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– DO NOT CITE OR QUOTE ¶ FEBRUARY 17, 2011 ¶ Formatted: Header Formatted: Font: Not Bold **6560 -**  **50 -**  **P** ***E.O. 12866 Review

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– Do Not Cite, Quote or Release During Review*** E.O. 12866 NSPS and NESHAP for Oil and Gas 2060

- AP76 Final Rule
20120417
**ENVIRONMENTAL PROTECTION AGENCY**  **40 CFR Part 63 [EPA**  **- HQ**  **- OAR**  **- 2010**  **- 0505; FRL**  **- ]**  **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.
**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 s ource 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, Style Definition

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... Deleted: (40 CFR part 60, subpart

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... Deleted: subparts KKK and LLL,

...Page 2 of 566 centrifugal compressors, reciprocating compressors, pneumatic controllers and storage vessels. This action also finalizes the residual ri sk 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, recordk eeping 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, shut down and malfunction.
**DATES:** This final rule is effective on **[INSERT DATE 60 DAYS AFTER THE DATE OF PUBLICATION IN THE FEDERAL REGISTER].**  The incorporation by reference of certain publications listed in this rule is approved by the Director of the Federal Register as of **[INSERT DATE 60 DAYS AFTER THE DATE OF PUBLICATION IN THE FEDERAL REGISTER].** 
**ADDRESSES:** The EPA has established a docket for this action under Docket ID. No. EPA

- HQ

- OAR

- 2010

- 0505. All documents in the Deleted: ,
Deleted: conducted under section 112 of the Clean Air Act Deleted: Facilities Deleted: (40 CFR part 63, subpart HH) Deleted: Facilities Deleted: (40 CFR part 63 , subpart HHH)
. Deleted: emission limit for glycol dehydration unit process vents and Deleted: pursuant to section 112(d)(2) and (3),

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docket are listed on the http: //www.reg ulations.gov web site

. Although listed in the index, s ome information is not publicly available, e.g. , confidentia l business information or other information whose disclosure is restricted by statute. Certain other material, such as copyrighted mate rial, is not placed on the Internet and will be publi cly 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 Const itution Avenue, NW, Washington, D.C. 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 Program s 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. Deleted: w ebsite

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- 05 ),Page 4 of 566

**SUPPLEMENTARY INFORMATION** : For specific information regarding risk assessment and exposure modeling methodo logy, 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 numbe r: (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

II I. Background Information on the NSPS and NESHAP A. What are the st atutory authorities for the NSPS and NESHAP?
B. What is the litig ation 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 Deleted: ,
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- 06),

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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 th e 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? Deleted: rule revisions

Deleted: , Transmission, and Distribution

Deleted: well affected facilities

Deleted: reciprocating compressor affected facilities Deleted: controller affected facilities Deleted: vessel affected facilities

Deleted: leaks a ffected facilities Deleted: sweetening unit affected facilities

Deleted: o nshore natural gas processing plant s Deleted: notification, recordkeeping Deleted: reporting requirements

Deleted: amendments fo r

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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, sh utdown 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 Deleted: D. How do the final NESHAPs provide for compliance assurance? ¶ E . What are the requirements for submission of performance test data to the EPA? ¶

Deleted: Natural Gas Production Facilities (subpart HH) source category ?

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Deleted: comments concerning a pplicability Deleted: comments concerning well completions Deleted: comments concerning pneumatic controllers Deleted: comme nts concerning compressors Deleted: comments concerning storage vessels Deleted: comments concerning equipment leaks ¶ G . Major comments concerning notification, recordkeeping Deleted: reporting requirements Deleted:Page 7 of 566 A. Major Comments Concerning Previously Unregulated Sources B. Major Comments Concerning the Risk Review C. Major Comments Concerning the Technology Review D. Major Comments Concerning Notification, Recordkeeping and Reporting Requirements XI. What are the cost, environmental and economic impacts of the final NESHAP and NSPS amendments?
A. What are the air impacts?
B. What are the energy impacts?
C. What are the cost impacts?
D. What are the economic impacts?
E. What are the benefits of this final rule?
XII. Statutory and Executive Order Reviews
A. Executive Order 12866 : Regulatory Planning and Review a nd Executive Order 13563 : Improving Regulation and Regulatory Review
B. Paperwork Reduction Act
C. Regulatory Flexibility Act
D. Unfu nded Mandates Reform Act
E. Executive Order 13132 : Federalism
F. E xecutive Order 13175 : Con sultation and Coordination with Indian Tribal Governments Deleted: comments concerning applicability Deleted: comments concerning Deleted: risk review Deleted: comments concerning Deleted: previously unregulated sources Deleted: comments concerning the technology review ¶ E. Major comments concerning notification, recordkeeping Deleted: reporting requirements Deleted: NSPS and

