be conducted according to 
the schedule specified in paragraph (e)(3)(vi) of this section.
    (i) * * *
    (B) To determine compliance with the enclosed combustion device 
total HAP concentration limit specified in Sec.  63.771(d)(1)(i)(B), or 
the BTEX emission limit specified in Sec.  63.765(b)(1)(iii) the 
sampling site shall be located at the outlet of the combustion device.
* * * * *
    (iv) * * *
    (C) * * *
    (1) The emission rate correction factor for excess air, integrated 
sampling and analysis procedures of Method 3A or 3B, 40 CFR part 60, 
appendix A, ASTM D6522-00 (Reapproved 2005), or ANSI/ASME PTC 19.10-
1981, Part 10 (manual portion only) (incorporated by reference as 
specified in Sec.  63.14) shall be used to determine the oxygen 
concentration. The samples shall be taken during the same time that the 
samples are taken for determining TOC concentration or total HAP 
concentration.
* * * * *
    (v) To determine compliance with the BTEX emission limit specified 
in Sec.  63.765(b)(1)(iii) the owner or operator shall use one of the 
following methods: Method 18, 40 CFR part 60, appendix A; ASTM D6420-99 
(Reapproved 2004), as specified in Sec.  63.772(a)(1)(ii) (incorporated 
by reference as specified in Sec.  63.14); or any other method or data 
that have been validated according to the applicable procedures in 
Method 301, 40 CFR part 63, appendix A. The following procedures shall 
be used to calculate BTEX emissions:
    (A) The minimum sampling time for each run shall be 1 hour in which 
either an integrated sample or a minimum of four grab samples shall be 
taken. If grab sampling is used, then the samples shall be taken at 
approximately equal intervals in time, such as 15-minute intervals 
during the run.
    (B) The mass rate of BTEX (Eo) shall be computed using 
the equations and procedures specified in paragraphs (e)(3)(v)(B)(1) 
and (2) of this section.
    (1) The following equation shall be used:
    [GRAPHIC] [TIFF OMITTED] TR16AU12.011
    

Where:

Eo = Mass rate of BTEX at the outlet of the control 
device, dry basis, kilogram per hour.
Coj = Concentration of sample component j of the gas 
stream at the outlet of the control device, dry basis, parts per 
million by volume.
Moj = Molecular weight of sample component j of the gas 
stream at the outlet of the control device, gram/gram-mole.
Qo = Flowrate of gas stream at the outlet of the control 
device, dry standard cubic meter per minute.
K2 = Constant, 2.494 x 10-6 (parts per 
million) (gram-mole per standard cubic meter) (kilogram/gram) 
(minute/hour), where standard temperature (gram-mole per standard 
cubic meter) is 20 degrees C.
n = Number of components in sample.

    (2) When the BTEX mass rate is calculated, only BTEX compounds 
measured by Method 18, 40 CFR part 60, appendix A, or ASTM D6420-99 
(Reapproved 2004) (incorporated by reference as specified in Sec.  
63.14) as specified in Sec.  63.772(a)(1)(ii), shall be summed using 
the equations in paragraph (e)(3)(v)(B)(1) of this section.
    (vi) The owner or operator shall conduct performance tests 
according to the schedule specified in paragraphs (e)(3)(vi)(A) and (B) 
of this section.
    (A) An initial performance test shall be conducted within 180 days 
after the compliance date that is specified for each affected source in 
Sec.  63.760(f)(7) through (8), except that the initial performance 
test for existing combustion control devices (i.e., control devices 
installed on or before August 23, 2011) at major sources shall be 
conducted no later than October 15, 2015. If the owner or operator of 
an existing combustion control device at a major source chooses to 
replace such device with a control device whose model is tested under 
Sec.  63.772(h), then the newly installed device shall comply with all 
provisions of this subpart no later than October 15, 2015. The 
performance test results shall be submitted in the Notification of 
Compliance Status Report as required in Sec.  63.775(d)(1)(ii).
    (B) Periodic performance tests shall be conducted for all control 
devices required to conduct initial performance tests except as 
specified in paragraphs (e)(3)(vi)(B)(1) and (2) of this section. The 
first periodic performance test shall be conducted no later than 60 
months after the initial performance test required in paragraph 
(e)(3)(vi)(A) of this section. Subsequent periodic performance tests 
shall be conducted at intervals no longer than 60 months following the 
previous periodic performance test or whenever a source desires to 
establish a new operating limit. The periodic performance test results 
must be submitted in the next Periodic Report as specified in Sec.  
63.775(e)(2)(xi). Combustion control devices meeting the criteria in 
either paragraph (e)(3)(vi)(B)(1) or (2) of this section are not 
required to conduct periodic performance tests.
    (1) A control device whose model is tested under, and meets the 
criteria of, Sec.  63.772(h), or
    (2) A combustion control device demonstrating during the 
performance test under Sec.  63.772(e) that combustion

[[Page 49575]]

zone temperature is an indicator of destruction efficiency and operates 
at a minimum temperature of 760 degrees C.
    (4) For a condenser design analysis conducted to meet the 
requirements of Sec.  63.771(d)(1), (e)(3)(ii), or (f)(1), the owner or 
operator shall meet the requirements specified in paragraphs (e)(4)(i) 
and (ii) of this section. Documentation of the design analysis shall be 
submitted as a part of the Notification of Compliance Status Report as 
required in Sec.  63.775(d)(1)(i).
    (i) The condenser design analysis shall include an analysis of the 
vent stream composition, constituent concentrations, flowrate, relative 
humidity, and temperature, and shall establish the design outlet 
organic compound concentration level, design average temperature of the 
condenser exhaust vent stream, and the design average temperatures of 
the coolant fluid at the condenser inlet and outlet. As an alternative 
to the condenser design analysis, an owner or operator may elect to use 
the procedures specified in paragraph (e)(5) of this section.
* * * * *
    (5) As an alternative to the procedures in paragraph (e)(4)(i) of 
this section, an owner or operator may elect to use the procedures 
documented in the GRI report entitled, ``Atmospheric Rich/Lean Method 
for Determining Glycol Dehydrator Emissions'' (GRI-95/0368.1) as inputs 
for the model GRI-GLYCalcTM, Version 3.0 or higher, to 
generate a condenser performance curve.
    (f) Compliance demonstration for control device performance 
requirements. This paragraph applies to the demonstration of compliance 
with the control device performance requirements specified in Sec.  
63.771(d)(1)(i), (e)(3), and (f)(1). Compliance shall be demonstrated 
using the requirements in paragraphs (f)(1) through (3) of this 
section. As an alternative, an owner or operator that installs a 
condenser as the control device to achieve the requirements specified 
in Sec.  63.771(d)(1)(ii), (e)(3), or (f)(1) may demonstrate compliance 
according to paragraph (g) of this section. An owner or operator may 
switch between compliance with paragraph (f) of this section and 
compliance with paragraph (g) of this section only after at least 1 
year of operation in compliance with the selected approach. 
Notification of such a change in the compliance method shall be 
reported in the next Periodic Report, as required in Sec.  63.775(e), 
following the change.
* * * * *
    (2) The owner or operator shall calculate the daily average of the 
applicable monitored parameter in accordance with Sec.  63.773(d)(4) 
except that the inlet gas flowrate to the control device shall not be 
averaged.
    (3) Compliance with the operating parameter limit is achieved when 
the daily average of the monitoring parameter value calculated under 
paragraph (f)(2) of this section is either equal to or greater than the 
minimum or equal to or less than the maximum monitoring value 
established under paragraph (f)(1) of this section. For inlet gas 
flowrate, compliance with the operating parameter limit is achieved 
when the value is equal to or less than the value established under 
Sec.  63.772(h) or under the performance test conducted under Sec.  
63.772(e), as applicable.
    (4) Except for periods of monitoring system malfunctions, repairs 
associated with monitoring system malfunctions, and required monitoring 
system quality assurance or quality control activities (including, as 
applicable, system accuracy audits and required zero and span 
adjustments), the CMS required in Sec.  63.773(d) must be operated at 
all times the affected source is operating. A monitoring system 
malfunction is any sudden, infrequent, not reasonably preventable 
failure of the monitoring system to provide valid data. Monitoring 
system failures that are caused in part by poor maintenance or careless 
operation are not malfunctions. Monitoring system repairs are required 
to be completed in response to monitoring system malfunctions and to 
return the monitoring system to operation as expeditiously as 
practicable.
    (5) Data recorded during monitoring system malfunctions, repairs 
associated with monitoring system malfunctions, or required monitoring 
system quality assurance or control activities may not be used in 
calculations used to report emissions or operating levels. All the data 
collected during all other required data collection periods must be 
used in assessing the operation of the control device and associated 
control system.
    (6) Except for periods of monitoring system malfunctions, repairs 
associated with monitoring system malfunctions, and required quality 
monitoring system quality assurance or quality control activities 
(including, as applicable, system accuracy audits and required zero and 
span adjustments), failure to collect required data is a deviation of 
the monitoring requirements.
    (g) Compliance demonstration with percent reduction or emission 
limit performance requirements--condensers. This paragraph applies to 
the demonstration of compliance with the performance requirements 
specified in Sec.  63.771(d)(1)(ii), (e)(3), or (f)(1) for condensers. 
Compliance shall be demonstrated using the procedures in paragraphs 
(g)(1) through (3) of this section.
    (1) The owner or operator shall establish a site-specific condenser 
performance curve according to Sec.  63.773(d)(5)(ii). For sources 
required to meet the BTEX limit in accordance with Sec.  63.771(e) or 
(f)(1) the owner or operator shall identify the minimum percent 
reduction necessary to meet the BTEX limit.
    (2) Compliance with the requirements in Sec.  63.771(d)(1)(ii), 
(e)(3), or (f)(1) shall be demonstrated by the procedures in paragraphs 
(g)(2)(i) through (iii) of this section.
* * * * *
    (iii) Except as provided in paragraphs (g)(2)(iii)(A) and (B) of 
this section, at the end of each operating day, the owner or operator 
shall calculate the 365-day average HAP, or BTEX, emission reduction, 
as appropriate, from the condenser efficiencies as determined in 
paragraph (g)(2)(ii) of this section for the preceding 365 operating 
days. If the owner or operator uses a combination of process 
modifications and a condenser in accordance with the requirements of 
Sec.  63.771(e), the 365-day average HAP, or BTEX, emission reduction 
shall be calculated using the emission reduction achieved through 
process modifications and the condenser efficiency as determined in 
paragraph (g)(2)(ii) of this section, both for the previous 365 
operating days.
    (A) After the compliance dates specified in Sec.  63.760(f), an 
owner or operator with less than 120 days of data for determining 
average HAP, or BTEX, emission reduction, as appropriate, shall 
calculate the average HAP, or BTEX emission reduction, as appropriate, 
for the first 120 days of operation after the compliance dates. For 
sources required to meet the overall 95.0 percent reduction 
requirement, compliance is achieved if the 120-day average HAP emission 
reduction is equal to or greater than 90.0 percent. For sources 
required to meet the BTEX limit under Sec.  63.765(b)(1)(iii), 
compliance is achieved if the average BTEX emission reduction is at 
least 95.0 percent of the required 365-day value identified under 
paragraph (g)(1) of this section (i.e., at least 76.0 percent if the 
365-day design value is 80.0 percent).
    (B) After 120 days and no more than 364 days of operation after the 
compliance dates specified in

[[Page 49576]]

Sec.  63.760(f), the owner or operator shall calculate the average HAP 
emission reduction as the HAP emission reduction averaged over the 
number of days between the current day and the applicable compliance 
date. For sources required to meet the overall 95.0-percent reduction 
requirement, compliance with the performance requirements is achieved 
if the average HAP emission reduction is equal to or greater than 90.0 
percent. For sources required to meet the BTEX limit under Sec.  
63.765(b)(1)(iii), compliance is achieved if the average BTEX emission 
reduction is at least 95.0 percent of the required 365-day value 
identified under paragraph (g)(1) of this section (i.e., at least 76.0 
percent if the 365-day design value is 80.0 percent).
    (3) If the owner or operator has data for 365 days or more of 
operation, compliance is achieved based on the applicable criteria in 
paragraphs (g)(3)(i) or (ii) of this section.
    (i) For sources meeting the HAP emission reduction specified in 
Sec.  63.771(d)(1)(ii) or (e)(3) the average HAP emission reduction 
calculated in paragraph (g)(2)(iii) of this section is equal to or 
greater than 95.0 percent.
    (ii) For sources required to meet the BTEX limit under Sec.  
63.771(e)(3) or (f)(1), compliance is achieved if the average BTEX 
emission reduction calculated in paragraph (g)(2)(iii) of this section 
is equal to or greater than the minimum percent reduction identified in 
paragraph (g)(1) of this section.
    (h) Performance testing for combustion control devices--
manufacturers' performance test. (1) This paragraph applies to the 
performance testing of a combustion control device conducted by the 
device manufacturer. The manufacturer shall demonstrate that a specific 
model of control device achieves the performance requirements in 
paragraph (h)(7) of this section by conducting a performance test as 
specified in paragraphs (h)(2) through (6) of this section.
    (2) Performance testing shall consist of three one-hour (or longer) 
test runs for each of the four following firing rate settings making a 
total of 12 test runs per test. Propene (propylene) gas shall be used 
for the testing fuel. All fuel analyses shall be performed by an 
independent third-party laboratory (not affiliated with the control 
device manufacturer or fuel supplier).
    (i) 90-100 percent of maximum design rate (fixed rate).
    (ii) 70-100-70 percent (ramp up, ramp down). Begin the test at 70 
percent of the maximum design rate. During the first 5 minutes, 
incrementally ramp the firing rate to 100 percent of the maximum design 
rate. Hold at 100 percent for 5 minutes. In the 10-15 minute time 
range, incrementally ramp back down to 70 percent of the maximum design 
rate. Repeat three more times for a total of 60 minutes of sampling.
    (iii) 30-70-30 percent (ramp up, ramp down). Begin the test at 30 
percent of the maximum design rate. During the first 5 minutes, 
incrementally ramp the firing rate to 70 percent of the maximum design 
rate. Hold at 70 percent for 5 minutes. In the 10-15 minute time range, 
incrementally ramp back down to 30 percent of the maximum design rate. 
Repeat three more times for a total of 60 minutes of sampling.
    (iv) 0-30-0 percent (ramp up, ramp down). Begin the test at 0 
percent of the maximum design rate. During the first 5 minutes, 
incrementally ramp the firing rate to 30 percent of the maximum design 
rate. Hold at 30 percent for 5 minutes. In the 10-15 minute time range, 
incrementally ramp back down to 0 percent of the maximum design rate. 
Repeat three more times for a total of 60 minutes of sampling.
    (3) All models employing multiple enclosures shall be tested 
simultaneously and with all burners operational. Results shall be 
reported for the each enclosure individually and for the average of the 
emissions from all interconnected combustion enclosures/chambers. 
Control device operating data shall be collected continuously 
throughout the performance test using an electronic Data Acquisition 
System and strip chart. Data shall be submitted with the test report in 
accordance with paragraph (h)(8)(iii) of this section.
    (4) Inlet gas testing shall be conducted as specified in paragraphs 
(h)(4)(i) through (iii) of this section.
    (i) The inlet gas flow metering system shall be located in 
accordance with Method 2A, 40 CFR part 60, appendix A-1, (or other 
approved procedure) to measure inlet gas flowrate at the control device 
inlet location. The fitting for filling inlet gas sample containers 
shall be located a minimum of 8 pipe diameters upstream of any inlet 
gas flow monitoring meter.
    (ii) Inlet gas flowrate shall be determined using Method 2A, 40 CFR 
part 60, appendix A-1. Record the start and stop reading for each 60-
minute THC test. Record the inlet gas pressure and temperature at 5-
minute intervals throughout each 60-minute THC test.
    (iii) Inlet gas fuel sampling shall be conducted in accordance with 
the criteria in paragraphs (h)(4)(iii)(A) and (B) of this section.
    (A) At the inlet gas sampling location, securely connect a 
Silonite-coated stainless steel evacuated canister fitted with a flow 
controller sufficient to fill the canister over a 3 hour period. 
Filling shall be conducted as specified in the following:
    (1) Open the canister sampling valve at the beginning of the total 
hydrocarbon (THC) test, and close the canister at the end of each THC 
run.
    (2) Fill one canister across the three test runs for each THC test 
such that one composite fuel sample exists for each test condition.
    (3) Label the canisters individually and record on a chain of 
custody form.
    (B) Each inlet gas sample shall be analyzed using the following 
methods. The results shall be included in the test report.
    (1) Hydrocarbon compounds containing between one and five atoms of 
carbon plus benzene using ASTM D1945-03 (Reapproved 2010) (incorporated 
by reference as specified in Sec.  63.14).
    (2) Hydrogen (H2), carbon monoxide (CO), carbon dioxide 
(CO2), nitrogen (N2), oxygen (O2) 
using ASTM D1945-03 (Reapproved 2010) (incorporated by reference as 
specified in Sec.  63.14).
    (3) Higher heating value using ASTM D3588-98 (Reapproved 2003) or 
ASTM D4891-89 (Reapproved 2006) (incorporated by reference as specified 
in Sec.  63.14).
    (5) Outlet testing shall be conducted in accordance with the 
criteria in paragraphs (h)(5)(i) through (v) of this section.
    (i) Sampling and flowrate measured in accordance with the 
following:
    (A) The outlet sampling location shall be a minimum of 4 equivalent 
stack diameters downstream from the highest peak flame or any other 
flow disturbance, and a minimum of one equivalent stack diameter 
upstream of the exit or any other flow disturbance. A minimum of two 
sample ports shall be used.
    (B) Flowrate shall be measured using Method 1, 40 CFR part 60, 
Appendix 1, for determining flow measurement traverse point location; 
and Method 2, 40 CFR part 60, Appendix 1, shall be used to measure duct 
velocity. If low flow conditions are encountered (i.e., velocity 
pressure differentials less than 0.05 inches of water) during the 
performance test, a more sensitive manometer or other pressure 
measurement device shall be used to obtain an accurate flow profile.
    (ii) Molecular weight shall be determined as specified in 
paragraphs (h)(4)(iii)(B) and (h)(5)(ii)(A) and (B) of this section.
    (A) An integrated bag sample shall be collected during the Method 
4, 40 CFR

[[Page 49577]]

part 60, Appendix A, moisture test. Analyze the bag sample using a gas 
chromatograph-thermal conductivity detector (GC-TCD) analysis meeting 
the following criteria:
    (1) Collect the integrated sample throughout the entire test, and 
collect representative volumes from each traverse location.
    (2) The sampling line shall be purged with stack gas before opening 
the valve and beginning to fill the bag.
    (3) The bag contents shall be vigorously mixed prior to the GC 
analysis.
    (4) The GC-TCD calibration procedure in Method 3C, 40 CFR part 60, 
Appendix A, shall be modified by using EPAAlt-045 as follows: For the 
initial calibration, triplicate injections of any single concentration 
must agree within 5 percent of their mean to be valid. The calibration 
response factor for a single concentration re-check must be within 10 
percent of the original calibration response factor for that 
concentration. If this criterion is not met, the initial calibration 
using at least three concentration levels shall be repeated.
    (B) Report the molecular weight of: O2, CO2, 
methane (CH4), and N2 and include in the test report 
submitted under Sec.  63.775(d)(iii). Moisture shall be determined 
using Method 4, 40 CFR part 60, Appendix A. Traverse both ports with 
the Method 4, 40 CFR part 60, Appendix A, sampling train during each 
test run. Ambient air shall not be introduced into the Method 3C, 40 
CFR part 60, Appendix A, integrated bag sample during the port change.
    (iii) Carbon monoxide shall be determined using Method 10, 40 CFR 
part 60, Appendix A, or ASTM D6522-00 (Reapproved 2005), (incorporated 
by reference as specified in Sec.  63.14). The test shall be run at the 
same time and with the sample points used for the EPA Method 25A, 40 
CFR part 60, Appendix A, testing. An instrument range of 0-10 per 
million by volume-dry (ppmvd) shall be used.
    (iv) Visible emissions shall be determined using Method 22, 40 CFR 
part 60, Appendix A. The test shall be performed continuously during 
each test run. A digital color photograph of the exhaust point, taken 
from the position of the observer and annotated with date and time, 
will be taken once per test run and the four photos included in the 
test report.
    (v) Excess air shall be determined using resultant data from the 
EPA Method 3C tests and EPA Method 3B, 40 CFR part 60, Appendix A, 
equation 3B-1 or ANSI/ASME PTC 19.10, 1981-Part 10 (manual portion 
only) (incorporated by reference as specified in Sec.  63.14).
    (6) Total hydrocarbons (THC) shall be determined as specified by 
the following criteria:
    (i) Conduct THC sampling using Method 25A, 40 CFR part 60, Appendix 
A, except the option for locating the probe in the center 10 percent of 
the stack shall not be allowed. The THC probe must be traversed to 16.7 
percent, 50 percent, and 83.3 percent of the stack diameter during each 
test.
    (ii) A valid test shall consist of three Method 25A, 40 CFR part 
60, Appendix A, tests, each no less than 60 minutes in duration.
    (iii) A 0-10 parts per million by volume-wet (ppmvw) (as propane) 
measurement range is preferred; as an alternative a 0-30 ppmvw (as 
carbon) measurement range may be used.
    (iv) Calibration gases will be propane in air and be certified 
through EPA Protocol 1--``EPA Traceability Protocol for Assay and 
Certification of Gaseous Calibration Standards,'' September 1997, as 
amended August 25, 1999, EPA-600/R-97/121 (or more recent if updated 
since 1999).
    (v) THC measurements shall be reported in terms of ppmvw as 
propane.
    (vi) THC results shall be corrected to 3 percent CO2, as 
measured by Method 3C, 40 CFR part 60, Appendix A.
    (vii) Subtraction of methane/ethane from the THC data is not 
allowed in determining results.
    (7) Performance test criteria:
    (i) The control device model tested must meet the criteria in 
paragraphs (h)(7)(i)(A) through (C) of this section:
    (A) Method 22, 40 CFR part 60, Appendix A, results under paragraph 
(h)(5)(v) of this section with no indication of visible emissions, and
    (B) Average Method 25A, 40 CFR part 60, Appendix A, results under 
paragraph (h)(6) of this section equal to or less than 10.0 ppmvw THC 
as propane corrected to 3.0 percent CO2, and
    (C) Average CO emissions determined under paragraph (h)(5)(iv) of 
this section equal to or less than 10 parts ppmvd, corrected to 3.0 
percent CO2.
    (D) Excess combustion air shall be equal to or greater than 150 
percent.
    (ii) The manufacturer shall determine a maximum inlet gas flowrate 
which shall not be exceeded for each control device model to achieve 
the criteria in paragraph (h)(7)(i) of this section.
    (iii) A control device meeting the criteria in paragraphs 
(h)(7)(i)(A) through (C) of this section will have demonstrated a 
destruction efficiency of 95.0 percent for HAP regulated under this 
subpart.
    (8) The owner or operator of a combustion control device model 
tested under this section shall submit the information listed in 
paragraphs (h)(8)(i) through (iii) of this section in the test report 
required under Sec.  63.775(d)(1)(iii).
    (i) Full schematic of the control device and dimensions of the 
device components.
    (ii) Design net heating value (minimum and maximum) of the device.
    (iii) Test fuel gas flow range (in both mass and volume). Include 
the minimum and maximum allowable inlet gas flowrate.
    (iv) Air/stream injection/assist ranges, if used.
    (v) The test parameter ranges listed in paragraphs (h)(8)(v)(A) 
through (O) of this section, as applicable for the tested model.
    (A) Fuel gas delivery pressure and temperature.
    (B) Fuel gas moisture range.
    (C) Purge gas usage range.
    (D) Condensate (liquid fuel) separation range.
    (E) Combustion zone temperature range. This is required for all 
devices that measure this parameter.
    (F) Excess combustion air range.
    (G) Flame arrestor(s).
    (H) Burner manifold pressure.
    (I) Pilot flame sensor.
    (J) Pilot flame design fuel and fuel usage.
    (K) Tip velocity range.
    (L) Momentum flux ratio.
    (M) Exit temperature range.
    (N) Exit flowrate.
    (O) Wind velocity and direction.
    (vi) The test report shall include all calibration quality 
assurance/quality control data, calibration gas values, gas cylinder 
certification, and strip charts annotated with test times and 
calibration values.
    (i) Compliance demonstration for combustion control devices--
manufacturers' performance test. This paragraph applies to the 
demonstration of compliance for a combustion control device tested 
under the provisions in paragraph (h) of this section. Owners or 
operators shall demonstrate that a control device achieves the 
performance requirements of Sec.  63.771(d)(1), (e)(3)(ii) or (f)(1), 
by installing a device tested under paragraph (h) of this section and 
complying with the following criteria:
    (1) The inlet gas flowrate shall meet the range specified by the 
manufacturer. Flowrate shall be calculated as specified in Sec.  
63.773(d)(3)(i)(H)(1).
    (2) A pilot flame shall be present at all times of operation. The 
pilot flame shall be monitored in accordance with Sec.  
63.773(d)(3)(i)(H)(2).
    (3) Devices shall be operated with no visible emissions, except for 
periods not

[[Page 49578]]

to exceed a total of 2 minutes during any hour. A visible emissions 
test using Method 22, 40 CFR part 60, Appendix A, shall be performed 
each calendar quarter. The observation period shall be 1 hour and shall 
be conducted according to EPA Method 22, 40 CFR part 60, Appendix A.
    (4) Compliance with the operating parameter limit is achieved when 
the following criteria are met:
    (i) The inlet gas flowrate monitored under paragraph (i)(1) of this 
section is equal to or below the maximum established by the 
manufacturer; and
    (ii) The pilot flame is present at all times; and
    (iii) During the visible emissions test performed under paragraph 
(i)(3) of this section the duration of visible emissions does not 
exceed a total of 2 minutes during the observation period. Devices 
failing the visible emissions test shall follow manufacturers repair 
instructions, if available, or best combustion engineering practice as 
outlined in the unit inspection and maintenance plan, to return the 
unit to compliant operation. All repairs and maintenance activities for 
each unit shall be recorded in a maintenance and repair log and shall 
be available on site for inspection.
    (iv) Following return to operation from maintenance or repair 
activity, each device must pass a Method 22 visual observation as 
described in paragraph (i)(3) of this section.

0
19. Section 63.773 is amended by:
0
a. Adding paragraph (b);
0
b. Revising paragraph (d)(1) introductory text;
0
c. Revising paragraph (d)(1)(ii) and adding paragraphs (d)(1)(iii) and 
(iv);
0
d. Revising paragraph (d)(2);
0
e. Revising paragraph (d)(3)(i)(A);
0
f. Revising paragraph (d)(3)(i)(D);
0
g. Revising paragraph (d)(3)(i)(G);
0
h. Adding paragraph (d)(3)(i)(H);
0
i. Revising paragraph (d)(4);
0
j. Revising paragraph (d)(5)(i);
0
k. Revising paragraphs (d)(5)(ii)(A) through (C);
0
l. Revising paragraph (d)(6) introductory text;
0
m. Revising paragraphs (d)(6)(ii) and (iii);
0
n. Adding paragraph (d)(6)(vi);
0
o. Revising paragraph (d)(7); and
0
p. Removing paragraphs (d)(8) and (9).
    The revisions and additions read as follows:


Sec.  63.773  Inspection and monitoring requirements.

* * * * *
    (b) The owner or operator of a control device whose model was 
tested under Sec.  63.772(h) shall develop an inspection and 
maintenance plan for each control device. At a minimum, the plan shall 
contain the control device manufacturer's recommendations for ensuring 
proper operation of the device. Semi-annual inspections shall be 
conducted for each control device with maintenance and replacement of 
control device components made in accordance with the plan.
* * * * *
    (d) Control device monitoring requirements. (1) For each control 
device, except as provided for in paragraph (d)(2) of this section, the 
owner or operator shall install and operate a continuous parameter 
monitoring system in accordance with the requirements of paragraphs 
(d)(3) through (7) of this section. Owners or operators that install 
and operate a flare in accordance with Sec.  63.771(d)(1)(iii) or 
(f)(1)(iii) are exempt from the requirements of paragraphs (d)(4) and 
(5) of this section. The continuous monitoring system shall be designed 
and operated so that a determination can be made on whether the control 
device is achieving the applicable performance requirements of Sec.  
63.771(d), (e)(3), or (f)(1). Each continuous parameter monitoring 
system shall meet the following specifications and requirements:
* * * * *
    (ii) A site-specific monitoring plan must be prepared that 
addresses the monitoring system design, data collection, and the 
quality assurance and quality control elements outlined in paragraph 
(d) of this section and in Sec.  63.8(d). Each CPMS must be installed, 
calibrated, operated, and maintained in accordance with the procedures 
in your approved site-specific monitoring plan. Using the process 
described in Sec.  63.8(f)(4), you may request approval of monitoring 
system quality assurance and quality control procedures alternative to 
those specified in paragraphs (d)(1)(ii)(A) through (E) of this section 
in your site-specific monitoring plan.
    (A) The performance criteria and design specifications for the 
monitoring system equipment, including the sample interface, detector 
signal analyzer, and data acquisition and calculations;
    (B) Sampling interface (e.g., thermocouple) location such that the 
monitoring system will provide representative measurements;
    (C) Equipment performance checks, system accuracy audits, or other 
audit procedures;
    (D) Ongoing operation and maintenance procedures in accordance with 
provisions in Sec.  63.8(c)(1) and (3); and
    (E) Ongoing reporting and recordkeeping procedures in accordance 
with provisions in Sec.  63.10(c), (e)(1), and (e)(2)(i).
    (iii) The owner or operator must conduct the CPMS equipment 
performance checks, system accuracy audits, or other audit procedures 
specified in the site-specific monitoring plan at least once every 12 
months.
    (iv) The owner or operator must conduct a performance evaluation of 
each CPMS in accordance with the site-specific monitoring plan.
    (2) An owner or operator is exempt from the monitoring requirements 
specified in paragraphs (d)(3) through (7) of this section for the 
following types of control devices:
    (i) Except for control devices for small glycol dehydration units, 
a boiler or process heater in which all vent streams are introduced 
with the primary fuel or is used as the primary fuel; or
    (ii) Except for control devices for small glycol dehydration units, 
a boiler or process heater with a design heat input capacity equal to 
or greater than 44 megawatts.
    (3) * * *
    (i) * * *
    (A) For a thermal vapor incinerator that demonstrates during the 
performance test conducted under Sec.  63.772(e) that the combustion 
zone temperature is an accurate indicator of performance, a temperature 
monitoring device equipped with a continuous recorder. The monitoring 
device shall have a minimum accuracy of 2 percent of the 
temperature being monitored in [deg]C, or 2.5 [deg]C, 
whichever value is greater. The temperature sensor shall be installed 
at a location representative of the combustion zone temperature.
* * * * *
    (D) For a boiler or process heater, a temperature monitoring device 
equipped with a continuous recorder. The temperature monitoring device 
shall have a minimum accuracy of 2 percent of the 
temperature being monitored in [deg]C, or 2.5 [deg]C, 
whichever value is greater. The temperature sensor shall be installed 
at a location representative of the combustion zone temperature.
* * * * *
    (G) For a nonregenerative-type carbon adsorption system, the owner 
or operator shall monitor the design carbon replacement interval 
established using a performance test performed in accordance with Sec.  
63.772(e)(3) and shall be based on the total carbon working capacity of 
the control device and source operating schedule.

[[Page 49579]]

    (H) For a control device model whose model is tested under Sec.  
63.772(h):
    (1) The owner or operator shall determine actual average inlet 
waste gas flowrate using the model GRI-GLYCalc \TM\, Version 3.0 or 
higher, ProMax, or AspenTech HYSYS. Inputs to the models shall be 
representative of actual operating conditions of the controlled unit. 
The determination shall be performed to coincide with the visible 
emissions test under Sec.  63.772(i)(3);
    (2) A heat sensing monitoring device equipped with a continuous 
recorder that indicates the continuous ignition of the pilot flame.
* * * * *
    (4) Using the data recorded by the monitoring system, except for 
inlet gas flowrate, the owner or operator must calculate the daily 
average value for each monitored operating parameter for each operating 
day. If the emissions unit operation is continuous, the operating day 
is a 24-hour period. If the emissions unit operation is not continuous, 
the operating day is the total number of hours of control device 
operation per 24-hour period. Valid data points must be available for 
75 percent of the operating hours in an operating day to compute the 
daily average.
    (5) * * *
    (i) The owner or operator shall establish a minimum operating 
parameter value or a maximum operating parameter value, as appropriate 
for the control device, to define the conditions at which the control 
device must be operated to continuously achieve the applicable 
performance requirements of Sec.  63.771(d)(1), (e)(3)(ii), or (f)(1). 
Each minimum or maximum operating parameter value shall be established 
as follows:
    (A) If the owner or operator conducts performance tests in 
accordance with the requirements of Sec.  63.772(e)(3) to demonstrate 
that the control device achieves the applicable performance 
requirements specified in Sec.  63.771(d)(1), (e)(3)(ii) or (f)(1), 
then the minimum operating parameter value or the maximum operating 
parameter value shall be established based on values measured during 
the performance test and supplemented, as necessary, by a condenser 
design analysis or control device manufacturer recommendations or a 
combination of both.
    (B) If the owner or operator uses a condenser design analysis in 
accordance with the requirements of Sec.  63.772(e)(4) to demonstrate 
that the control device achieves the applicable performance 
requirements specified in Sec.  63.771(d)(1), (e)(3)(ii), or (f)(1), 
then the minimum operating parameter value or the maximum operating 
parameter value shall be established based on the condenser design 
analysis and may be supplemented by the condenser manufacturer's 
recommendations.
    (C) If the owner or operator operates a control device where the 
performance test requirement was met under Sec.  63.772(h) to 
demonstrate that the control device achieves the applicable performance 
requirements specified in Sec.  63.771(d)(1), (e)(3)(ii), or (f)(1), 
then the maximum inlet gas flowrate shall be established based on the 
performance test and supplemented, as necessary, by the manufacturer 
recommendations.
    (ii) * * *
    (A) If the owner or operator conducts a performance test in 
accordance with the requirements of Sec.  63.772(e)(3) to demonstrate 
that the condenser achieves the applicable performance requirements in 
Sec.  63.771(d)(1), (e)(3)(ii), or (f)(1), then the condenser 
performance curve shall be based on values measured during the 
performance test and supplemented as necessary by control device design 
analysis, or control device manufacturer's recommendations, or a 
combination of both.
    (B) If the owner or operator uses a control device design analysis 
in accordance with the requirements of Sec.  63.772(e)(4)(i) to 
demonstrate that the condenser achieves the applicable performance 
requirements specified in Sec.  63.771(d)(1), (e)(3)(ii), or (f)(1), 
then the condenser performance curve shall be based on the condenser 
design analysis and may be supplemented by the control device 
manufacturer's recommendations.
    (C) As an alternative to paragraph (d)(5)(ii)(B) of this section, 
the owner or operator may elect to use the procedures documented in the 
GRI report entitled, ``Atmospheric Rich/Lean Method for Determining 
Glycol Dehydrator Emissions'' (GRI-95/0368.1) as inputs for the model 
GRI-GLYCalc \TM\, Version 3.0 or higher, to generate a condenser 
performance curve.
    (6) An excursion for a given control device is determined to have 
occurred when the monitoring data or lack of monitoring data result in 
any one of the criteria specified in paragraphs (d)(6)(i) through (vi) 
of this section being met. When multiple operating parameters are 
monitored for the same control device and during the same operating day 
and more than one of these operating parameters meets an excursion 
criterion specified in paragraphs (d)(6)(i) through (vi) of this 
section, then a single excursion is determined to have occurred for the 
control device for that operating day.
* * * * *
    (ii) For sources meeting Sec.  63.771(d)(1)(ii), an excursion 
occurs when the 365-day average condenser efficiency calculated 
according to the requirements specified in Sec.  63.772(g)(2)(iii) is 
less than 95.0 percent. For sources meeting Sec.  63.771(f)(1), an 
excursion occurs when the 365-day average condenser efficiency 
calculated according to the requirements specified in Sec.  
63.772(g)(2)(iii) is less than 95.0 percent of the identified 365-day 
required percent reduction.
    (iii) For sources meeting Sec.  63.771(d)(1)(ii), if an owner or 
operator has less than 365 days of data, an excursion occurs when the 
average condenser efficiency calculated according to the procedures 
specified in Sec.  63.772(g)(2)(iii)(A) or (B) is less than 90.0 
percent. For sources meeting Sec.  63.771(f)(1), an excursion occurs 
when the 365-day average condenser efficiency calculated according to 
the requirements specified in Sec.  63.772(g)(2)(iii) is less than the 
identified 365-day required percent reduction.
* * * * *
    (vi) For control device whose model is tested under Sec.  63.772(h) 
an excursion occurs when:
    (A) The inlet gas flowrate exceeds the maximum established during 
the test conducted under Sec.  63.772(h).
    (B) Failure of the quarterly visible emissions test conducted under 
Sec.  63.772(i)(3) occurs.
    (7) For each excursion, the owner or operator shall be deemed to 
have failed to have applied control in a manner that achieves the 
required operating parameter limits. Failure to achieve the required 
operating parameter limits is a violation of this standard.
* * * * *
0
20. Section 63.774 is amended by:
0
a. Revising paragraph (b)(3) introductory text;
0
b. Removing and reserving paragraph (b)(3)(ii);
0
c. Revising paragraph (b)(4)(ii) introductory text;
0
d. Adding paragraph (b)(4)(ii)(C);
0
e. Revising paragraph (b)(4)(iii);
0
f. Adding paragraph (b)(7)(ix); and
0
g. Adding paragraphs (g) through (i).
    The revisions and additions read as follows:


Sec.  63.774  Recordkeeping requirements.

* * * * *
    (b) * * *
    (3) Records specified in Sec.  63.10(c) for each monitoring system 
operated by the

[[Page 49580]]

owner or operator in accordance with the requirements of Sec.  
63.773(d). Notwithstanding the requirements of Sec.  63.10(c), 
monitoring data recorded during periods identified in paragraphs 
(b)(3)(i) through (iv) of this section shall not be included in any 
average or percent leak rate computed under this subpart. Records shall 
be kept of the times and durations of all such periods and any other 
periods during process or control device operation when monitors are 
not operating or failed to collect required data.
* * * * *
    (4) * * *
    (ii) Records of the daily average value of each continuously 
monitored parameter for each operating day determined according to the 
procedures specified in Sec.  63.773(d)(4) of this subpart, except as 
specified in paragraphs (b)(4)(ii)(A) through (C) of this section.
* * * * *
    (C) For a control device whose model is tested under Sec.  
63.772(h), the records required in paragraph (h) of this section.
    (iii) Hourly records of the times and durations of all periods when 
the vent stream is diverted from the control device or the device is 
not operating.
* * * * *
    (7) * * *
    (ix) Records identifying the carbon replacement schedule under 
Sec.  63.771(d)(5) and records of each carbon replacement.
* * * * *
    (g) The owner or operator of an affected source subject to this 
subpart shall maintain records of the occurrence and duration of each 
malfunction of operation (i.e., process equipment) or the air pollution 
control equipment and monitoring equipment. The owner or operator shall 
maintain records of actions taken during periods of malfunction to 
minimize emissions in accordance with Sec.  63.764(j), including 
corrective actions to restore malfunctioning process and air pollution 
control and monitoring equipment to its normal or usual manner of 
operation.
    (h) Record the following when using a control device whose model is 
tested under Sec.  63.772(h) to comply with Sec.  63.771(d), 
(e)(3)(ii), and (f)(1):
    (1) All visible emission readings and flowrate calculations made 
during the compliance determination required by Sec.  63.772(i); and
    (2) All hourly records and other recorded periods when the pilot 
flame is absent.
    (i) The date the semi-annual maintenance inspection required under 
Sec.  63.773(b) is performed. Include a list of any modifications or 
repairs made to the control device during the inspection and other 
maintenance performed such as cleaning of the fuel nozzles.