Deleted: Tribal GovernmentsPage 8 of 566

G. Executive Order 13045 : Protection of Children from Environmental Health Risks and Safety Risks
H. Executive Order 13211 : Acti ons Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use
I. National Technology Transfer and Advancement Act
J. Executive Order 12 898: Federal Actions to Address Environmental Justice in Mino rity 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 Amer ican 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
C AA Clean Air Act Deleted: ,

Deleted: ACGIH American Conference of Governmental Industrial Hygienists ¶ ADAF Age

- Dependent Adjustment Factors ¶ AEGL Acute Exposure Guideline Levels ¶ AERMOD The air dispersion model used by the HEM

– 3 model ¶ Deleted: Deleted: Deleted: BID Background Information Document ¶ BPD Deleted: Deleted:

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CBM Coal Bed Methane
CDX Central Data Exchange
CEDRI Compliance and Emissions Data Reporting Interface
CFR Code of Federal Regulations
CO Carbon Monoxide
CO 2 Carbon Dioxide
CO 2 e 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

H 2 S Hydrogen Sulfide
ICR Information Collection Request
IPCC Intergovernmental Panel on Climate Change Deleted: CalEPA California Environmental Protection Agency ¶ CBI Confidential Business Information ¶ CEM Continuous Deleted: Monitoring

Deleted: CEMS Continuous Emissions Monitoring System ¶ Deleted: Deleted: CIIT Chemical Industry Institute of Toxicology ¶ Deleted: Deleted: Deleted:

Deleted: ECHO Enforcement and Compliance History Online ¶ Deleted: Deleted: EJ Environmental Justice ¶ Deleted: Deleted: Deleted: Deleted:

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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 c ode 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
MMtC O 2 e 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 Deleted:

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NESHAP National Emissions Standards for Hazardous Air Pollutants
NGL Natural Gas Liquids
NIOSH National Institutes for Occupational Safety and Health
NO X 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 Plan ning 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

PM 2.5 Particulate Matter (2.5 microns and less)
POM Polycyclic Organic Matter
ppm Parts p er Million
ppmv Parts p er Million by Volume
PSIG Pounds p er S quare I nch G auge PSIA Pounds per Square Inch Absolute
PTE Potential to Emit QA Quality Assurance Deleted:

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RACT Reasonably Available Control Technology
RBLC RACT/BACT/LAER Clearinghouse
REC Reduced Emissions Completions

REL Cal ifornia 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 p er 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 Deleted:

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STEL Short

- term Exposure Limit
TLV Threshold Limit Value
TOSHI Target Orga n - 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
**I I**  **. General Information** A. Executive Summary 1. Purpose of the Regulatory Action Responding to the requirements of a consent decree, t his action finalizes several rules that apply to the oil and gas Deleted:

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Deleted: Deleted: Deleted: Deleted: Deleted: Deleted: Deleted: Formatted: Font color: Auto Formatted: Underline Deleted: On January 14, 2009, pursuant to section 304(a)(2) of the CAA, WildEarth Guardians and the San Juan Citizens Alliance filed a Complaint alleging that the EPA failed to meet its obligations under CAA sections 111(b)(1)(B), 112(d)(6) and 112(f)(2) to take actions relative to the review/revision of the NSPS and the NESHAP with respect to the Oil and Natural Gas Production source category. On February 4, 2010, the Court entered a consent decree that, as modified, requires the EPA to sign by July 28, 2011, proposed standards and/or determinations not to issue standards pursuant to CAA sections 111(b)(1)(B), 1 12(d)(6) and 112(f)(2) and to take final action by April 3, 2012. ¶ This action finalizes the review conducted under section 111(b) of the Clean Air Act of newPage 14 of 566 production industry and significantly reduce emissions of air pollutants

. More particularly, t he action finalizes:

• **New source performance standards**  **(NSPS)** for the Crude Oil and Natural Gas Production and onshore natural gas processing plant source categor y. The EPA reviewed two existing NSPS for onshore natural gas processing plant source categor y under section 111(b) of the Clean Air Act (CAA). T his 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 (**  **NESH AP**  **)** 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) f or these rules under section 112 of the
CAA. In addition, the EPA has established emission limits for certain currently uncontrolled emission sources in these source categories. These limits reflect maximum achievable control technology (MACT)

. 2. Summary of the Major Provisions of the Regulatory Action s **New So urce Performance Standards (NSPS).**  The newly established NSP S for the Crude Oil and Natural Gas P roduction source category regulate volatile organic compound ( VOC ) Formatted: Font: Bold, No underline, Font color: Auto Deleted: listed oil

Formatted: No underline, Font color: Auto Deleted: This action also finalizes the residual risk and technology review conducted

Deleted: 112

Formatted: List Paragraph,CARB_BULLETS, Bulleted + Level: 1 + Aligned at: 0.5" + Indent at: 0.75", Adjust space between Latin and Asian text, Adjust space between Asian text and numbers Deleted: Facilities Deleted: (40 CFR part 63, subpart HH) Deleted: Facilities Deleted: (40 CFR part 63, subpart HHH). Deleted: pursuant to section 112(d)(2) and (3), Formatted: Font: No underline, Font color: Auto Deleted: in this action Deleted: reflecting maximum achievable control technology

Formatted: Font color: Auto Deleted: Action

Formatted: Underline Deleted: In this action the EPA revised the new source performance standards for volatile organic compounds from leaking components at onshore natural gas processing plants (40 CFR part 60, subpart KKK) and new source performance standards for sulfur dioxide emissions from natural gas processing plants (40 CFR part 60, subpart LLL). The EPA also Deleted: standards (40 CFR part 60, subpart OOOO) for certain oil and gas operations not covered by the existing standards. In addition to the operations covered by subparts KKK and LLL, subpart OOOO willPage 15 of 566 emissions from gas wells, centrifugal compressors, reciprocating

com pressors, pneumatic controllers, storage vessels and leaking components at onshore natural gas processing plants, as well as sulfur dioxide ( SO 2 ) 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. Fo r fractured and refractured gas wells, the rule generally requires owners/operators to use reduced emissions completion s, also known as “RECs” or “green completions,” to reduce VOC emissions from well completions. To achieve these VOC reductions, o wners 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.** I ndividual storage vessels in the oil and natural gas production segment and the natural gas processing, transmission and storage segme nts with emissions equal to or greater than 6 tons per year ( tpy ) must achieve at least 95 .0 Deleted: and Deleted:

. ¶ For gas Deleted: affected facilities, we are finalizing operational standards for completions of hydraulically fractured gas wells. The final rule applies to three subcategories of fractured gas well s for which well completion operations are conducted: (1) wildcat (exploratory) and delineation wells; (2) non

- wildcat and non

delineation wells for which the reservoir pressure is insufficient for a reduced emissions completion (REC), commonly referred to as a “green completion,” to be performed, as determined by a simple calculation involving reservoir pressure, well depth and gathering line pressure at the sales meter (we refer to these wells as “low pressure wells”) and (3) all other fractured gas wells

. For category (3) wells, each well completion operation must employ REC in combination with use of a completion combustion device to control gas not suitable for entering the gathering line. For category (1) wells (exploratory and delineation wells) and c ategory (2) wells (low pressure wells), the final rule contains an operational standard that requires the use of a completion combustion device. However, the final rule does not prohibit the use of REC for completion of these wells. Deleted: For compressor affected facilities, the final rule requires measures to reduce VOC emissions from centrifugal and reciprocating compressors. The final rule contains standards forPage 16 of 566 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, conti nuous 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 require s a 95 .0 p ercent 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 the se 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 Formatted: Indent: First line: 0.5" Formatted: Font: Bold, No underline, Font color: Auto Deleted: The final standards require 95 percent reduction of VOC 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 9 5 percent. Deleted: The operational standards for reciprocating compressors in the final rule require replacement of the rod packing based on usage. The rod packing must be changed every 26,000 hours of operation. Alternatively, owners or operators can elect to change the rod packing every 36 months in lieu of monitoring compressor operating hours. ¶ We are also finalizing VOC standards to reduce emissions from individual natural gas