0
21. Section 63.775 is amended by:
0
a. Revising paragraph (b)(1);
0
b. Revising paragraph (b)(6);
0
c. Removing and reserving paragraph (b)(7);
0
d. Revising paragraph (c)(1);
0
e. Revising paragraph (c)(6);
0
f. Revising paragraph (c)(7)(i);
0
g. Revising paragraph (d)(1)(i);
0
h. Revising paragraph (d)(1)(ii) introductory text;
0
i. Revising paragraph (d)(5)(ii);
0
j. Adding paragraph (d)(5)(iv);
0
k. Revising paragraph (d)(11);
0
l. Adding paragraphs (d)(13) and (d)(14);
0
m. Revising paragraphs (e)(2) introductory text, (e)(2)(ii)(B) and (C);
0
n. Adding paragraphs (e)(2)(ii)(E) and (F);
0
o. Adding paragraphs (e)(2)(xi) through (xiv); and
0
p. Adding paragraph (g).
    The revisions and additions read as follows:


Sec.  63.775  Reporting requirements.

* * * * *
    (b) * * *
    (1) The initial notifications required for existing affected 
sources under Sec.  63.9(b)(2) shall be submitted as provided in 
paragraphs (b)(1)(i) and (ii) of this section.
    (i) Except as otherwise provided in paragraph (b)(1)(ii) of this 
section, the initial notifications shall be submitted by 1 year after 
an affected source becomes subject to the provisions of this subpart or 
by June 17, 2000, whichever is later. Affected sources that are major 
sources on or before June 17, 2000, and plan to be area sources by June 
17, 2002, shall include in this notification a brief, nonbinding 
description of a schedule for the action(s) that are planned to achieve 
area source status.
    (ii) An affected source identified under Sec.  63.760(f)(7) or (9) 
shall submit an initial notification required for existing affected 
sources under Sec.  63.9(b)(2) within 1 year after the affected source 
becomes subject to the provisions of this subpart or by October 15, 
2013, whichever is later. An affected source identified under Sec.  
63.760(f)(7) or (9) that plans to be an area source by October 15, 
2015, shall include in this notification a brief, nonbinding 
description of a schedule for the action(s) that are planned to achieve 
area source status.
* * * * *
    (6) If there was a malfunction during the reporting period, the 
Periodic Report specified in paragraph (e) of this section shall 
include the number, duration, and a brief description for each type of 
malfunction which occurred during the reporting period and which caused 
or may have caused any applicable emission limitation to be exceeded. 
The report must also include a description of actions taken by an owner 
or operator during a malfunction of an affected source to minimize 
emissions in accordance with Sec.  63.764(j), including actions taken 
to correct a malfunction.
* * * * *
    (c) * * *
    (1) The initial notifications required under Sec.  63.9(b)(2) not 
later than January 3, 2008. In addition to submitting your initial 
notification to the addressees specified under Sec.  63.9(a), you must 
also submit a copy of the initial notification to the EPA's Office of 
Air Quality Planning and Standards. Send your notification via email to 
Oil and Gas Sector@epa.gov or via U.S. mail or other mail delivery 
service to U.S. EPA, Sector Policies and Programs Division/Fuels and 
Incineration Group (E143-01), Attn: Oil and Gas Project Leader, 
Research Triangle Park, NC 27711.
* * * * *
    (6) If there was a malfunction during the reporting period, the 
Periodic Report specified in paragraph (e) of this section shall 
include the number, duration, and a brief description for each type of 
malfunction which occurred during the reporting period and which caused 
or may have caused any applicable emission limitation to be exceeded. 
The report must also include a description of actions taken by an owner 
or operator during a malfunction of an affected source to minimize 
emissions in accordance with Sec.  63.764(j), including actions taken 
to correct a malfunction.
    (7) * * *
    (i) Documentation of the source's location relative to the nearest 
UA plus offset and UC boundaries. This information shall include the 
latitude and longitude of the affected source; whether the source is 
located in an urban cluster with 10,000 people or more; the distance in 
miles to the nearest urbanized area boundary if the source is not 
located in an urban cluster with 10,000 people or more; and the name of 
the nearest urban cluster with 10,000 people or more and nearest 
urbanized area.
* * * * *
    (d) * * *
    (1) * * *
    (i) The condenser design analysis documentation specified in

[[Page 49581]]

Sec.  63.772(e)(4) of this subpart, if the owner or operator elects to 
prepare a design analysis.
    (ii) If the owner or operator is required to conduct a performance 
test, the performance test results including the information specified 
in paragraphs (d)(1)(ii)(A) and (B) of this section. Results of a 
performance test conducted prior to the compliance date of this subpart 
can be used provided that the test was conducted using the methods 
specified in Sec.  63.772(e)(3) and that the test conditions are 
representative of current operating conditions. If the owner or 
operator operates a combustion control device model tested under Sec.  
63.772(h), an electronic copy of the performance test results shall be 
submitted via email to Oil_and_Gas_PT@EPA.GOV unless the test 
results for that model of combustion control device are posted at the 
following Web site: epa.gov/airquality/oilandgas/.
* * * * *
    (5) * * *
    (ii) An explanation of the rationale for why the owner or operator 
selected each of the operating parameter values established in Sec.  
63.773(d)(5). This explanation shall include any data and calculations 
used to develop the value and a description of why the chosen value 
indicates that the control device is operating in accordance with the 
applicable requirements of Sec.  63.771(d)(1), (e)(3)(ii) or (f)(1).
* * * * *
    (iv) For each carbon adsorber, the predetermined carbon replacement 
schedule as required in Sec.  63.771(d)(5)(i).
* * * * *
    (11) The owner or operator shall submit the analysis prepared under 
Sec.  63.771(e)(2) to demonstrate the conditions by which the facility 
will be operated to achieve the HAP emission reduction of 95.0 percent, 
or the BTEX limit in Sec.  63.765(b)(1)(iii), through process 
modifications or a combination of process modifications and one or more 
control devices.
* * * * *
    (13) If the owner or operator installs a combustion control device 
model tested under the procedures in Sec.  63.772(h), the data listed 
under Sec.  63.772(h)(8).
    (14) For each combustion control device model tested under Sec.  
63.772(h), the information listed in paragraphs (d)(14)(i) through (vi) 
of this section.
    (i) Name, address and telephone number of the control device 
manufacturer.
    (ii) Control device model number.
    (iii) Control device serial number.
    (iv) Date the model of control device was tested by the 
manufacturer.
    (v) Manufacturer's HAP destruction efficiency rating.
    (vi) Control device operating parameters, maximum allowable inlet 
gas flowrate.
    (e) * * *
    (2) The owner or operator shall include the information specified 
in paragraphs (e)(2)(i) through (ix) of this section, as applicable.
* * * * *
    (ii) * * *
    (B) For each excursion caused when the 365-day average condenser 
control efficiency is less than the value specified in Sec.  
63.773(d)(6)(ii), the report must include the 365-day average values of 
the condenser control efficiency, and the date and duration of the 
period that the excursion occurred.
    (C) For each excursion caused when condenser control efficiency is 
less than the value specified in Sec.  63.773(d)(6)(iii), the report 
must include the average values of the condenser control efficiency, 
and the date and duration of the period that the excursion occurred.
* * * * *
    (E) For each excursion caused when the maximum inlet gas flowrate 
identified under Sec.  63.772(h) is exceeded, the report must include 
the values of the inlet gas identified and the date and duration of the 
period that the excursion occurred.
    (F) For each excursion caused when visible emissions determined 
under Sec.  63.772(i) exceed the maximum allowable duration, the report 
must include the date and duration of the period that the excursion 
occurred, repairs affected to the unit, and date the unit was returned 
to service.
* * * * *
    (xi) The results of any periodic test as required in Sec.  
63.772(e)(3) conducted during the reporting period.
    (xii) For each carbon adsorber used to meet the control device 
requirements of Sec.  63.771(d)(1), records of each carbon replacement 
that occurred during the reporting period.
    (xiii) For combustion control device inspections conducted in 
accordance with Sec.  63.773(b) the records specified in Sec.  
63.774(i).
    (xiv) Certification by a responsible official of truth, accuracy, 
and completeness. This certification shall state that, based on 
information and belief formed after reasonable inquiry, the statements 
and information in the document are true, accurate, and complete.
* * * * *
    (g) Electronic reporting. (1) Within 60 days after the date of 
completing each performance test (defined in Sec.  63.2) as required by 
this subpart you must submit the results of the performance tests 
required by this subpart to EPA's WebFIRE database by using the 
Compliance and Emissions Data Reporting Interface (CEDRI) that is 
accessed through EPA's Central Data Exchange (CDX) (www.epa.gov/cdx). 
Performance test data must be submitted in the file format generated 
through use of EPA's Electronic Reporting Tool (ERT) (see http://www.epa.gov/ttn/chief/ert/index.html). Only data collected using test 
methods on the ERT Web site are subject to this requirement for 
submitting reports electronically to WebFIRE. Owners or operators who 
claim that some of the information being submitted for performance 
tests is confidential business information (CBI) must submit a complete 
ERT file including information claimed to be CBI on a compact disk or 
other commonly used electronic storage media (including, but not 
limited to, flash drives) to EPA. The electronic media must be clearly 
marked as CBI and mailed to U.S. EPA/OAPQS/CORE CBI Office, Attention: 
WebFIRE Administrator, MD C404-02, 4930 Old Page Rd., Durham, NC 27703. 
The same ERT file with the CBI omitted must be submitted to EPA via CDX 
as described earlier in this paragraph. At the discretion of the 
delegated authority, you must also submit these reports, including the 
confidential business information, to the delegated authority in the 
format specified by the delegated authority.
    (2) All reports required by this subpart not subject to the 
requirements in paragraph (g)(1) of this section must be sent to the 
Administrator at the appropriate address listed in Sec.  63.13. The 
Administrator or the delegated authority may request a report in any 
form suitable for the specific case (e.g., by commonly used electronic 
media such as Excel spreadsheet, on CD or hard copy). The Administrator 
retains the right to require submittal of reports subject to paragraph 
(g)(1) of this section in paper format.

0
22. Appendix to subpart HH of part 63 is amended by revising Table 2 to 
read as follows:

Appendix to Subpart HH of Part 63--Tables

* * * * *

[[Page 49582]]



    Table 2 to Subpart HH of Part 63--Applicability of 40 CFR Part 63
                    General Provisions to Subpart HH
------------------------------------------------------------------------
                                  Applicable to
General provisions reference       subpart HH            Explanation
------------------------------------------------------------------------
Sec.   63.1(a)(1)...........  Yes.                  ....................
Sec.   63.1(a)(2)...........  Yes.                  ....................
Sec.   63.1(a)(3)...........  Yes.                  ....................
Sec.   63.1(a)(4)...........  Yes.                  ....................
Sec.   63.1(a)(5)...........  No..................  Section reserved.
Sec.   63.1(a)(6)...........  Yes.                  ....................
Sec.   63.1(a)(7) through     No..................  Section reserved.
 (a)(9).
Sec.   63.1(a)(10)..........  Yes.                  ....................
Sec.   63.1(a)(11)..........  Yes.                  ....................
Sec.   63.1(a)(12)..........  Yes.                  ....................
Sec.   63.1(b)(1)...........  No..................  Subpart HH specifies
                                                     applicability.
Sec.   63.1(b)(2)...........  No..................  Section reserved.
Sec.   63.1(b)(3)...........  Yes.                  ....................
Sec.   63.1(c)(1)...........  No..................  Subpart HH specifies
                                                     applicability.
Sec.   63.1(c)(2)...........  Yes.................  Subpart HH exempts
                                                     area sources from
                                                     the requirement to
                                                     obtain a Title V
                                                     permit unless
                                                     otherwise required
                                                     by law as specified
                                                     in Sec.
                                                     63.760(h).
Sec.   63.1(c)(3) and (c)(4)  No..................  Section reserved.
Sec.   63.1(c)(5)...........  Yes.                  ....................
Sec.   63.1(d)..............  No..................  Section reserved.
Sec.   63.1(e)..............  Yes.                  ....................
Sec.   63.2.................  Yes.................  Except definition of
                                                     major source is
                                                     unique for this
                                                     source category and
                                                     there are
                                                     additional
                                                     definitions in
                                                     subpart HH.
Sec.   63.3(a) through (c)..  Yes.                  ....................
Sec.   63.4(a)(1) through     Yes.                  ....................
 (a)(2).
Sec.   63.4(a)(3) through     No..................  Section reserved.
 (a)(5).
Sec.   63.4(b)..............  Yes.                  ....................
Sec.   63.4(c)..............  Yes.                  ....................
Sec.   63.5(a)(1)...........  Yes.                  ....................
Sec.   63.5(a)(2)...........  Yes.                  ....................
Sec.   63.5(b)(1)...........  Yes.                  ....................
Sec.   63.5(b)(2)...........  No..................  Section reserved.
Sec.   63.5(b)(3)...........  Yes.                  ....................
Sec.   63.5(b)(4)...........  Yes.                  ....................
Sec.   63.5(b)(5)...........  No..................  Section Reserved.
Sec.   63.5(b)(6)...........  Yes.                  ....................
Sec.   63.5(c)..............  No..................  Section reserved.
Sec.   63.5(d)(1)...........  Yes.                  ....................
Sec.   63.5(d)(2)...........  Yes.                  ....................
Sec.   63.5(d)(3)...........  Yes.                  ....................
Sec.   63.5(d)(4)...........  Yes.                  ....................
Sec.   63.5(e)..............  Yes.                  ....................
Sec.   63.5(f)(1)...........  Yes.                  ....................
Sec.   63.5(f)(2)...........  Yes.                  ....................
Sec.   63.6(a)..............  Yes.                  ....................
Sec.   63.6(b)(1)...........  Yes.                  ....................
Sec.   63.6(b)(2)...........  Yes.                  ....................
Sec.   63.6(b)(3)...........  Yes.                  ....................
Sec.   63.6(b)(4)...........  Yes.                  ....................
Sec.   63.6(b)(5)...........  Yes.                  ....................
Sec.   63.6(b)(6)...........  No..................  Section reserved.
Sec.   63.6(b)(7)...........  Yes.                  ....................
Sec.   63.6(c)(1)...........  Yes.                  ....................
Sec.   63.6(c)(2)...........  Yes.                  ....................
Sec.   63.6(c)(3) through     No..................  Section reserved.
 (c)(4).
Sec.   63.6(c)(5)...........  Yes.                  ....................
Sec.   63.6(d)..............  No..................  Section reserved.
Sec.   63.6(e)(1)(i)........  No..................  See Sec.   63.764(j)
                                                     for general duty
                                                     requirement.
Sec.   63.6(e)(1)(ii).......  No.                   ....................
Sec.   63.6(e)(1)(iii)......  Yes.                  ....................
Sec.   63.6(e)(2)...........  No..................  Section reserved.
Sec.   63.6(e)(3)...........  No.                   ....................
Sec.   63.6(f)(1)...........  No.                   ....................
Sec.   63.6(f)(2)...........  Yes.                  ....................
Sec.   63.6(f)(3)...........  Yes.                  ....................
Sec.   63.6(g)..............  Yes.                  ....................
Sec.   63.6(h)(1)...........  No.                   ....................
Sec.   63.6(h)(2) through     Yes.                  ....................
 (h)(9).
Sec.   63.6(i)(1) through     Yes.                  ....................
 (i)(14).
Sec.   63.6(i)(15)..........  No..................  Section reserved.
Sec.   63.6(i)(16)..........  Yes.                  ....................
Sec.   63.6(j)..............  Yes.                  ....................

[[Page 49583]]

 
Sec.   63.7(a)(1)...........  Yes.                  ....................
Sec.   63.7(a)(2)...........  Yes.................  But the performance
                                                     test results must
                                                     be submitted within
                                                     180 days after the
                                                     compliance date.
Sec.   63.7(a)(3)...........  Yes.                  ....................
Sec.   63.7(a)(4)...........  Yes.                  ....................
Sec.   63.7(c)..............  Yes.                  ....................
Sec.   63.7(d)..............  Yes.                  ....................
Sec.   63.7(e)(1)...........  No.                   ....................
Sec.   63.7(e)(2)...........  Yes.                  ....................
Sec.   63.7(e)(3)...........  Yes.                  ....................
Sec.   63.7(e)(4)...........  Yes.                  ....................
Sec.   63.7(f)..............  Yes.                  ....................
Sec.   63.7(g)..............  Yes.                  ....................
Sec.   63.7(h)..............  Yes.                  ....................
Sec.   63.8(a)(1)...........  Yes.                  ....................
Sec.   63.8(a)(2)...........  Yes.                  ....................
Sec.   63.8(a)(3)...........  No..................  Section reserved.
Sec.   63.8(a)(4)...........  Yes.                  ....................
Sec.   63.8(b)(1)...........  Yes.                  ....................
Sec.   63.8(b)(2)...........  Yes.                  ....................
Sec.   63.8(b)(3)...........  Yes.                  ....................
Sec.   63.8(c)(1)...........  No.                   ....................
Sec.   63.8(c)(1)(i)........  No.
Sec.   63.8(c)(1)(ii).......  Yes.
Sec.   63.8(c)(1)(iii)......  No.                   ....................
Sec.   63.8(c)(2)...........  Yes.                  ....................
Sec.   63.8(c)(3)...........  Yes.                  ....................
Sec.   63.8(c)(4)...........  Yes.                  ....................
Sec.   63.8(c)(4)(i)........  No..................  Subpart HH does not
                                                     require continuous
                                                     opacity monitors.
Sec.   63.8(c)(4)(ii).......  Yes.                  ....................
Sec.   63.8(c)(5) through     Yes.                  ....................
 (c)(8).
Sec.   63.8(d)(1)...........  Yes.
Sec.   63.8(d)(2)...........  Yes.                  ....................
Sec.   63.8(d)(3)...........  Yes.................  Except for last
                                                     sentence, which
                                                     refers to an SSM
                                                     plan. SSM plans are
                                                     not required.
Sec.   63.8(e)..............  Yes.................  Subpart HH does not
                                                     specifically
                                                     require continuous
                                                     emissions monitor
                                                     performance
                                                     evaluation,
                                                     however, the
                                                     Administrator can
                                                     request that one be
                                                     conducted.
Sec.   63.8(f)(1) through     Yes.                  ....................
 (f)(5).
Sec.   63.8(f)(6)...........  Yes.                  ....................
Sec.   63.8(g)..............  No..................  Subpart HH specifies
                                                     continuous
                                                     monitoring system
                                                     data reduction
                                                     requirements.
Sec.   63.9(a)..............  Yes.                  ....................
Sec.   63.9(b)(1)...........  Yes.                  ....................
Sec.   63.9(b)(2)...........  Yes.................  Existing sources are
                                                     given 1 year
                                                     (rather than 120
                                                     days) to submit
                                                     this notification.
                                                     Major and area
                                                     sources that meet
                                                     Sec.   63.764(e) do
                                                     not have to submit
                                                     initial
                                                     notifications.
Sec.   63.9(b)(3)...........  No..................  Section reserved.
Sec.   63.9(b)(4)...........  Yes.                  ....................
Sec.   63.9(b)(5)...........  Yes.                  ....................
Sec.   63.9(c)..............  Yes.                  ....................
Sec.   63.9(d)..............  Yes.                  ....................
Sec.   63.9(e)..............  Yes.                  ....................
Sec.   63.9(f)..............  Yes.                  ....................
Sec.   63.9(g)..............  Yes.                  ....................
Sec.   63.9(h)(1) through     Yes.................  Area sources located
 (h)(3).                                             outside UA plus
                                                     offset and UC
                                                     boundaries are not
                                                     required to submit
                                                     notifications of
                                                     compliance status.
Sec.   63.9(h)(4)...........  No..................  Section reserved.
Sec.   63.9(h)(5) through     Yes.                  ....................
 (h)(6).
Sec.   63.9(i)..............  Yes.                  ....................
Sec.   63.9(j)..............  Yes.                  ....................
Sec.   63.10(a).............  Yes.                  ....................
Sec.   63.10(b)(1)..........  Yes.................  Sec.   63.774(b)(1)
                                                     requires sources to
                                                     maintain the most
                                                     recent 12 months of
                                                     data on-site and
                                                     allows offsite
                                                     storage for the
                                                     remaining 4 years
                                                     of data.
Sec.   63.10(b)(2)..........  Yes.                  ....................
Sec.   63.10(b)(2)(i).......  No.                   ....................
Sec.   63.10(b)(2)(ii)......  No..................  See Sec.   63.774(g)
                                                     for recordkeeping
                                                     of (1) occurrence
                                                     and duration and
                                                     (2) actions taken
                                                     during
                                                     malfunctions.
Sec.   63.10(b)(2)(iii).....  Yes.                  ....................
Sec.   63.10(b)(2)(iv)        No.                   ....................
 through (b)(2)(v).
Sec.   63.10(b)(2)(vi)        Yes.                  ....................
 through (b)(2)(xiv).

[[Page 49584]]

 
Sec.   63.10(b)(3)..........  Yes.................  Sec.   63.774(b)(1)
                                                     requires sources to
                                                     maintain the most
                                                     recent 12 months of
                                                     data on-site and
                                                     allows offsite
                                                     storage for the
                                                     remaining 4 years
                                                     of data.
Sec.   63.10(c)(1)..........  Yes.                  ....................
Sec.   63.10(c)(2) through    No..................  Sections reserved.
 (c)(4).
Sec.   63.10(c)(5) through    Yes.                  ....................
 (c)(8).
Sec.   63.10(c)(9)..........  No..................  Section reserved.
Sec.   63.10(c)(10) through   No..................  See Sec.   63.774(g)
 (11).                                               for recordkeeping
                                                     of malfunctions.
Sec.   63.10(c)(12) through   Yes.                  ....................
 (14).
Sec.   63.10(c)(15).........  No.                   ....................
Sec.   63.10(d)(1)..........  Yes.                  ....................
Sec.   63.10(d)(2)..........  Yes.................  Area sources located
                                                     outside UA plus
                                                     offset and UC
                                                     boundaries do not
                                                     have to submit
                                                     performance test
                                                     reports.
Sec.   63.10(d)(3)..........  Yes.                  ....................
Sec.   63.10(d)(4)..........  Yes.                  ....................
Sec.   63.10(d)(5)..........  No..................  See Sec.
                                                     63.775(b)(6) or
                                                     (c)(6) for
                                                     reporting of
                                                     malfunctions.
Sec.   63.10(e)(1)..........  Yes.................  Area sources located
                                                     outside UA plus
                                                     offset and UC
                                                     boundaries are not
                                                     required to submit
                                                     reports.
Sec.   63.10(e)(2)..........  Yes.................  Area sources located
                                                     outside UA plus
                                                     offset and UC
                                                     boundaries are not
                                                     required to submit
                                                     reports.
Sec.   63.10(e)(3)(i).......  Yes.................  Subpart HH requires
                                                     major sources to
                                                     submit Periodic
                                                     Reports semi-
                                                     annually. Area
                                                     sources are
                                                     required to submit
                                                     Periodic Reports
                                                     annually. Area
                                                     sources located
                                                     outside UA plus
                                                     offset and UC
                                                     boundaries are not
                                                     required to submit
                                                     reports.
Sec.   63.10(e)(3)(i)(A)....  Yes.                  ....................
Sec.   63.10(e)(3)(i)(B)....  Yes.                  ....................
Sec.   63.10(e)(3)(i)(C)....  No.
Sec.   63.10(e)(3)(i)(D)....  Yes.................  Section reserved.
Sec.   63.10(e)(3)(ii)        Yes.
 through (viii).
Sec.   63.10(e)(4)..........  Yes.                  ....................
Sec.   63.10(f).............  Yes.                  ....................
Sec.   63.11(a) and (b).....  Yes.                  ....................
Sec.   63.11(c), (d), and     Yes.                  ....................
 (e).
Sec.   63.12(a) through (c).  Yes.                  ....................
Sec.   63.13(a) through (c).  Yes.                  ....................
Sec.   63.14(a) through (q).  Yes.                  ....................
Sec.   63.15(a) and (b).....  Yes.                  ....................
Sec.   63.16................  Yes.                  ....................
------------------------------------------------------------------------

Subpart HHH--[Amended]

0
23. Section 63.1270 is amended by:
0
a. Revising paragraph (a) introductory text;
0
b. Revising paragraph (a)(4);
0
c. Revising paragraph (b);
0
d. Revising paragraphs (d)(1) and (2); and
0
e. Adding paragraphs (d)(3) and (4).
    The revisions and additions read as follows:


Sec.  63.1270  Applicability and designation of affected source.

    (a) This subpart applies to owners and operators of natural gas 
transmission and storage facilities that transport or store natural gas 
prior to entering the pipeline to a local distribution company or to a 
final end user (if there is no local distribution company), and that 
are major sources of hazardous air pollutants (HAP) emissions as 
defined in Sec.  63.1271. Emissions for major source determination 
purposes can be estimated using the maximum natural gas throughput 
calculated in either paragraph (a)(1) or (2) of this section and 
paragraphs (a)(3) and (4) of this section. As an alternative to 
calculating the maximum natural gas throughput, the owner or operator 
of a new or existing source may use the facility design maximum natural 
gas throughput to estimate the maximum potential emissions. Other means 
to determine the facility's major source status are allowed, provided 
the information is documented and recorded to the Administrator's 
satisfaction in accordance with Sec.  63.10(b)(3). A compressor station 
that transports natural gas prior to the point of custody transfer or 
to a natural gas processing plant (if present) is not considered a part 
of the natural gas transmission and storage source category. A facility 
that is determined to be an area source, but subsequently increases its 
emissions or its potential to emit above the major source levels 
(without obtaining and complying with other limitations that keep its 
potential to emit HAP below major source levels), and becomes a major 
source, must comply thereafter with all applicable provisions of this 
subpart starting on the applicable compliance date specified in 
paragraph (d) of this section. Nothing in this paragraph is intended to 
preclude a source from limiting its potential to emit through other 
appropriate mechanisms that may be available through the permitting 
authority.
* * * * *
    (4) The owner or operator shall determine the maximum values for 
other parameters used to calculate potential emissions as the maximum 
over the same period for which maximum throughput is determined as 
specified in paragraph (a)(1) or (a)(2) of this section. These 
parameters shall be based on an annual average or the highest single 
measured value. For estimating maximum potential emissions from glycol 
dehydration units, the glycol circulation rate used in the calculation 
shall be the unit's maximum rate under its physical and

[[Page 49585]]

operational design consistent with the definition of potential to emit 
in Sec.  63.2.
    (b) The affected source is each new and existing glycol dehydration 
unit specified in paragraphs (b)(1) through (3) of this section.
    (1) Each large glycol dehydration unit;
    (2) Each small glycol dehydration unit for which construction 
commenced on or before August 23, 2011, is an existing small glycol 
dehydration unit.
    (3) Each small glycol dehydration unit for which construction 
commenced after August 23, 2011, is a new small glycol dehydration 
unit.
* * * * *
    (d) * * *
    (1) Except as specified in paragraphs (d)(3) through (4) of this 
section, the owner or operator of an affected source, the construction 
or reconstruction of which commenced before February 6, 1998, shall 
achieve compliance with this provisions of the subpart no later than 
June 17, 2002 except as provided for in Sec.  63.6(i). The owner or 
operator of an area source, the construction or reconstruction of which 
commenced before February 6, 1998, that increases its emissions of (or 
its potential to emit) HAP such that the source becomes a major source 
that is subject to this subpart shall comply with this subpart 3 years 
after becoming a major source.
    (2) Except as specified in paragraphs (d)(3) through (4) of this 
section, the owner or operator of an affected source, the construction 
or reconstruction of which commences on or after February 6, 1998, 
shall achieve compliance with the provisions of this subpart 
immediately upon initial startup or June 17, 1999, whichever date is 
later. Area sources, the construction or reconstruction of which 
commences on or after February 6, 1998, that become major sources shall 
comply with the provisions of this standard immediately upon becoming a 
major source.
    (3) Each affected small glycol dehydration unit, as defined in 
Sec.  63.1271, located at a major source, that commenced construction 
before August 23, 2011, must achieve compliance no later than October 
15, 2015, except as provided in Sec.  63.6(i).
    (4) Each affected small glycol dehydration unit, as defined in 
Sec.  63.1271, located at a major source, that commenced construction 
on or after August 23, 2011, must achieve compliance immediately upon 
initial startup or October 15, 2012, whichever is later.
* * * * *

0
24. Section 63.1271 is amended by:

0
a. Adding, in alphabetical order, definitions for the terms 
``affirmative defense,'' ``BTEX,'' ``flare,'' ``large glycol 
dehydration units,'' ``responsible official'' and ``small glycol 
dehydration units;'' and
0
b. Revising the definition for ``glycol dehydration unit baseline 
operations.''
    The additions and revision read as follows:


Sec.  63.1271  Definitions.

* * * * *
    Affirmative defense means, in the context of an enforcement 
proceeding, a response or defense put forward by a defendant, regarding 
which the defendant has the burden of proof, and the merits of which 
are independently and objectively evaluated in a judicial or 
administrative proceeding.
* * * * *
    BTEX means benzene, toluene, ethyl benzene, and xylene.
* * * * *
    Flare means a thermal oxidation system using an open flame (i.e., 
without enclosure).
* * * * *
    Glycol dehydration unit baseline operations means operations 
representative of the large glycol dehydration unit operations as of 
June 17, 1999 and the small glycol dehydration unit operations as of 
August 23, 2011. For the purposes of this subpart, for determining the 
percentage of overall HAP emission reduction attributable to process 
modifications, glycol dehydration unit baseline operations shall be 
parameter values (including, but not limited to, glycol circulation 
rate or glycol-HAP absorbency) that represent actual long-term 
conditions (i.e., at least 1 year). Glycol dehydration units in 
operation for less than 1 year shall document that the parameter values 
represent expected long-term operating conditions had process 
modifications not been made.
* * * * *
    Large glycol dehydration unit means a glycol dehydration unit with 
an actual annual average natural gas flowrate equal to or greater than 
283.0 thousand standard cubic meters per day and actual annual average 
benzene emissions equal to or greater than 0.90 Mg/yr, determined 
according to Sec.  63.1282(a). A glycol dehydration unit complying with 
the 0.9 Mg/yr control option under 63.1275(b)(1)(ii) is considered to 
be a large dehydrator.
* * * * *
    Responsible official means one of the following:
    (1) For a corporation: A president, secretary, treasurer, or vice-
president of the corporation in charge of a principal business 
function, or any other person who performs similar policy or decision-
making functions for the corporation, or a duly authorized 
representative of such person if the representative is responsible for 
the overall operation of one or more manufacturing, production, or 
operating facilities applying for or subject to a permit and either:
    (i) The facilities employ more than 250 persons or have gross 
annual sales or expenditures exceeding $25 million (in second quarter 
1980 dollars); or
    (ii) The delegation of authority to such representatives is 
approved in advance by the permitting authority;
    (2) For a partnership or sole proprietorship: A general partner or 
the proprietor, respectively;
    (3) For a municipality, State, Federal, or other public agency: 
Either a principal executive officer or ranking elected official. For 
the purposes of this part, a principal executive officer of a Federal 
agency includes the chief executive officer having responsibility for 
the overall operations of a principal geographic unit of the agency 
(e.g., a Regional Administrator of EPA); or
    (4) For affected sources:
    (i) The designated representative in so far as actions, standards, 
requirements, or prohibitions under title IV of the Act or the 
regulations promulgated thereunder are concerned; and
    (ii) The designated representative for any other purposes under 
part 70.
* * * * *
    Small glycol dehydration unit means a glycol dehydration unit, 
located at a major source, with an actual annual average natural gas 
flowrate less than 283.0 thousand standard cubic meters per day or 
actual annual average benzene emissions less than 0.90 Mg/yr, 
determined according to Sec.  63.1282(a).
* * * * *

0
25. Section 63.1272 is revised to read as follows:


Sec.  63.1272  Affirmative defense for violations of emission standards 
during malfunction.

    (a) The provisions set forth in this subpart shall apply at all 
times.
    (b) [Reserved]
    (c) [Reserved]
    (d) In response to an action to enforce the standards set forth in 
this subpart, you may assert an affirmative defense to a claim for 
civil penalties for violations of such standards that are caused by 
malfunction, as defined at Sec.  63.2. Appropriate penalties may be 
assessed; however, if you fail to meet your burden of proving all of 
the requirements in the affirmative defense, the affirmative defense 
shall not be available for claims for injunctive relief.

[[Page 49586]]

    (1) To establish the affirmative defense in any action to enforce 
such a standard, you must timely meet the reporting requirements in 
paragraph (d)(2) of this section, and must prove by a preponderance of 
evidence that:
    (i) The violation:
    (A) Was caused by a sudden, infrequent, and unavoidable failure of 
air pollution control equipment, process equipment, or a process to 
operate in a normal or usual manner; and
    (B) Could not have been prevented through careful planning, proper 
design or better operation and maintenance practices; and
    (C) Did not stem from any activity or event that could have been 
foreseen and avoided, or planned for; and
    (D) Was not part of a recurring pattern indicative of inadequate 
design, operation, or maintenance; and
    (ii) Repairs were made as expeditiously as possible when a 
violation occurred. Off-shift and overtime labor were used, to the 
extent practicable to make these repairs; and
    (iii) The frequency, amount and duration of the violation 
(including any bypass) were minimized to the maximum extent 
practicable; and
    (iv) If the violation resulted from a bypass of control equipment 
or a process, then the bypass was unavoidable to prevent loss of life, 
personal injury, or severe property damage; and
    (v) All possible steps were taken to minimize the impact of the 
violation on ambient air quality, the environment, and human health; 
and
    (vi) All emissions monitoring and control systems were kept in 
operation if at all possible, consistent with safety and good air 
pollution control practices; and
    (vii) All of the actions in response to the violation were 
documented by properly signed, contemporaneous operating logs; and
    (viii) At all times, the affected source was operated in a manner 
consistent with good practices for minimizing emissions; and
    (ix) A written root cause analysis has been prepared, the purpose 
of which is to determine, correct, and eliminate the primary causes of 
the malfunction and the violation resulting from the malfunction event 
at issue. The analysis shall also specify, using best monitoring 
methods and engineering judgment, the amount of any emissions that were 
the result of the malfunction.
    (2) Report. The owner or operator seeking to assert an affirmative 
defense shall submit a written report to the Administrator with all 
necessary supporting documentation, that it has met the requirements 
set forth in paragraph (d)(1) of this section. This affirmative defense 
report shall be included in the first periodic compliance, deviation 
report or excess emission report otherwise required after the initial 
occurrence of the violation of the relevant standard (which may be the 
end of any applicable averaging period). If such compliance, deviation 
report or excess emission report is due less than 45 days after the 
initial occurrence of the violation, the affirmative defense report may 
be included in the second compliance, deviation report or excess 
emission report due after the initial occurrence of the violation of 
the relevant standard.

0
26. Section 63.1274 is amended by:
0
a. Revising paragraph (c) introductory text;
0
b. Removing and reserving paragraph (d);
0
c. Revising paragraph (g); and
0
d. Adding paragraph (h).
    The revisions and addition read as follows:


Sec.  63.1274  General standards.

* * * * *
    (c) The owner or operator of an affected source (i.e., glycol 
dehydration unit) located at an existing or new major source of HAP 
emissions shall comply with the requirements in this subpart as 
follows:
* * * * *
    (d) [Reserved]
* * * * *
    (g) In all cases where the provisions of this subpart require an 
owner or operator to repair leaks by a specified time after the leak is 
detected, it is a violation of this standard to fail to take action to 
repair the leak(s) within the specified time. If action is taken to 
repair the leak(s) within the specified time, failure of that action to 
successfully repair the leak(s) is not a violation of this standard. 
However, if the repairs are unsuccessful, and a leak is detected, the 
owner or operator shall take further action as required by the 
applicable provisions of this subpart.
    (h) At all times the owner or operator must operate and maintain 
any affected source, including associated air pollution control 
equipment and monitoring equipment, in a manner consistent with safety 
and good air pollution control practices for minimizing emissions. 
Determination of whether such operation and maintenance procedures are 
being used will be based on information available to the Administrator 
which may include, but is not limited to, monitoring results, review of 
operation and maintenance procedures, review of operation and 
maintenance records, and inspection of the source.

0
27. Section 63.1275 is amended by:
0
a. Revising paragraph (a);
0
b. Revising paragraph (b)(1);
0
c. Revising paragraph (c)(2); and
0
d. Revising paragraph (c)(3).

The revisions read as follows:


Sec.  63.1275  Glycol dehydration unit process vent standards.

    (a) This section applies to each glycol dehydration unit subject to 
this subpart that must be controlled for air emissions as specified in 
paragraph (c)(1) of Sec.  63.1274.
    (b) * * *
    (1) For each glycol dehydration unit process vent, the owner or 
operator shall control air emissions by either paragraph (b)(1)(i) or 
(iii) of this section.
    (i) The owner or operator of a large glycol dehydration unit, as 
defined in Sec.  63.1271, shall connect the process vent to a control 
device or a combination of control devices through a closed-vent 
system. The closed-vent system shall be designed and operated in 
accordance with the requirements of Sec.  63.1281(c). The control 
device(s) shall be designed and operated in accordance with the 
requirements of Sec.  63.1281(d).
    (ii) The owner or operator of a large glycol dehydration unit shall 
connect the process vent to a control device or a combination of 
control devices through a closed-vent system and the outlet benzene 
emissions from the control device(s) shall be less than 0.90 megagrams 
per year. The closed-vent system shall be designed and operated in 
accordance with the requirements of Sec.  63.1281(c). The control 
device(s) shall be designed and operated in accordance with the 
requirements of Sec.  63.1281(d), except that the performance 
requirements specified in Sec.  63.1281(d)(1)(i) and (ii) do not apply.
    (iii) You must limit BTEX emissions from each existing small glycol 
dehydration unit, as defined in Sec.  63.1271, to the limit determined 
in Equation 1 of this section. You must limit BTEX emissions from each 
new small glycol dehydration unit process vent, as defined in Sec.  
63.1271, to the limit determined in Equation 2 of this section. The 
limits determined using Equation 1 or Equation 2, of this section, must 
be met in accordance with one of the alternatives specified in 
paragraphs (b)(1)(iii)(A) through (D) of this section.

[[Page 49587]]

[GRAPHIC] [TIFF OMITTED] TR16AU12.012


Where:

ELBTEX = Unit-specific BTEX emission limit, megagrams per 
year;
3.10 x 10-4 = BTEX emission limit, grams BTEX/standard 
cubic meter-ppmv;
Throughput = Annual average daily natural gas throughput, standard 
cubic meters per day;
Ci,BTEX = Annual average BTEX concentration of the 
natural gas at the inlet to the glycol dehydration unit, ppmv.
[GRAPHIC] [TIFF OMITTED] TR16AU12.013


Where:

ELBTEX = Unit-specific BTEX emission limit, megagrams per 
year;
5.44 x 10-5 = BTEX emission limit, grams BTEX/standard 
cubic meter-ppmv;
Throughput = Annual average daily natural gas throughput, standard 
cubic meters per day;
Ci,BTEX = Annual average BTEX concentration of the 
natural gas at the inlet to the glycol dehydration unit, ppmv.

    (A) Connect the process vent to a control device or combination of 
control devices through a closed-vent system. The closed vent system 
shall be designed and operated in accordance with the requirements of 
Sec.  63.1281(c). The control device(s) shall be designed and operated 
in accordance with the requirements of Sec.  63.1281(f).
    (B) Meet the emissions limit through process modifications in 
accordance with the requirements specified in Sec.  63.1281(e).
    (C) Meet the emission limit for each small glycol dehydration unit 
using a combination of process modifications and one or more control 
devices through the requirements specified in paragraphs (b)(1)(iii)(A) 
and (B) of this section.
    (D) Demonstrate that the emissions limit is met through actual 
uncontrolled operation of the small glycol dehydration unit. Document 
operational parameters in accordance with the requirements specified in 
Sec.  63.1281(e) and emissions in accordance with the requirements 
specified in Sec.  63.1282(a)(3).
* * * * *
    (c) * * *
    (2) The owner or operator shall demonstrate, to the Administrator's 
satisfaction, that the total HAP emissions to the atmosphere from the 
large glycol dehydration unit process vent are reduced by 95.0 percent 
through process modifications or a combination of process modifications 
and one or more control devices, in accordance with the requirements 
specified in Sec.  63.1281(e).
    (3) Control of HAP emissions from a GCG separator (flash tank) vent 
is not required if the owner or operator demonstrates, to the 
Administrator's satisfaction, that total emissions to the atmosphere 
from the glycol dehydration unit process vent are reduced by one of the 
levels specified in paragraph (c)(3)(i) through (iv) through the 
installation and operation of controls as specified in paragraph (b)(1) 
of this section.
    (i) For any large glycol dehydration unit, HAP emissions are 
reduced by 95.0 percent or more.
    (ii) For any large glycol dehydration unit, benzene emissions are 
reduced to a level less than 0.90 megagrams per year.
    (iii) For each existing small glycol dehydration unit, BTEX 
emissions are reduced to a level less than the limit calculated in 
Equation 1 of paragraph (b)(1)(iii) of this section.
    (iv) For each new small glycol dehydration unit, BTEX emissions are 
reduced to a level less than the limit calculated in Equation 2 of 
paragraph (b)(1)(iii) of this section.

0
28. Section 63.1281 is amended by:
0
a. Revising paragraph (c)(1);
0
b. Revising the heading of paragraph (d).
0
c. Adding paragraph (d) introductory text;
0
d. Revising paragraph (d)(1)(i)(C);
0
e. Revising paragraphs (d)(1)(ii) and (iii);
0
f. Revising paragraph (d)(4)(i);
0
g. Revising paragraph (d)(5)(i);
0
h. Revising paragraph (e)(2);
0
i. Revising paragraph (e)(3) introductory text;
0
j. Revising paragraph (e)(3)(ii); and
0
k. Adding paragraph (f).

The revisions and additions read as follows:


Sec.  63.1281  Control equipment requirements.

* * * * *
    (c) * * *
    (1) The closed-vent system shall route all gases, vapors, and fumes 
emitted from the material in an emissions unit to a control device that 
meets the requirements specified in paragraph (d) of this section.
* * * * *
    (d) Control device requirements for sources except small glycol 
dehydration units. Owners and operators of small glycol dehydration 
units shall comply with the control requirements in paragraph (f) of 
this section.
    (1) * * *
    (i) * * *
    (C) Operates at a minimum temperature of 760 degrees C, provided 
the control device has demonstrated, under Sec.  63.1282(d), that 
combustion zone temperature is an indicator of destruction efficiency.
* * * * *
    (ii) A vapor recovery device (e.g., carbon adsorption system or 
condenser) or other non-destructive control device that is designed and 
operated to reduce the mass content of either TOC or total HAP in the 
gases vented to the device by 95.0 percent by weight or greater as 
determined in accordance with the requirements of Sec.  63.1282(d).
    (iii) A flare, as defined in Sec.  63.1271, that is designed and 
operated in accordance with the requirements of Sec.  63.11(b).
* * * * *
    (4) * * *
    (i) Each control device used to comply with this subpart shall be 
operating at all times when gases, vapors, and fumes are vented from 
the emissions unit or units through the closed vent system to the 
control device as required under Sec.  63.1275. An owner or operator 
may vent more than one unit to a control device used to comply with 
this subpart.
* * * * *
    (5) * * *
    (i) Following the initial startup of the control device, all carbon 
in the control device shall be replaced with fresh carbon on a regular, 
predetermined time interval that is no longer than the carbon service 
life established for the

[[Page 49588]]

carbon adsorption system. Records identifying the schedule for 
replacement and records of each carbon replacement shall be maintained 
as required in Sec.  63.1284(b)(7)(ix). The schedule for replacement 
shall be submitted with the Notification of Compliance Status Report as 
specified in Sec.  63.1285(d)(4)(iv). Each carbon replacement must be 
reported in the Periodic Reports as specified in Sec.  
63.1285(e)(2)(xi).
* * * * *
    (e) * * *
    (2) The owner or operator shall document, to the Administrator's 
satisfaction, the conditions for which glycol dehydration unit baseline 
operations shall be modified to achieve the 95.0 percent overall HAP 
emission reduction, or BTEX limit determined in Sec.  
63.1275(b)(1)(iii), as applicable, either through process modifications 
or through a combination of process modifications and one or more 
control devices. If a combination of process modifications and one or 
more control devices are used, the owner or operator shall also 
establish the emission reduction to be achieved by the control device 
to achieve an overall HAP emission reduction of 95.0 percent for the 
glycol dehydration unit process vent or, if applicable, the BTEX limit 
determined in Sec.  63.1275(b)(1)(iii) for the small glycol dehydration 
unit process vent. Only modifications in glycol dehydration unit 
operations directly related to process changes, including but not 
limited to changes in glycol circulation rate or glycol-HAP absorbency, 
shall be allowed. Changes in the inlet gas characteristics or natural 
gas throughput rate shall not be considered in determining the overall 
emission reduction due to process modifications.
    (3) The owner or operator that achieves a 95.0 percent HAP emission 
reduction or meets the BTEX limit determined in Sec.  
63.1275(b)(1)(iii), as applicable, using process modifications alone 
shall comply with paragraph (e)(3)(i) of this section. The owner or 
operator that achieves a 95.0 percent HAP emission reduction or meets 
the BTEX limit determined in Sec.  63.1275(b)(1)(iii), as applicable, 
using a combination of process modifications and one or more control 
devices shall comply with paragraphs (e)(3)(i) and (e)(3)(ii) of this 
section.
* * * * *
    (ii) The owner or operator shall comply with the control device 
requirements specified in paragraph (d) or (f) of this section, as 
applicable, except that the emission reduction or limit achieved shall 
be the emission reduction or limit specified for the control device(s) 
in paragraph (e)(2) of this section.
    (f) Control device requirements for small glycol dehydration units. 
(1) The control device used to meet BTEX the emission limit calculated 
in Sec.  63.1275(b)(1)(iii) shall be one of the control devices 
specified in paragraphs (f)(1)(i) through (iii) of this section.
    (i) An enclosed combustion device (e.g., thermal vapor incinerator, 
catalytic vapor incinerator, boiler, or process heater) that is 
designed and operated to meet the levels specified in paragraphs 
(f)(1)(i)(A) or (B) of this section. If a boiler or process heater is 
used as the control device, then the vent stream shall be introduced 
into the flame zone of the boiler or process heater.
    (A) The mass content of BTEX in the gases vented to the device is 
reduced as determined in accordance with the requirements of Sec.  
63.1282(d).
    (B) The concentration of either TOC or total HAP in the exhaust 
gases at the outlet of the device is reduced to a level equal to or 
less than 20 parts per million by volume on a dry basis corrected to 3 
percent oxygen as determined in accordance with the requirements of 
Sec.  63.1282(e).
    (ii) A vapor recovery device (e.g., carbon adsorption system or 
condenser) or other non-destructive control device that is designed and 
operated to reduce the mass content of BTEX in the gases vented to the 
device as determined in accordance with the requirements of Sec.  
63.1282(d).
    (iii) A flare, as defined in Sec.  63.1271, that is designed and 
operated in accordance with the requirements of Sec.  63.11(b).
    (2) The owner or operator shall operate each control device in 
accordance with the requirements specified in paragraphs (f)(2)(i) and 
(ii) of this section.
    (i) Each control device used to comply with this subpart shall be 
operating at all times. An owner or operator may vent more than one 
unit to a control device used to comply with this subpart.
    (ii) For each control device monitored in accordance with the 
requirements of Sec.  63.1283(d), the owner or operator shall 
demonstrate compliance according to the requirements of either Sec.  
63.1282(e) or (h).
    (3) For each carbon adsorption system used as a control device to 
meet the requirements of paragraph (f)(1) of this section, the owner or 
operator shall manage the carbon as required under (d)(5)(i) and (ii) 
of this section.


0
29. Section 63.1282 is amended by:
0
a. Revising paragraph (a) introductory text;
0
b. Revising paragraph (a)(1)(ii);
0
c. Revising paragraph (a)(2);
0
d. Revising paragraph (b)(6)(i);
0
e. Adding paragraph (c);
0
f. Revising paragraph (d) introductory text;
0
g. Revising paragraphs (d)(1)(i) through (v);
0
h. Revising paragraph (d)(2);
0
i. Revising paragraph (d)(3) introductory text;
0
j. Revising paragraph (d)(3)(i)(B);
0
k. Revising paragraph (d)(3)(iii) introductory text;
0
l. Revising paragraph (d)(3)(iv) introductory text;
0
m. Revising paragraph (d)(3)(iv)(C)(1);
0
n. Adding paragraphs (d)(3)(v) and (vi);
0
o. Revising paragraph (d)(4) introductory text;
0
p. Revising paragraph (d)(4)(i);
0
q. Revising paragraph (d)(5);
0
r. Revising paragraph (e) introductory text;
0
s. Revising paragraphs (e)(2) and (3);
0
t. Adding paragraphs (e)(4) through (e)(6);
0
u. Revising paragraph (f) introductory text;
0
v. Revising paragraph (f)(1);
0
w. Revising paragraph (f)(2) introductory text;
0
x. Revising paragraph (f)(2)(iii) introductory text, (f)(2)(iii)(A) and 
(f)(2)(iii)(B);
0
y. Revising paragraph (f)(3); and
0
z. Adding paragraphs (g) and (h).
The revisions and additions read as follows:


Sec.  63.1282  Test methods, compliance procedures, and compliance 
demonstrations.

    (a) Determination of glycol dehydration unit flowrate, benzene 
emissions, or BTEX emissions. The procedures of this paragraph shall be 
used by an owner or operator to determine glycol dehydration unit 
natural gas flowrate, benzene emissions, or BTEX emissions.
    (1) * * *
    (ii) The owner or operator shall document, to the Administrator's 
satisfaction, the actual annual average natural gas flowrate to the 
glycol dehydration unit.
    (2) The determination of actual average benzene or BTEX emissions 
from a glycol dehydration unit shall be made using the procedures of 
either paragraph (a)(2)(i) or (ii) of this section. Emissions shall be 
determined either uncontrolled or with federally enforceable controls 
in place.
    (i) The owner or operator shall determine actual average benzene or

[[Page 49589]]

BTEX emissions using the model GRI-GLYCalc\TM\, Version 3.0 or higher, 
and the procedures presented in the associated GRI-GLYCalc\TM\ 
Technical Reference Manual. Inputs to the model shall be representative 
of actual operating conditions of the glycol dehydration unit and may 
be determined using the procedures documented in the Gas Research 
Institute (GRI) report entitled ``Atmospheric Rich/Lean Method for 
Determining Glycol Dehydrator Emissions'' (GRI-95/0368.1); or
    (ii) The owner or operator shall determine an average mass rate of 
benzene or BTEX emissions in kilograms per hour through direct 
measurement by performing three runs of Method 18 in 40 CFR part 60, 
appendix A; or ASTM D6420-99 (Reapproved 2004) (incorporated by 
reference as specified in Sec.  63.14), as specified in Sec.  
63.772(a)(1)(ii); or an equivalent method; and averaging the results of 
the three runs. Annual emissions in kilograms per year shall be 
determined by multiplying the mass rate by the number of hours the unit 
is operated per year. This result shall be converted to megagrams per 
year.
    (b) * * *
    (6) * * *
    (i) Except as provided in paragraph (b)(6)(ii) of this section, the 
detection instrument shall meet the performance criteria of Method 21 
of 40 CFR part 60, appendix A, except the instrument response factor 
criteria in section 3.1.2(a) of Method 21 shall be for the average 
composition of the process fluid not each individual volatile organic 
compound in the stream. For process streams that contain nitrogen, air, 
or other inert gases that are not organic HAP or VOC, the average 
stream response factor shall be calculated on an inert-free basis.
* * * * *
    (c) Test procedures and compliance demonstrations for small glycol 
dehydration units. This paragraph (c) applies to the test procedures 
for small dehydration units.
    (1) If the owner or operator is using a control device to comply 
with the emission limit in Sec.  63.1275(b)(1)(iii), the requirements 
of paragraph (d) of this section apply. Compliance is demonstrated 
using the methods specified in paragraph (e) of this section.
    (2) If no control device is used to comply with the emission limit 
in Sec.  63.1275(b)(1)(iii), the owner or operator must determine the 
glycol dehydration unit BTEX emissions as specified in paragraphs 
(c)(2)(i) through (iii) of this section. Compliance is demonstrated if 
the BTEX emissions determined as specified in paragraphs (c)(2)(i) 
through (iii) are less than the emission limit calculated using the 
equation in Sec.  63.1275(b)(1)(iii).
    (i) Method 1 or 1A, 40 CFR part 60, appendix A, as appropriate, 
shall be used for selection of the sampling sites at the outlet of the 
glycol dehydration unit process vent. Any references to particulate 
mentioned in Methods 1 and 1A do not apply to this section.
    (ii) The gas volumetric flowrate shall be determined using Method 
2, 2A, 2C, or 2D, 40 CFR part 60, appendix A, as appropriate.
    (iii) The BTEX emissions from the outlet of the glycol dehydration 
unit process vent shall be determined using the procedures specified in 
paragraph (d)(3)(v) of this section. As an alternative, the mass rate 
of BTEX at the outlet of the glycol dehydration unit process vent may 
be calculated using the model GRI-GLYCalc\TM\, Version 3.0 or higher, 
and the procedures presented in the associated GRI-GLYCalc\TM\ 
Technical Reference Manual. Inputs to the model shall be representative 
of actual operating conditions of the glycol dehydration unit and shall 
be determined using the procedures documented in the Gas Research 
Institute (GRI) report entitled ``Atmospheric Rich/Lean Method for 
Determining Glycol Dehydrator Emissions'' (GRI-95/0368.1). When the 
BTEX mass rate is calculated for glycol dehydration units using the 
model GRI-GLYCalc\TM\, all BTEX measured by Method 18, 40 CFR part 60, 
appendix A, shall be summed.
    (d) Control device performance test procedures. This paragraph 
applies to the performance testing of control devices. The owners or 
operators shall demonstrate that a control device achieves the 
performance requirements of Sec.  63.1281(d)(1), (e)(3)(ii), or (f)(1) 
using a performance test as specified in paragraph (d)(3) of this 
section. Owners or operators using a condenser have the option to use a 
design analysis as specified in paragraph (d)(4) of this section. The 
owner or operator may elect to use the alternative procedures in 
paragraph (d)(5) of this section for performance testing of a condenser 
used to control emissions from a glycol dehydration unit process vent. 
Flares shall meet the provisions in paragraph (d)(2) of this section. 
As an alternative to conducting a performance test under this section 
for combustion control devices, a control device that can be 
demonstrated to meet the performance requirements of Sec.  
63.1281(d)(1), (e)(3)(ii), or (f)(1) through a performance test 
conducted by the manufacturer, as specified in paragraph (g) of this 
section, can be used.
    (1) * * *
    (i) Except as specified in paragraph (d)(2) of this section, a 
flare, as defined in Sec.  63.1271, that is designed and operated in 
accordance with Sec.  63.11(b);
    (ii) Except for control devices used for small glycol dehydration 
units, a boiler or process heater with a design heat input capacity of 
44 megawatts or greater;
    (iii) Except for control devices used for small glycol dehydration 
units, a boiler or process heater into which the vent stream is 
introduced with the primary fuel or is used as the primary fuel;
    (iv) Except for control devices used for small glycol dehydration 
units, a boiler or process heater burning hazardous waste for which the 
owner or operator has either been issued a final permit under 40 CFR 
part 270 and complies with the requirements of 40 CFR part 266, subpart 
H, or has certified compliance with the interim status requirements of 
40 CFR part 266, subpart H;
    (v) Except for control devices used for small glycol dehydration 
units, a hazardous waste incinerator for which the owner or operator 
has been issued a final permit under 40 CFR part 270 and complies with 
the requirements of 40 CFR part 264, subpart O, or has certified 
compliance with the interim status requirements of 40 CFR part 265, 
subpart O.
* * * * *
    (2) An owner or operator shall design and operate each flare, as 
defined in Sec.  63.1271, in accordance with the requirements specified 
in Sec.  63.11(b) and the compliance determination shall be conducted 
using Method 22 of 40 CFR part 60, appendix A, to determine visible 
emissions.
    (3) For a performance test conducted to demonstrate that a control 
device meets the requirements of Sec.  63.1281(d)(1), (e)(3)(ii), or 
(f)(1) the owner or operator shall use the test methods and procedures 
specified in paragraphs (d)(3)(i) through (v) of this section. The 
initial and periodic performance tests shall be conducted according to 
the schedule specified in paragraph (d)(3)(vi) of this section.
    (i) * * *
    (B) To determine compliance with the enclosed combustion device 
total HAP concentration limit specified in Sec.  63.1281(d)(1)(i)(B), 
or the BTEX emission limit specified in Sec.  63.1275(b)(1)(iii), the 
sampling site

[[Page 49590]]

shall be located at the outlet of the combustion device.
* * * * *
    (iii) To determine compliance with the control device percent 
reduction performance requirement in Sec.  63.1281(d)(1)(i)(A), 
63.1281(d)(1)(ii), or 63.1281(e)(3)(ii), the owner or operator shall 
use either Method 18, 40 CFR part 60, appendix A, or Method 25A, 40 CFR 
part 60, appendix A; or ASTM D6420-99 (incorporated by reference as 
specified in Sec.  63.14), as specified in Sec.  63.772(a)(1)(ii); 
alternatively, any other method or data that have been validated 
according to the applicable procedures in Method 301 of appendix A of 
this part may be used. The following procedures shall be used to 
calculate the percentage of reduction:
* * * * *
    (iv) To determine compliance with the enclosed combustion device 
total HAP concentration limit specified in Sec.  63.1281(d)(1)(i)(B), 
the owner or operator shall use either Method 18, 40 CFR part 60, 
appendix A; or Method 25A, 40 CFR part 60, appendix A; or ASTM D6420-99 
(Reapproved 2004) (incorporated by reference as specified in Sec.  
63.14), as specified in Sec.  63.772(a)(1)(ii), to measure either TOC 
(minus methane and ethane) or total HAP. Alternatively, any other 
method or data that have been validated according to Method 301 of 
appendix A of this part, may be used. The following procedures shall be 
used to calculate parts per million by volume concentration, corrected 
to 3 percent oxygen:
* * * * *
    (C) * * *
    (1) The emission rate correction factor for excess air, integrated 
sampling and analysis procedures of Method 3A or 3B, 40 CFR part 60, 
appendix A, ASTM D6522-00 (Reapproved 2005), or ANSI/ASME PTC 19.10-
1981, Part 10 (manual portion only) (incorporated by reference as 
specified in Sec.  63.14) shall be used to determine the oxygen 
concentration (%O2d). The samples shall be taken during the 
same time that the samples are taken for determining TOC concentration 
or total HAP concentration.
* * * * *
    (v) To determine compliance with the BTEX emission limit specified 
in Sec.  63.1275(b)(1)(iii) the owner or operator shall use one of the 
following methods: Method 18, 40 CFR part 60, appendix A; ASTM D6420-99 
(Reapproved 2004) (incorporated by reference as specified in Sec.  
63.14), as specified in Sec.  63.772(a)(1)(ii); or any other method or 
data that have been validated according to the applicable procedures in 
Method 301, 40 CFR part 63, appendix A. The following procedures shall 
be used to calculate BTEX emissions:
    (A) The minimum sampling time for each run shall be 1 hour in which 
either an integrated sample or a minimum of four grab samples shall be 
taken. If grab sampling is used, then the samples shall be taken at 
approximately equal intervals in time, such as 15-minute intervals 
during the run.
    (B) The mass rate of BTEX (Eo) shall be computed using 
the equations and procedures specified in paragraphs (d)(3)(v)(B)(1) 
and (2) of this section.
    (1) The following equation shall be used:
    [GRAPHIC] [TIFF OMITTED] TR16AU12.014
    

Where:

Eo = Mass rate of BTEX at the outlet of the control 
device, dry basis, kilogram per hour.
Coj = Concentration of sample component j of the gas 
stream at the outlet of the control device, dry basis, parts per 
million by volume.
Moj = Molecular weight of sample component j of the gas 
stream at the outlet of the control device, gram/gram-mole.
Qo = Flowrate of gas stream at the outlet of the control 
device, dry standard cubic meter per minute.
K2 = Constant, 2.494 x 10-6 (parts per 
million) (gram-mole per standard cubic meter) (kilogram/gram) 
(minute/hour), where standard temperature (gram-mole per standard 
cubic meter) is 20 degrees C.
n = Number of components in sample.

    (2) When the BTEX mass rate is calculated, only BTEX compounds 
measured by Method 18, 40 CFR part 60, appendix A, or ASTM D6420-99 
(Reapproved 2004) (incorporated by reference as specified in Sec.  
63.14) as specified in Sec.  63.772(a)(1)(ii), shall be summed using 
the equations in paragraph (d)(3)(v)(B)(1) of this section.
    (vi) The owner or operator shall conduct performance tests 
according to the schedule specified in paragraphs (d)(3)(vi)(A) and (B) 
of this section.
    (A) An initial performance test shall be conducted within 180 days 
after the compliance date that is specified for each affected source in 
Sec.  63.1270(d)(3) and (4) except that the initial performance test 
for existing combustion control devices (i.e., control devices 
installed on or before August 23, 2011) at major sources shall be 
conducted no later than October 15, 2015. If the owner or operator of 
an existing combustion control device at a major source chooses to 
replace such device with a control device whose model is tested under 
Sec.  63.1282(g), then the newly installed device shall comply with all 
provisions of this subpart no later than October 15, 2015. The 
performance test results shall be submitted in the Notification of 
Compliance Status Report as required in Sec.  63.1285(d)(1)(ii).
    (B) Periodic performance tests shall be conducted for all control 
devices required to conduct initial performance tests except as 
specified in paragraphs (e)(3)(vi)(B)(1) and (2) of this section. The 
first periodic performance test shall be conducted no later than 60 
months after the initial performance test required in paragraph 
(d)(3)(vi)(A) of this section. Subsequent periodic performance tests 
shall be conducted at intervals no longer than 60 months following the 
previous periodic performance test or whenever a source desires to 
establish a new operating limit. The periodic performance test results 
must be submitted in the next Periodic Report as specified in Sec.  
63.1285(e)(2)(x). Combustion control devices meeting the criteria in 
either paragraph (e)(3)(vi)(B)(1) or (2) of this section are not 
required to conduct periodic performance tests.
    (1) A control device whose model is tested under, and meets the 
criteria of, Sec.  63.1282(g), or
    (2) A combustion control device demonstrating during the 
performance test under Sec.  63.1282(d) that combustion zone 
temperature is an indicator of destruction efficiency and operates at a 
minimum temperature of 760 degrees C.
    (4) For a condenser design analysis conducted to meet the 
requirements of Sec.  63.1281(d)(1), (e)(3)(ii), or (f)(1), the owner 
or operator shall meet the requirements specified in paragraphs 
(d)(4)(i) and (ii) of this section. Documentation of the design 
analysis shall be submitted as a part of the Notification of Compliance 
Status Report as required in Sec.  63.1285(d)(1)(i).
    (i) The condenser design analysis shall include an analysis of the 
vent stream composition, constituent concentrations, flowrate, relative 
humidity, and temperature, and shall establish the design outlet 
organic compound concentration level, design average temperature of the 
condenser exhaust vent stream, and the design average temperatures of 
the coolant fluid at the condenser inlet and outlet. As an alternative 
to the condenser design analysis, an owner or operator may elect to use 
the procedures specified in paragraph (d)(5) of this section.
* * * * *

[[Page 49591]]

    (5) As an alternative to the procedures in paragraph (d)(4)(i) of 
this section, an owner or operator may elect to use the procedures 
documented in the GRI report entitled, ``Atmospheric Rich/Lean Method 
for Determining Glycol Dehydrator Emissions,'' (GRI-95/0368.1) as 
inputs for the model GRI-GLYCalc\TM\, Version 3.0 or higher, to 
generate a condenser performance curve.
    (e) Compliance demonstration for control devices performance 
requirements. This paragraph applies to the demonstration of compliance 
with the control device performance requirements specified in Sec.  
63.1281(d)(1), (e)(3)(ii), and (f)(1). Compliance shall be demonstrated 
using the requirements in paragraphs (e)(1) through (3) of this 
section. As an alternative, an owner or operator that installs a 
condenser as the control device to achieve the requirements specified 
in Sec.  63.1281(d)(1)(ii), (e)(3)(ii), or (f)(1) may demonstrate 
compliance according to paragraph (f) of this section. An owner or 
operator may switch between compliance with paragraph (e) of this 
section and compliance with paragraph (f) of this section only after at 
least 1 year of operation in compliance with the selected approach. 
Notification of such a change in the compliance method shall be 
reported in the next Periodic Report, as required in Sec.  63.1285(e), 
following the change.
* * * * *
    (2) The owner or operator shall calculate the daily average of the 
applicable monitored parameter in accordance with Sec.  63.1283(d)(4) 
except that the inlet gas flowrate to the control device shall not be 
averaged.
    (3) Compliance is achieved when the daily average of the monitoring 
parameter value calculated under paragraph (e)(2) of this section is 
either equal to or greater than the minimum or equal to or less than 
the maximum monitoring value established under paragraph (e)(1) of this 
section. For inlet gas flowrate, compliance with the operating 
parameter limit is achieved when the value is equal to or less than the 
value established under Sec.  63.1282(g) or under the performance test 
conducted under Sec.  63.1282(d), as applicable.
    (4) Except for periods of monitoring system malfunctions, repairs 
associated with monitoring system malfunctions, and required monitoring 
system quality assurance or quality control activities (including, as 
applicable, system accuracy audits and required zero and span 
adjustments), the CMS required in Sec.  63.1283(d) must be operated at 
all times the affected source is operating. A monitoring system 
malfunction is any sudden, infrequent, not reasonably preventable 
failure of the monitoring system to provide valid data. Monitoring 
system failures that are caused in part by poor maintenance or careless 
operation are not malfunctions. Monitoring system repairs are required 
to be completed in response to monitoring system malfunctions and to 
return the monitoring system to operation as expeditiously as 
practicable.
    (5) Data recorded during monitoring system malfunctions, repairs 
associated with monitoring system malfunctions, or required monitoring 
system quality assurance or control activities may not be used in 
calculations used to report emissions or operating levels. All the data 
collected during all other required data collection periods must be 
used in assessing the operation of the control device and associated 
control system.
    (6) Except for periods of monitoring system malfunctions, repairs 
associated with monitoring system malfunctions, and required quality 
monitoring system quality assurance or quality control activities 
(including, as applicable, system accuracy audits and required zero and 
span adjustments), failure to collect required data is a deviation of 
the monitoring requirements.
    (f) Compliance demonstration with percent reduction or emission 
limit performance requirements--condensers. This paragraph applies to 
the demonstration of compliance with the performance requirements 
specified in Sec.  63.1281(d)(1)(ii), (e)(3) or (f)(1) for condensers. 
Compliance shall be demonstrated using the procedures in paragraphs 
(f)(1) through (f)(3) of this section.
    (1) The owner or operator shall establish a site-specific condenser 
performance curve according to the procedures specified in Sec.  
63.1283(d)(5)(ii). For sources required to meet the BTEX limit in 
accordance with Sec.  63.1281(e) or (f)(1) the owner or operator shall 
identify the minimum percent reduction necessary to meet the BTEX 
limit.
    (2) Compliance with the percent reduction requirement in Sec.  
63.1281(d)(1)(ii), (e)(3), or (f)(1) shall be demonstrated by the 
procedures in paragraphs (f)(2)(i) through (iii) of this section.
* * * * *
    (iii) Except as provided in paragraphs (f)(2)(iii)(A), (B), and (D) 
of this section, at the end of each operating day the owner or operator 
shall calculate the 30-day average HAP, or BTEX, emission reduction, as 
appropriate, from the condenser efficiencies as determined in paragraph 
(f)(2)(ii) of this section for the preceding 30 operating days. If the 
owner or operator uses a combination of process modifications and a 
condenser in accordance with the requirements of Sec.  63.1281(e), the 
30-day average HAP emission, or BTEX, emission reduction, shall be 
calculated using the emission reduction achieved through process 
modifications and the condenser efficiency as determined in paragraph 
(f)(2)(ii) of this section, both for the preceding 30 operating days.
    (A) After the compliance date specified in Sec.  63.1270(d), an 
owner or operator of a facility that stores natural gas that has less 
than 30 days of data for determining the average HAP, or BTEX, emission 
reduction, as appropriate, shall calculate the cumulative average at 
the end of the withdrawal season, each season, until 30 days of 
condenser operating data are accumulated. For a facility that does not 
store natural gas, the owner or operator that has less than 30 days of 
data for determining average HAP, or BTEX, emission reduction, as 
appropriate, shall calculate the cumulative average at the end of the 
calendar year, each year, until 30 days of condenser operating data are 
accumulated.
    (B) After the compliance date specified in Sec.  63.1270(d), for an 
owner or operator that has less than 30 days of data for determining 
the average HAP, or BTEX, emission reduction, as appropriate, 
compliance is achieved if the average HAP, or BTEX, emission reduction, 
as appropriate, calculated in paragraph (f)(2)(iii)(A) of this section 
is equal to or greater than 95.0 percent or is equal to or greater than 
the minimum percent reduction necessary to meet the BTEX emission limit 
as determined in paragraph (f)(1) of this section.
* * * * *
    (3) Compliance is achieved based on the applicable criteria in 
paragraphs (f)(3)(i) or (ii) of this section.
    (i) For sources meeting the HAP emission reduction specified in 
Sec.  63.1281(d)(1)(ii) or (e)(3) if the average HAP emission reduction 
calculated in paragraph (f)(2)(iii) of this section is equal to or 
greater than 95.0 percent.
    (ii) For sources required to meet the BTEX limit under Sec.  
63.1281(e)(3) or (f)(1), compliance is achieved if the average BTEX 
emission reduction calculated in paragraph (f)(2)(iii) of this section 
is equal to or greater than the minimum percent reduction identified in 
paragraph (f)(1) of this section.

[[Page 49592]]

    (g) Performance testing for combustion control devices--
manufacturers' performance test.
    (1) This paragraph (g) applies to the performance testing of a 
combustion control device conducted by the device manufacturer. The 
manufacturer shall demonstrate that a specific model of control device 
achieves the performance requirements in (g)(7) of this section by 
conducting a performance test as specified in paragraphs (g)(2) through 
(6) of this section.
    (2) Performance testing shall consist of three one-hour (or longer) 
test runs for each of the four following firing rate settings making a 
total of 12 test runs per test. Propene (propylene) gas shall be used 
for the testing fuel. All fuel analyses shall be performed by an 
independent third-party laboratory (not affiliated with the control 
device manufacturer or fuel supplier).
    (i) 90-100 percent of maximum design rate (fixed rate).
    (ii) 70-100-70 percent (ramp up, ramp down). Begin the test at 70 
percent of the maximum design rate. During the first 5 minutes, 
incrementally ramp the firing rate to 100 percent of the maximum design 
rate. Hold at 100 percent for 5 minutes. In the 10-15 minute time 
range, incrementally ramp back down to 70 percent of the maximum design 
rate. Repeat three more times for a total of 60 minutes of sampling.
    (iii) 30-70-30 percent (ramp up, ramp down). Begin the test at 30 
percent of the maximum design rate. During the first 5 minutes, 
incrementally ramp the firing rate to 70 percent of the maximum design 
rate. Hold at 70 percent for 5 minutes. In the 10-15 minute time range, 
incrementally ramp back down to 30 percent of the maximum design rate. 
Repeat three more times for a total of 60 minutes of sampling.
    (iv) 0-30-0 percent (ramp up, ramp down). Begin the test at 0 
percent of the maximum design rate. During the first 5 minutes, 
incrementally ramp the firing rate to 30 percent of the maximum design 
rate. Hold at 30 percent for 5 minutes. In the 10-15 minute time range, 
incrementally ramp back down to 0 percent of the maximum design rate. 
Repeat three more times for a total of 60 minutes of sampling.
    (3) All models employing multiple enclosures shall be tested 
simultaneously and with all burners operational. Results shall be 
reported for each enclosure individually and for the average of the 
emissions from all interconnected combustion enclosures/chambers. 
Control device operating data shall be collected continuously 
throughout the performance test using an electronic Data Acquisition 
System and strip chart. Data shall be submitted with the test report in 
accordance with paragraph (g)(8)(iii) of this section.
    (4) Inlet testing shall be conducted as specified in paragraphs 
(g)(4)(i) through (iii) of this section.
    (i) The inlet gas flow metering system shall be located in 
accordance with Method 2A, 40 CFR part 60, appendix A-1, (or other 
approved procedure) to measure inlet gas flowrate at the control device 
inlet location. The fitting for filling fuel sample containers shall be 
located a minimum of 8 pipe diameters upstream of any inlet gas flow 
monitoring meter.
    (ii) Inlet gas flowrate shall be determined using Method 2A, 40 CFR 
part 60, appendix A-1. Record the start and stop reading for each 60-
minute THC test. Record the inlet gas pressure and temperature at 5-
minute intervals throughout each 60-minute THC test.
    (iii) Inlet gas sampling shall be conducted in accordance with the 
criteria in paragraphs (g)(4)(iii)(A) and (B) of this section.
    (A) At the inlet gas sampling location, securely connect a 
Silonite-coated stainless steel evacuated canister fitted with a flow 
controller sufficient to fill the canister over a 3 hour period. 
Filling shall be conducted as specified in the following:
    (1) Open the canister sampling valve at the beginning of the total 
hydrocarbon (THC) test, and close the canister at the end of each THC 
test run.
    (2) Fill one canister across the three test runs for each THC test 
such that one composite fuel sample exists for each test condition.
    (3) Label the canisters individually and record on a chain of 
custody form.
    (B) Each inlet gas sample shall be analyzed using the following 
methods. The results shall be included in the test report.
    (1) Hydrocarbon compounds containing between one and five atoms of 
carbon plus benzene using ASTM D1945-03 (Reapproved 2010) (incorporated 
by reference as specified in Sec.  63.14).
    (2) Hydrogen (H2), carbon monoxide (CO), carbon dioxide 
(CO2), nitrogen (N2), oxygen (O2) 
using ASTM D1945-03 (Reapproved 2010) (incorporated by reference as 
specified in Sec.  63.14).
    (3) Higher heating value using ASTM D3588-98 (Reapproved 2003) or 
ASTM D4891-89 (Reapproved 2006) (incorporated by reference as specified 
in Sec.  63.14).
    (5) Outlet testing shall be conducted in accordance with the 
criteria in paragraphs (g)(5)(i) through (v) of this section.
    (i) Sampling and flowrate measured in accordance with the 
following:
    (A) The outlet sampling location shall be a minimum of 4 equivalent 
stack diameters downstream from the highest peak flame or any other 
flow disturbance, and a minimum of one equivalent stack diameter 
upstream of the exit or any other flow disturbance. A minimum of two 
sample ports shall be used.
    (B) Flowrate shall be measured using Method 1, 40 CFR part 60, 
Appendix 1, for determining flow measurement traverse point location; 
and Method 2, 40 CFR part 60, Appendix 1, shall be used to measure duct 
velocity. If low flow conditions are encountered (i.e., velocity 
pressure differentials less than 0.05 inches of water) during the 
performance test, a more sensitive manometer or other pressure 
measurement device shall be used to obtain an accurate flow profile.
    (ii) Molecular weight shall be determined as specified in 
paragraphs (g)(4)(iii)(B), and (g)(5)(ii)(A) and (B) of this section.
    (A) An integrated bag sample shall be collected during the Method 
4, 40 CFR part 60, Appendix A, moisture test. Analyze the bag sample 
using a gas chromatograph-thermal conductivity detector (GC-TCD) 
analysis meeting the following criteria:
    (1) Collect the integrated sample throughout the entire test, and 
collect representative volumes from each traverse location.
    (2) The sampling line shall be purged with stack gas before opening 
the valve and beginning to fill the bag.
    (3) The bag contents shall be vigorously mixed prior to the GC 
analysis.
    (4) The GC-TCD calibration procedure in Method 3C, 40 CFR part 60, 
Appendix A, shall be modified by using EPAAlt-045 as follows: For the 
initial calibration, triplicate injections of any single concentration 
must agree within 5 percent of their mean to be valid. The calibration 
response factor for a single concentration re-check must be within 10 
percent of the original calibration response factor for that 
concentration. If this criterion is not met, the initial calibration 
using at least three concentration levels shall be repeated.
    (B) Report the molecular weight of: O2, CO2, 
methane (CH4), and N2 and include in the test report 
submitted under Sec.  63.775(d)(iii). Moisture shall be determined 
using Method 4, 40 CFR part 60, Appendix A. Traverse both ports with 
the Method 4, 40 CFR part 60, Appendix A, sampling train during each 
test run. Ambient air shall not be

[[Page 49593]]

introduced into the Method 3C, 40 CFR part 60, Appendix A, integrated 
bag sample during the port change.
    (iii) Carbon monoxide shall be determined using Method 10, 40 CFR 
part 60, Appendix A or ASTM D6522-00 (Reapproved 2005) (incorporated by 
reference as specified in Sec.  63.14). The test shall be run at the 
same time and with the sample points used for the EPA Method 25A, 40 
CFR part 60, Appendix A, testing. An instrument range of 0-10 per 
million by volume-dry (ppmvd) shall be used.
    (iv) Visible emissions shall be determined using Method 22, 40 CFR 
part 60, Appendix A. The test shall be performed continuously during 
each test run. A digital color photograph of the exhaust point, taken 
from the position of the observer and annotated with date and time, 
will be taken once per test run and the four photos included in the 
test report.
    (v) Excess air shall be determined using resultant data from the 
EPA Method 3C tests and EPA Method 3B, 40 CFR part 60, Appendix A, 
equation 3B-1 or ANSI/ASME PTC 19.10-1981, Part 10 (manual portion 
only) (incorporated by reference as specified in Sec.  63.14).
    (6) Total hydrocarbons (THC) shall be determined as specified by 
the following criteria:
    (i) Conduct THC sampling using Method 25A, 40 CFR part 60, Appendix 
A, except the option for locating the probe in the center 10 percent of 
the stack shall not be allowed. The THC probe must be traversed to 16.7 
percent, 50 percent, and 83.3 percent of the stack diameter during the 
test run.
    (ii) A valid test shall consist of three Method 25A, 40 CFR part 
60, Appendix A, tests, each no less than 60 minutes in duration.
    (iii) A 0-10 parts per million by volume-wet (ppmvw) (as propane) 
measurement range is preferred; as an alternative a 0-30 ppmvw (as 
carbon) measurement range may be used.
    (iv) Calibration gases will be propane in air and be certified 
through EPA Protocol 1--``EPA Traceability Protocol for Assay and 
Certification of Gaseous Calibration Standards,'' September 1997, as 
amended August 25, 1999, EPA-600/R-97/121 (or more recent if updated 
since 1999).
    (v) THC measurements shall be reported in terms of ppmvw as 
propane.
    (vi) THC results shall be corrected to 3 percent CO2, as 
measured by Method 3C, 40 CFR part 60, Appendix A.
    (vii) Subtraction of methane/ethane from the THC data is not 
allowed in determining results.
    (7) Performance test criteria:
    (i) The control device model tested must meet the criteria in 
paragraphs (g)(7)(i)(A) through (C) of this section:
    (A) Method 22, 40 CFR part 60, Appendix A, results under paragraph 
(g)(5)(v) of this section with no indication of visible emissions, and
    (B) Average Method 25A, 40 CFR part 60, Appendix A, results under 
paragraph (g)(6) of this section equal to or less than 10.0 ppmvw THC 
as propane corrected to 3.0 percent CO2, and
    (C) Average CO emissions determined under paragraph (g)(5)(iv) of 
this section equal to or less than 10 parts ppmvd, corrected to 3.0 
percent CO2.
    (D) Excess combustion air shall be equal to or greater than 150 
percent.
    (ii) The manufacturer shall determine a maximum inlet gas flowrate 
which shall not be exceeded for each control device model to achieve 
the criteria in paragraph (g)(7)(i) of this section.
    (iii) A control device meeting the criteria in paragraph 
(g)(7)(i)(A) through (C) of this section will have demonstrated a 
destruction efficiency of 95.0 percent for HAP regulated under this 
subpart.
    (8) The owner or operator of a combustion control device model 
tested under this section shall submit the information listed in 
paragraphs (g)(8)(i) through (iii) in the test report required under 
Sec.  63.775(d)(1)(iii).
    (i) Full schematic of the control device and dimensions of the 
device components.
    (ii) Design net heating value (minimum and maximum) of the device.
    (iii) Test fuel gas flow range (in both mass and volume). Include 
the minimum and maximum allowable inlet gas flowrate.
    (iv) Air/stream injection/assist ranges, if used.
    (v) The test parameter ranges listed in paragraphs (g)(8)(v)(A) 
through (O) of this section, as applicable for the tested model.
    (A) Fuel gas delivery pressure and temperature.
    (B) Fuel gas moisture range.
    (C) Purge gas usage range.
    (D) Condensate (liquid fuel) separation range.
    (E) Combustion zone temperature range. This is required for all 
devices that measure this parameter.
    (F) Excess combustion air range.
    (G) Flame arrestor(s).
    (H) Burner manifold pressure.
    (I) Pilot flame sensor.
    (J) Pilot flame design fuel and fuel usage.
    (K) Tip velocity range.
    (L) Momentum flux ratio.
    (M) Exit temperature range.
    (N) Exit flowrate.
    (O) Wind velocity and direction.
    (vi) The test report shall include all calibration quality 
assurance/quality control data, calibration gas values, gas cylinder 
certification, and strip charts annotated with test times and 
calibration values.
    (h) Compliance demonstration for combustion control devices--
manufacturers' performance test. This paragraph applies to the 
demonstration of compliance for a combustion control device tested 
under the provisions in paragraph (g) of this section. Owners or 
operators shall demonstrate that a control device achieves the 
performance requirements of Sec.  63.1281(d)(1), (e)(3)(ii) or (f)(1), 
by installing a device tested under paragraph (g) of this section and 
complying with the following criteria:
    (1) The inlet gas flowrate shall meet the range specified by the 
manufacturer. Flowrate shall be calculated as specified in Sec.  
63.1283(d)(3)(i)(H)(1).
    (2) A pilot flame shall be present at all times of operation. The 
pilot flame shall be monitored in accordance with Sec.  
63.1283(d)(3)(i)(H)(2).
    (3) Devices shall be operated with no visible emissions, except for 
periods not to exceed a total of 2 minutes during any hour. A visible 
emissions test using Method 22, 40 CFR part 60, Appendix A, shall be 
performed each calendar quarter. The observation period shall be 1 hour 
and shall be conducted according to EPA Method 22, 40 CFR part 60, 
Appendix A.
    (4) Compliance with the operating parameter limit is achieved when 
the following criteria are met:
    (i) The inlet gas flowrate monitored under paragraph (h)(1) of this 
section is equal to or below the maximum established by the 
manufacturer; and
    (ii) The pilot flame is present at all times; and
    (iii) During the visible emissions test performed under paragraph 
(h)(3) of this section the duration of visible emissions does not 
exceed a total of 2 minutes during the observation period. Devices 
failing the visible emissions test shall follow manufacturers repair 
instructions, if available, or best combustion engineering practice as 
outlined in the unit inspection and maintenance plan, to return the 
unit to compliant operation. All repairs and maintenance activities for 
each unit shall be recorded in a maintenance and repair log and shall 
be available on site for inspection.
    (iv) Following return to operation from maintenance or repair 
activity, each device must pass a Method 22 visual observation as 
described in paragraph (h)(3) of this section.

[[Page 49594]]


0
30. Section 63.1283 is amended by:
0
a. Adding paragraph (b);
0
b. Revising paragraph (d)(1) introductory text;
0
c. Revising paragraph (d)(1)(ii) and adding paragraphs (d)(1)(iii) and 
(iv);
0
d. Revising paragraph (d)(2);
0
e. Revising paragraph (d)(3)(i)(A);
0
f. Revising paragraph (d)(3)(i)(D);
0
g. Revising paragraph (d)(3)(i)(G);
0
h. Adding paragraph (d)(3)(i)(H);
0
i. Revising paragraph (d)(4);
0
j. Revising paragraph (d)(5)(i);
0
k. Revising paragraphs (d)(5)(ii)(A) through (C);
0
l. Revising paragraph (d)(6) introductory text;
0
m. Revising paragraph (d)(6)(ii);
0
n. Adding paragraph (d)(6)(v);
0
o. Revising paragraph (d)(7); and
0
p. Removing and reserving paragraph (d)(8).
    The additions and revisions read as follows:


Sec.  63.1283  Inspection and monitoring requirements.

* * * * *
    (b) The owner or operator of a control device whose model was 
tested under 63.1282(g) shall develop an inspection and maintenance 
plan for each control device. At a minimum, the plan shall contain the 
control device manufacturer's recommendations for ensuring proper 
operation of the device. Semi-annual inspections shall be conducted for 
each control device with maintenance and replacement of control device 
components made in accordance with the plan.
* * * * *
    (d) Control device monitoring requirements. (1) For each control 
device except as provided for in paragraph (d)(2) of this section, the 
owner or operator shall install and operate a continuous parameter 
monitoring system in accordance with the requirements of paragraphs 
(d)(3) through (7) of this section. Owners or operators that install 
and operate a flare in accordance with Sec.  63.1281(d)(1)(iii) or 
(f)(1)(iii) are exempt from the requirements of paragraphs (d)(4) and 
(5) of this section. The continuous monitoring system shall be designed 
and operated so that a determination can be made on whether the control 
device is achieving the applicable performance requirements of Sec.  
63.1281(d), (e)(3), or (f)(1). Each continuous parameter monitoring 
system shall meet the following specifications and requirements:
* * * * *
    (ii) A site-specific monitoring plan must be prepared that 
addresses the monitoring system design, data collection, and the 
quality assurance and quality control elements outlined in paragraph 
(d) of this section and in Sec.  63.8(d). Each CPMS must be installed, 
calibrated, operated, and maintained in accordance with the procedures 
in your approved site-specific monitoring plan. Using the process 
described in Sec.  63.8(f)(4), you may request approval of monitoring 
system quality assurance and quality control procedures alternative to 
those specified in paragraphs (d)(1)(ii)(A) through (E) of this section 
in your site-specific monitoring plan.
    (A) The performance criteria and design specifications for the 
monitoring system equipment, including the sample interface, detector 
signal analyzer, and data acquisition and calculations;
    (B) Sampling interface (e.g., thermocouple) location such that the 
monitoring system will provide representative measurements;
    (C) Equipment performance checks, system accuracy audits, or other 
audit procedures;
    (D) Ongoing operation and maintenance procedures in accordance with 
provisions in Sec.  63.8(c)(1) and (c)(3); and
    (E) Ongoing reporting and recordkeeping procedures in accordance 
with provisions in Sec.  63.10(c), (e)(1), and (e)(2)(i).
    (iii) The owner or operator must conduct the CPMS equipment 
performance checks, system accuracy audits, or other audit procedures 
specified in the site-specific monitoring plan at least once every 12 
months.
    (iv) The owner or operator must conduct a performance evaluation of 
each CPMS in accordance with the site-specific monitoring plan.
    (2) An owner or operator is exempted from the monitoring 
requirements specified in paragraphs (d)(3) through (7) of this section 
for the following types of control devices:
    (i) Except for control devices for small glycol dehydration units, 
a boiler or process heater in which all vent streams are introduced 
with the primary fuel or are used as the primary fuel;
    (ii) Except for control devices for small glycol dehydration units, 
a boiler or process heater with a design heat input capacity equal to 
or greater than 44 megawatts.
    (3) * * *
    (i) * * *
    (A) For a thermal vapor incinerator that demonstrates during the 
performance test conducted under Sec.  63.1282(d) that combustion zone 
temperature is an accurate indicator of performance, a temperature 
monitoring device equipped with a continuous recorder. The monitoring 
device shall have a minimum accuracy of 2 percent of the 
temperature being monitored in [deg]C, or 2.5 [deg]C, 
whichever value is greater. The temperature sensor shall be installed 
at a location representative of the combustion zone temperature.
* * * * *
    (D) For a boiler or process heater, a temperature monitoring device 
equipped with a continuous recorder. The temperature monitoring device 
shall have a minimum accuracy of 2 percent of the 
temperature being monitored in [deg]C, or 2.5 [deg]C, 
whichever value is greater. The temperature sensor shall be installed 
at a location representative of the combustion zone temperature.
* * * * *
    (G) For a nonregenerative-type carbon adsorption system, the owner 
or operator shall monitor the design carbon replacement interval 
established using a performance test performed in accordance with Sec.  
63.1282(d)(3) and shall be based on the total carbon working capacity 
of the control device and source operating schedule.
    (H) For a control device whose model is tested under Sec.  
63.1282(g):
    (1) The owner or operator shall determine actual average inlet 
waste gas flowrate using the model GRI-GLYCalc\TM\, Version 3.0 or 
higher, ProMax, or AspenTech HYSYS. Inputs to the models shall be 
representative of actual operating conditions of the controlled unit. 
The determination shall be performed to coincide with the visible 
emissions test under Sec.  63.1282(h)(3);
    (2) A heat sensing monitoring device equipped with a continuous 
recorder that indicates the continuous ignition of the pilot flame.
* * * * *
    (4) Using the data recorded by the monitoring system, except for 
inlet gas flowrate, the owner or operator must calculate the daily 
average value for each monitored operating parameter for each operating 
day. If the emissions unit operation is continuous, the operating day 
is a 24-hour period. If the emissions unit operation is not continuous, 
the operating day is the total number of hours of control device 
operation per 24-hour period. Valid data points must be available for 
75 percent of the operating hours in an operating day to compute the 
daily average.
    (5) * * *
    (i) The owner or operator shall establish a minimum operating 
parameter value or a maximum operating parameter value, as appropriate 
for the control device, to

[[Page 49595]]

define the conditions at which the control device must be operated to 
continuously achieve the applicable performance requirements of Sec.  
63.1281(d)(1), (e)(3)(ii), or (f)(1). Each minimum or maximum operating 
parameter value shall be established as follows:
    (A) If the owner or operator conducts performance tests in 
accordance with the requirements of Sec.  63.1282(d)(3) to demonstrate 
that the control device achieves the applicable performance 
requirements specified in Sec.  63.1281(d)(1), (e)(3)(ii), or (f)(1), 
then the minimum operating parameter value or the maximum operating 
parameter value shall be established based on values measured during 
the performance test and supplemented, as necessary, by a condenser 
design analysis or control device manufacturer's recommendations or a 
combination of both.
    (B) If the owner or operator uses a condenser design analysis in 
accordance with the requirements of Sec.  63.1282(d)(4) to demonstrate 
that the control device achieves the applicable performance 
requirements specified in Sec.  63.1281(d)(1), (e)(3)(ii), or (f)(1), 
then the minimum operating parameter value or the maximum operating 
parameter value shall be established based on the condenser design 
analysis and may be supplemented by the condenser manufacturer's 
recommendations.
    (C) If the owner or operator operates a control device where the 
performance test requirement was met under Sec.  63.1282(g) to 
demonstrate that the control device achieves the applicable performance 
requirements specified in Sec.  63.1281(d)(1), (e)(3)(ii) or (f)(1), 
then the maximum inlet gas flowrate shall be established based on the 
performance test and supplemented, as necessary, by the manufacturer 
recommendations.
    (ii) * * *
    (A) If the owner or operator conducts a performance test in 
accordance with the requirements of Sec.  63.1282(d)(3) to demonstrate 
that the condenser achieves the applicable performance requirements in 
Sec.  63.1281(d)(1), (e)(3)(ii), or (f)(1), then the condenser 
performance curve shall be based on values measured during the 
performance test and supplemented as necessary by control device design 
analysis, or control device manufacturer's recommendations, or a 
combination or both.
    (B) If the owner or operator uses a control device design analysis 
in accordance with the requirements of Sec.  63.1282(d)(4)(i) to 
demonstrate that the condenser achieves the applicable performance 
requirements specified in Sec.  63.1281(d)(1), (e)(3)(ii), or (f)(1), 
then the condenser performance curve shall be based on the condenser 
design analysis and may be supplemented by the control device 
manufacturer's recommendations.
    (C) As an alternative to paragraph (d)(5)(ii)(B) of this section, 
the owner or operator may elect to use the procedures documented in the 
GRI report entitled, ``Atmospheric Rich/Lean Method for Determining 
Glycol Dehydrator Emissions'' (GRI-95/0368.1) as inputs for the model 
GRI-GLYCalc\TM\, Version 3.0 or higher, to generate a condenser 
performance curve.
    (6) An excursion for a given control device is determined to have 
occurred when the monitoring data or lack of monitoring data result in 
any one of the criteria specified in paragraphs (d)(6)(i) through 
(d)(6)(v) of this section being met. When multiple operating parameters 
are monitored for the same control device and during the same operating 
day, and more than one of these operating parameters meets an excursion 
criterion specified in paragraphs (d)(6)(i) through (d)(6)(v) of this 
section, then a single excursion is determined to have occurred for the 
control device for that operating day.
* * * * *
    (ii) For sources meeting Sec.  63.1281(d)(1)(ii), an excursion 
occurs when average condenser efficiency calculated according to the 
requirements specified in Sec.  63.1282(f)(2)(iii) is less than 95.0 
percent, as specified in Sec.  63.1282(f)(3). For sources meeting Sec.  
63.1281(f)(1), an excursion occurs when the 30-day average condenser 
efficiency calculated according to the requirements of Sec.  
63.1282(f)(2)(iii) is less than the identified 30-day required percent 
reduction.
* * * * *
    (v) For control device whose model is tested under Sec.  63.1282(g) 
an excursion occurs when:
    (A) The inlet gas flowrate exceeds the maximum established during 
the test conducted under Sec.  63.1282(g).
    (B) Failure of the quarterly visible emissions test conducted under 
Sec.  63.1282(h)(3) occurs.
    (7) For each excursion, the owner or operator shall be deemed to 
have failed to have applied control in a manner that achieves the 
required operating parameter limits. Failure to achieve the required 
operating parameter limits is a violation of this standard.
    (8) [Reserved]
* * * * *

0
31. Section 63.1284 is amended by:
0
a. Revising paragraph (b)(3) introductory text;
0
b. Removing and reserving paragraph (b)(3)(ii);
0
c. Revising paragraph (b)(4)(ii);
0
d. Revising paragraph (b)(4)(iii);
0
e. Adding paragraph (b)(7)(ix); and
0
f. Adding paragraphs (f), (g) and (h).
    The revisions and additions read as follows:


Sec.  63.1284  Recordkeeping requirements.

* * * * *
    (b) * * *
    (3) Records specified in Sec.  63.10(c) for each monitoring system 
operated by the owner or operator in accordance with the requirements 
of Sec.  63.1283(d). Notwithstanding the previous sentence, monitoring 
data recorded during periods identified in paragraphs (b)(3)(i) through 
(iv) of this section shall not be included in any average or percent 
leak rate computed under this subpart. Records shall be kept of the 
times and durations of all such periods and any other periods during 
process or control device operation when monitors are not operating or 
failed to collect required data.
* * * * *
    (ii) [Reserved]
* * * * *
    (4) * * *
    (ii) Records of the daily average value of each continuously 
monitored parameter for each operating day determined according to the 
procedures specified in Sec.  63.1283(d)(4) of this subpart, except as 
specified in paragraphs (b)(4)(ii)(A) through (C) of this section.
    (A) For flares, the records required in paragraph (e) of this 
section.
    (B) For condensers installed to comply with Sec.  63.1275, records 
of the annual 30-day rolling average condenser efficiency determined 
under Sec.  63.1282(f) shall be kept in addition to the daily averages.
    (C) For a control device whose model is tested under Sec.  
63.1282(g), the records required in paragraph (g) of this section.
    (iii) Hourly records of the times and durations of all periods when 
the vent stream is diverted from the control device or the device is 
not operating.
* * * * *
    (7) * * *
    (ix) Records identifying the carbon replacement schedule under 
Sec.  63.1281(d)(5) and records of each carbon replacement.
* * * * *
    (f) The owner or operator of an affected source subject to this 
subpart shall maintain records of the occurrence and duration of each 
malfunction of

[[Page 49596]]

operation (i.e., process equipment) or the air pollution control 
equipment and monitoring equipment. The owner or operator shall 
maintain records of actions taken during periods of malfunction to 
minimize emissions in accordance with Sec.  63.1274(h), including 
corrective actions to restore malfunctioning process and air pollution 
control and monitoring equipment to its normal or usual manner of 
operation.
    (g) Record the following when using a control device whose model is 
tested under Sec.  63.1282(g) to comply with Sec.  63.1281(d), 
(e)(3)(ii) and (f)(1):
    (1) All visible emission readings and flowrate calculations made 
during the compliance determination required by Sec.  63.1282(h); and
    (2) All hourly records and other recorded periods when the pilot 
flame is absent.
    (h) The date the semi-annual maintenance inspection required under 
Sec.  63.1283(b) is performed. Include a list of any modifications or 
repairs made to the control device during the inspection and other 
maintenance performed such as cleaning of the fuel nozzles.

0
32. Section 63.1285 is amended by:
0
a. Revising paragraph (b)(1);
0
b. Revising paragraph (b)(6);
0
c. Removing paragraph (b)(7);
0
d. Revising paragraph (d) introductory text;
0
e. Revising paragraph (d)(1) introductory text;
0
f. Revising paragraph (d)(1)(i);
0
g. Revising paragraph (d)(1)(ii) introductory text;
0
h. Revising paragraph (d)(2) introductory text;
0
i. Revising paragraph (d)(4) introductory text;
0
j. Revising paragraph (d)(4)(ii);
0
k. Adding paragraph (d)(4)(iv);
0
l. Revising paragraph (d)(10);
0
m. Adding paragraphs (d)(11) and (d)(12);
0
n. Revising paragraph (e)(2) introductory text;
0
o. Revising paragraph (e)(2)(ii)(B);
0
p. Adding paragraphs (e)(2)(ii)(D) and (E);
0
q. Adding paragraphs (e)(2)(x) through (xiii); and
0
r. Adding paragraph (g).

The revisions and additions read as follows:


Sec.  63.1285  Reporting requirements.

* * * * *
    (b) * * *
    (1) The initial notifications required for existing affected 
sources under Sec.  63.9(b)(2) shall be submitted as provided in 
paragraphs (b)(1)(i) and (ii) of this section.
    (i) Except as otherwise provided in paragraph (b)(1)(ii) of this 
section, the initial notification shall be submitted by 1 year after an 
affected source becomes subject to the provisions of this subpart or by 
June 17, 2000, whichever is later. Affected sources that are major 
sources on or before June 17, 2000 and plan to be area sources by June 
17, 2002 shall include in this notification a brief, nonbinding 
description of a schedule for the action(s) that are planned to achieve 
area source status.
    (ii) An affected source identified under Sec.  63.1270(d)(3) shall 
submit an initial notification required for existing affected sources 
under Sec.  63.9(b)(2) within 1 year after the affected source becomes 
subject to the provisions of this subpart or by October 15, 2013, 
whichever is later. An affected source identified under Sec.  
63.1270(d)(3) that plans to be an area source by October 15, 2015, 
shall include in this notification a brief, nonbinding description of a 
schedule for the action(s) that are planned to achieve area source 
status.
* * * * *
    (6) If there was a malfunction during the reporting period, the 
Periodic Report specified in paragraph (e) of this section shall 
include the number, duration, and a brief description for each type of 
malfunction which occurred during the reporting period and which caused 
or may have caused any applicable emission limitation to be exceeded. 
The report must also include a description of actions taken by an owner 
or operator during a malfunction of an affected source to minimize 
emissions in accordance with Sec.  63.1274(h), including actions taken 
to correct a malfunction.
* * * * *
    (d) Each owner or operator of a source subject to this subpart 
shall submit a Notification of Compliance Status Report as required 
under Sec.  63.9(h) within 180 days after the compliance date specified 
in Sec.  63.1270(d). In addition to the information required under 
Sec.  63.9(h), the Notification of Compliance Status Report shall 
include the information specified in paragraphs (d)(1) through (12) of 
this section. This information may be submitted in an operating permit 
application, in an amendment to an operating permit application, in a 
separate submittal, or in any combination of the three. If all of the 
information required under this paragraph have been submitted at any 
time prior to 180 days after the applicable compliance dates specified 
in Sec.  63.1270(d), a separate Notification of Compliance Status 
Report is not required. If an owner or operator submits the information 
specified in paragraphs (d)(1) through (12) of this section at 
different times, and/or different submittals, subsequent submittals may 
refer to previous submittals instead of duplicating and resubmitting 
the previously submitted information.
    (1) If a closed-vent system and a control device other than a flare 
are used to comply with Sec.  63.1274, the owner or operator shall 
submit the information in paragraph (d)(1)(iii) of this section and the 
information in either paragraph (d)(1)(i) or (ii) of this section.
    (i) The condenser design analysis documentation specified in Sec.  
63.1282(d)(4) of this subpart if the owner or operator elects to 
prepare a design analysis; or
    (ii) If the owner or operator is required to conduct a performance 
test, the performance test results including the information specified 
in paragraphs (d)(1)(ii)(A) and (B) of this section. Results of a 
performance test conducted prior to the compliance date of this subpart 
can be used provided that the test was conducted using the methods 
specified in Sec.  63.1282(d)(3), and that the test conditions are 
representative of current operating conditions. If the owner or 
operator operates a combustion control device model tested under Sec.  
63.1282(g), an electronic copy of the performance test results shall be 
submitted via email to Oil_and_Gas_PT@EPA.GOV unless the test 
results for that model of combustion control device are posted at the 
following Web site: epa.gov/airquality/oilandgas/.
* * * * *
    (2) If a closed-vent system and a flare are used to comply with 
Sec.  63.1274, the owner or operator shall submit performance test 
results including the information in paragraphs (d)(2)(i) and (ii) of 
this section. The owner or operator shall also submit the information 
in paragraph (d)(2)(iii) of this section.
* * * * *
    (4) For each control device other than a flare used to meet the 
requirements of Sec.  63.1274, the owner or operator shall submit the 
information specified in paragraphs (d)(4)(i) through (iv) of this 
section for each operating parameter required to be monitored in 
accordance with the requirements of Sec.  63.1283(d).
* * * * *
    (ii) An explanation of the rationale for why the owner or operator 
selected each of the operating parameter values established in Sec.  
63.1283(d)(5) of this subpart. This explanation shall include

[[Page 49597]]

any data and calculations used to develop the value, and a description 
of why the chosen value indicates that the control device is operating 
in accordance with the applicable requirements of Sec.  63.1281(d)(1), 
(e)(3)(ii), or (f)(1).
* * * * *
    (iv) For each carbon adsorber, the predetermined carbon replacement 
schedule as required in Sec.  63.1281(d)(5)(i).
* * * * *
    (10) The owner or operator shall submit the analysis prepared under 
Sec.  63.1281(e)(2) to demonstrate that the conditions by which the 
facility will be operated to achieve the HAP emission reduction of 95.0 
percent, or the BTEX limit in Sec.  63.1275(b)(1)(iii) through process 
modifications or a combination of process modifications and one or more 
control devices.
    (11) If the owner or operator installs a combustion control device 
model tested under the procedures in Sec.  63.1282(g), the data listed 
under Sec.  63.1282(g)(8).
    (12) For each combustion control device model tested under Sec.  
63.1282(g), the information listed in paragraphs (d)(12)(i) through 
(vi) of this section.
    (i) Name, address and telephone number of the control device 
manufacturer.
    (ii) Control device model number.
    (iii) Control device serial number.
    (iv) Date the model of control device was tested by the 
manufacturer.
    (v) Manufacturer's HAP destruction efficiency rating.
    (vi) Control device operating parameters, maximum allowable inlet 
gas flowrate.
* * * * *
    (e) * * *
    (2) The owner or operator shall include the information specified 
in paragraphs (e)(2)(i) through (xiii) of this section, as applicable.
* * * * *
    (ii) * * *
    (B) For each excursion caused when the 30-day average condenser 
control efficiency is less than the value, as specified in Sec.  
63.1283(d)(6)(ii), the report must include the 30-day average values of 
the condenser control efficiency, and the date and duration of the 
period that the excursion occurred.
* * * * *
    (D) For each excursion caused when the maximum inlet gas flowrate 
identified under Sec.  63.1282(g) is exceeded, the report must include 
the values of the inlet gas identified and the date and duration of the 
period that the excursion occurred.
    (E) For each excursion caused when visible emissions determined 
under Sec.  63.1282(h) exceed the maximum allowable duration, the 
report must include the date and duration of the period that the 
excursion occurred, repairs affected to the unit, and date the unit was 
returned to service.
* * * * *
    (x) The results of any periodic test as required in Sec.  
63.1282(d)(3) conducted during the reporting period.
    (xi) For each carbon adsorber used to meet the control device 
requirements of Sec.  63.1281(d)(1), records of each carbon replacement 
that occurred during the reporting period.
    (xii) For combustion control device inspections conducted in 
accordance with Sec.  63.1283(b) the records specified in Sec.  
63.1284(h).
    (xiii) Certification by a responsible official of truth, accuracy, 
and completeness. This certification shall state that, based on 
information and belief formed after reasonable inquiry, the statements 
and information in the document are true, accurate, and complete.
* * * * *
    (g) Electronic reporting. (1) Within 60 days after the date of 
completing each performance test (defined in Sec.  63.2) as required by 
this subpart you must submit the results of the performance tests 
required by this subpart to EPA's WebFIRE database by using the 
Compliance and Emissions Data Reporting Interface (CEDRI) that is 
accessed through EPA's Central Data Exchange (CDX)(www.epa.gov/cdx). 
Performance test data must be submitted in the file format generated 
through use of EPA's Electronic Reporting Tool (ERT) (see http://www.epa.gov/ttn/chief/ert/index.html). Only data collected using test 
methods on the ERT Web site are subject to this requirement for 
submitting reports electronically to WebFIRE. Owners or operators who 
claim that some of the information being submitted for performance 
tests is confidential business information (CBI) must submit a complete 
ERT file including information claimed to be CBI on a compact disk or 
other commonly used electronic storage media (including, but not 
limited to, flash drives) to EPA. The electronic media must be clearly 
marked as CBI and mailed to U.S. EPA/OAPQS/CORE CBI Office, Attention: 
WebFIRE Administrator, MD C404-02, 4930 Old Page Rd., Durham, NC 27703. 
The same ERT file with the CBI omitted must be submitted to EPA via CDX 
as described earlier in this paragraph. At the discretion of the 
delegated authority, you must also submit these reports, including the 
confidential business information, to the delegated authority in the 
format specified by the delegated authority.
    (2) All reports required by this subpart not subject to the 
requirements in paragraph (g)(1) of this section must be sent to the 
Administrator at the appropriate address listed in Sec.  63.13. The 
Administrator or the delegated authority may request a report in any 
form suitable for the specific case (e.g., by commonly used electronic 
media such as Excel spreadsheet, on CD or hard copy). The Administrator 
retains the right to require submittal of reports subject to paragraph 
(g)(1) of this section in paper format.


0
33. Section 63.1287 is amended by revising paragraph (a) to read as 
follows:


Sec.  63.1287  Alternative means of emission limitation.

    (a) If, in the judgment of the Administrator, an alternative means 
of emission limitation will achieve a reduction in HAP emissions at 
least equivalent to the reduction in HAP emissions from that source 
achieved under the applicable requirements in Sec. Sec.  63.1274 
through 63.1281, the Administrator will publish a notice in the Federal 
Register permitting the use of the alternative means for purposes of 
compliance with that requirement. The notice may condition the 
permission on requirements related to the operation and maintenance of 
the alternative means.
* * * * *


0
34. Appendix to Subpart HHH of Part 63--Table is amended by revising 
Table 2 to read as follows:

Appendix to Subpart HHH of Part 63--Tables

* * * * *

[[Page 49598]]



   Table 2 to Subpart HHH of Part 63--Applicability of 40 CFR Part 63
                    General Provisions to Subpart HHH
------------------------------------------------------------------------
     General provisions           Applicable to
          reference                subpart HHH           Explanation
------------------------------------------------------------------------
Sec.   63.1(a)(1)...........  Yes.                  ....................
Sec.   63.1(a)(2)...........  Yes.                  ....................
Sec.   63.1(a)(3)...........  Yes.                  ....................
Sec.   63.1(a)(4)...........  Yes.                  ....................
Sec.   63.1(a)(5)...........  No..................  Section reserved.
Sec.   63.1(a)(6) through     Yes.                  ....................
 (a)(8).
Sec.   63.1(a)(9)...........  No..................  Section reserved.
Sec.   63.1(a)(10)..........  Yes.                  ....................
Sec.   63.1(a)(11)..........  Yes.                  ....................
Sec.   63.1(a)(12)..........  Yes.                  ....................
Sec.   63.1(b)(1)...........  No..................  Subpart HHH
                                                     specifies
                                                     applicability.
Sec.   63.1(b)(2)...........  Yes.                  ....................
Sec.   63.1(b)(3)...........  No.                   ....................
Sec.   63.1(c)(1)...........  No..................  Subpart HHH
                                                     specifies
                                                     applicability.
Sec.   63.1(c)(2)...........  No.                   ....................
Sec.   63.1(c)(3)...........  No..................  Section reserved.
Sec.   63.1(c)(4)...........  Yes.                  ....................
Sec.   63.1(c)(5)...........  Yes.                  ....................
Sec.   63.1(d)..............  No..................  Section reserved.
Sec.   63.1(e)..............  Yes.                  ....................
Sec.   63.2.................  Yes.................  Except definition of
                                                     major source is
                                                     unique for this
                                                     source category and
                                                     there are
                                                     additional
                                                     definitions in
                                                     subpart HHH.
Sec.   63.3(a) through (c)..  Yes.                  ....................
Sec.   63.4(a)(1)...........  Yes.................
Sec.   63.4(a)(2)...........  Yes.................
Sec.   63.4(a)(3)...........  No..................  Section reserved.
Sec.   63.4(a)(4)...........  No..................  Section reserved.
Sec.   63.4(a)(5)...........  No..................  Section reserved.
Sec.   63.4(b)..............  Yes.                  ....................
Sec.   63.4(c)..............  Yes.                  ....................
Sec.   63.5(a)(1)...........  Yes.                  ....................
Sec.   63.5(a)(2)...........  No..................  Preconstruction
                                                     review required
                                                     only for major
                                                     sources that
                                                     commence
                                                     construction after
                                                     promulgation of the
                                                     standard.
Sec.   63.5(b)(1)...........  Yes.                  ....................
Sec.   63.5(b)(2)...........  No..................  Section reserved.
Sec.   63.5(b)(3)...........  Yes.                  ....................
Sec.   63.5(b)(4)...........  Yes.                  ....................
Sec.   63.5(b)(5)...........  No..................  Section reserved.
Sec.   63.5(b)(6)...........  Yes.                  ....................
Sec.   63.5(c)..............  No..................  Section reserved.
Sec.   63.5(d)(1)...........  Yes.                  ....................
Sec.   63.5(d)(2)...........  Yes.                  ....................
Sec.   63.5(d)(3)...........  Yes.                  ....................
Sec.   63.5(d)(4)...........  Yes.                  ....................
Sec.   63.5(e)..............  Yes.                  ....................
Sec.   63.5(f)(1)...........  Yes.                  ....................
Sec.   63.5(f)(2)...........  Yes.                  ....................
Sec.   63.6(a)..............  Yes.                  ....................
Sec.   63.6(b)(1)...........  Yes.                  ....................
Sec.   63.6(b)(2)...........  Yes.                  ....................
Sec.   63.6(b)(3)...........  Yes.                  ....................
Sec.   63.6(b)(4)...........  Yes.                  ....................
Sec.   63.6(b)(5)...........  Yes.                  ....................
Sec.   63.6(b)(6)...........  No..................  Section reserved.
Sec.   63.6(b)(7)...........  Yes.                  ....................
Sec.   63.6(c)(1)...........  Yes.                  ....................
Sec.   63.6(c)(2)...........  Yes.                  ....................
Sec.   63.6(c)(3) and (c)(4)  No..................  Section reserved.
Sec.   63.6(c)(5)...........  Yes.                  ....................
Sec.   63.6(d)..............  No..................  Section reserved.
Sec.   63.6(e)..............  Yes.                  ....................
Sec.   63.6(e)..............  Yes.................  Except as otherwise
                                                     specified.
Sec.   63.6(e)(1)(i)........  No..................  See Sec.
                                                     63.1274(h) for
                                                     general duty
                                                     requirement.
Sec.   63.6(e)(1)(ii).......  No.                   ....................
Sec.   63.6(e)(1)(iii)......  Yes.                  ....................
Sec.   63.6(e)(2)...........  No..................  Section reserved.
Sec.   63.6(e)(3)...........  No.                   ....................
Sec.   63.6(f)(1)...........  No.                   ....................
Sec.   63.6(f)(2)...........  Yes.                  ....................
Sec.   63.6(f)(3)...........  Yes.                  ....................
Sec.   63.6(g)..............  Yes.                  ....................

[[Page 49599]]

 
Sec.   63.6(h)(1)...........  No.                   ....................
Sec.   63.6(h)(2)...........  Yes.                  ....................
Sec.   63.6(h)(3)...........  No..................  Section reserved.
Sec.   63.6(h)(4) through     Yes.                  ....................
 (h)(9).
Sec.   63.6(i)(1) through     Yes.                  ....................
 (i)(14).
Sec.   63.6(i)(15)..........  No..................  Section reserved.
Sec.   63.6(i)(16)..........  Yes.                  ....................
Sec.   63.6(j)..............  Yes.                  ....................
Sec.   63.7(a)(1)...........  Yes.                  ....................
Sec.   63.7(a)(2)...........  Yes.................  But the performance
                                                     test results must
                                                     be submitted within
                                                     180 days after the
                                                     compliance date.
Sec.   63.7(a)(3)...........  Yes.                  ....................
Sec.   63.7(a)(4)...........  Yes.                  ....................
Sec.   63.7(b)..............  Yes.                  ....................
Sec.   63.7(c)..............  Yes.                  ....................
Sec.   63.7(d)..............  Yes.                  ....................
Sec.   63.7(e)(1)...........  No.                   ....................
Sec.   63.7(e)(2)...........  Yes.                  ....................
Sec.   63.7(e)(3)...........  Yes.                  ....................
Sec.   63.7(e)(4)...........  Yes.                  ....................
Sec.   63.7(f)..............  Yes.                  ....................
Sec.   63.7(g)..............  Yes.                  ....................
Sec.   63.7(h)..............  Yes.                  ....................
Sec.   63.8(a)(1)...........  Yes.                  ....................
Sec.   63.8(a)(2)...........  Yes.                  ....................
Sec.   63.8(a)(3)...........  No..................  Section reserved.
Sec.   63.8(a)(4)...........  Yes.                  ....................
Sec.   63.8(b)(1)...........  Yes.                  ....................
Sec.   63.8(b)(2)...........  Yes.                  ....................
Sec.   63.8(b)(3)...........  Yes.                  ....................
Sec.   63.8(c)(1)...........  Yes.                  ....................
Sec.   63.8(c)(1)(i)........  No.
Sec.   63.8(c)(1)(ii).......  Yes.
Sec.   63.8(c)(1)(iii)......  No.                   ....................
Sec.   63.8(c)(2)...........  Yes.                  ....................
Sec.   63.8(c)(3)...........  Yes.                  ....................
Sec.   63.8(c)(4)...........  No.                   ....................
Sec.   63.8(c)(5) through     Yes.                  ....................
 (c)(8).
Sec.   63.8(d)(1)...........  Yes.                  ....................
Sec.   63.8(d)(2)...........  Yes.                  ....................
Sec.   63.8(d)(3)...........  Yes.................  Except for last
                                                     sentence, which
                                                     refers to an SSM
                                                     plan. SSM plans are
                                                     not required.
Sec.   63.8(e)..............  Yes.................  Subpart HHH does not
                                                     specifically
                                                     require continuous
                                                     emissions monitor
                                                     performance
                                                     evaluations,
                                                     however, the
                                                     Administrator can
                                                     request that one be
                                                     conducted.
Sec.   63.8(f)(1) through     Yes.                  ....................
 (f)(5).
Sec.   63.8(f)(6)...........  No..................  Subpart HHH does not
                                                     require continuous
                                                     emissions
                                                     monitoring.
Sec.   63.8(g)..............  No..................  Subpart HHH
                                                     specifies
                                                     continuous
                                                     monitoring system
                                                     data reduction
                                                     requirements.
Sec.   63.9(a)..............  Yes.                  ....................
Sec.   63.9(b)(1)...........  Yes.                  ....................
Sec.   63.9(b)(2)...........  Yes.................  Existing sources are
                                                     given 1 year
                                                     (rather than 120
                                                     days) to submit
                                                     this notification.
Sec.   63.9(b)(3)...........  No..................  Section reserved.
Sec.   63.9(b)(4)...........  Yes.                  ....................
Sec.   63.9(b)(5)...........  Yes.                  ....................
Sec.   63.9(c)..............  Yes.                  ....................
Sec.   63.9(d)..............  Yes.                  ....................
Sec.   63.9(e)..............  Yes.                  ....................
Sec.   63.9(f)..............  Yes.                  ....................
Sec.   63.9(g)..............  Yes.                  ....................
Sec.   63.9(h)(1) through     Yes.                  ....................
 (h)(3).
Sec.   63.9(h)(4)...........  No..................  Section reserved.
Sec.   63.9(h)(5) and (h)(6)  Yes.                  ....................
Sec.   63.9(i)..............  Yes.                  ....................
Sec.   63.9(j)..............  Yes.                  ....................
Sec.   63.10(a).............  Yes.                  ....................
Sec.   63.10(b)(1)..........  Yes.................  Section
                                                     63.1284(b)(1)
                                                     requires sources to
                                                     maintain the most
                                                     recent 12 months of
                                                     data on-site and
                                                     allows offsite
                                                     storage for the
                                                     remaining 4 years
                                                     of data.
Sec.   63.10(b)(2)..........  Yes.                  ....................

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Sec.   63.10(b)(2)(i).......  No.                   ....................
Sec.   63.10(b)(2)(ii)......  No..................  See Sec.
                                                     63.1284(f) for
                                                     recordkeeping of
                                                     (1) occurrence and
                                                     duration and (2)
                                                     actions taken
                                                     during malfunction.
Sec.   63.10(b)(2)(iii).....  Yes.                  ....................
Sec.   63.10(b)(2)(iv)        No.                   ....................
 through (b)(2)(v).
Sec.   63.10(b)(2)(vi)        Yes.                  ....................
 through (b)(2)(xiv).
Sec.   63.10(b)(3)..........  No.                   ....................
Sec.   63.10(c)(1)..........  Yes.                  ....................
Sec.   63.10(c)(2) through    No..................  Sections reserved.
 (c)(4).
Sec.   63.10(c)(5) through    Yes.                  ....................
 (c)(8).
Sec.   63.10(c)(9)..........  No..................  Section reserved.
Sec.   63.10(c)(10) through   No..................  See Sec.
 (c)(11).                                            63.1284(f) for
                                                     recordkeeping of
                                                     malfunctions.
Sec.   63.10(c)(12) through   Yes.                  ....................
 (c)(14).
Sec.   63.10(c)(15).........  No.                   ....................
Sec.   63.10(d)(1)..........  Yes.                  ....................
Sec.   63.10(d)(2)..........  Yes.                  ....................
Sec.   63.10(d)(3)..........  Yes.                  ....................
Sec.   63.10(d)(4)..........  Yes.                  ....................
Sec.   63.10(d)(5)..........  No..................  See Sec.
                                                     63.1285(b)(6) for
                                                     reporting of
                                                     malfunctions.
Sec.   63.10(e)(1)..........  Yes.                  ....................
Sec.   63.10(e)(2)..........  Yes.                  ....................
Sec.   63.10(e)(3)(i).......  Yes.................  Subpart HHH requires
                                                     major sources to
                                                     submit Periodic
                                                     Reports semi-
                                                     annually.
Sec.   63.10(e)(3)(i)(A)....  Yes.                  ....................
Sec.   63.10(e)(3)(i)(B)....  Yes.                  ....................
Sec.   63.10(e)(3)(i)(C)....  No..................  Section reserved.
Sec.   63.10(e)(3)(i)(D)....  Yes.                  ....................
Sec.   63.10(e)(3)(ii)        Yes.                  ....................
 through (e)(3)(viii).
Sec.   63.10(f).............  Yes.                  ....................
Sec.   63.11(a) through (e).  Yes.                  ....................
Sec.   63.12(a) through (c).  Yes.                  ....................
Sec.   63.13(a) through (c).  Yes.                  ....................
Sec.   63.14(a) through (q).  Yes.                  ....................
Sec.   63.15(a) and (b).....  Yes.                  ....................
------------------------------------------------------------------------

[FR Doc. 2012-16806 Filed 8-15-12; 8:45 am]
BILLING CODE 6560-50-P