- driven pneumatic controllers that vent continuously to the atmosphere and are located between the wellhead and the point at which the gas enters the transmission and storage segment. At natural gas processing plants, the final rule includes a natural gas bleed rate limit of zero standard cubic feet per hour for each individual pneumatic controller. 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 final rule contains VOC standards for new or mo dified storage vessels. The final rule, which applies to individual vessels, requires that storage vessels with emissions equal to or greater than 6 tpy achieve at least 95 percent reduction in VOC emissions. ¶ Formatted: Font: Bold, No underline, Font color: Auto Deleted: we are revising Deleted: by 40 CFR 60, subpart VVaPage 17 of 566 Synthetic Organic C hemicals Manufacturing Industry . This final action also revises the existing NSPS requirements for SO 2 emission reductions 99.8 percent to 99.9 percent based on reanalysis of the original data

. **National Emissions Standards for Hazardous Air Pollutants (NE**  **SHAP).** 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 d efinition 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 Formatted: Font: Bold, No underline, Font color: Auto Deleted: includes revisions to Deleted: national emission standards for hazardous air pollutants Deleted: revised the new source MACT standards for “large” glycol dehydrators as well as the leak detection and repair requirements. In addition, pursuant to section 112(d)(2 Deleted: (3), we Deleted: dehydrators and storage vessels that were not controlled under the initial NESHAP. ¶

In this final rule, we have established for the first time MACT standards for “small” glycol Deleted: left Deleted: This subcategory consists of Deleted: flowrate Deleted: 0.9 megagrams per year (Mg/yr). Deleted: The final MACT standards for the subcategory of small dehydrators at oil and gas production facilities require that existing affected sources meet a unit

- specific BTEX limit of 3.28x10

- 4 grams BTEX/standard cubic meters (scm)

- parts per million by volume (ppmv) and that new affected sources meet a BTEX limit of 4.66 x10

- 6 grams BTEX/scm

- ppmv. ¶

In the final rule, we have also established for the f irst time MACT standards for certain storage vessels that were not previously Formatted: Indent: First line: 0.5" Deleted: The standard is the same as that promulgated in the initial NESHAP for the other storage vessels (i.e., 95 percent emission reduction). ¶ In the subpart HH final rule, as a result of our review under section 112(d)(6), we are revising the leak definition for valves to 500 ppm, thus requiring the application of the leak detection and repair requirement at this lower detection level. This leak definition applies only to valves and not other components. ¶

... Deleted: . In addition, pursuant to section 112(d)(2) and (3), we have established MACT standards for “small” glycol dehydrators that

... Deleted: flowratePage 18 of 566 283,000 scmd or actual average benzene emissions less than 0. 9 0 Mg/yr , and they must meet unit

- specific BTEX emission limit s. 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 M ONETIZED 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 Final NESHAP**  **Amendments Final NSPS and**  **NESHAP Amendments** 

**Combined** Total Monetized Benefits 2 N/A N/A N/A

Total Costs 3 - $ 1 5 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 1 90,000 tons of VOC 1,200 tons of VOC 1 90,000 tons of VOC 1.0 million tons of methane 420 tons of methane 1.0 million tons of methane Health effects of HAP exposure Health effects of PM 2.5 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 eff ects associated with HAP, ozone and particulate matter (PM) , as well as climate effects associated with methane, we have determined that quantificati on 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 i mpacts of Deleted: 9 Deleted:

. ¶ The final MACT standard for this subcategory of small dehydrators requires existing affected sources to Deleted: a Deleted: 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 Formatted: Font color: Auto Formatted: Underline Deleted: 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 Produc tion source category is approximately $47 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 $370 thousand. 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 $18 million. The tota l 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 $360,000. All costs are in 2008 dollars. ¶ The estimated total capital cost to comply with the final NSPS is approximately $340 million in 2008 dollars. The total estimated net annual cost to industry to comply with the final NSPS is approximately $340 million in 2008 dollars. ¶ The final Oil and Natural Gas NSPS and NESHAP amendm ents 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 20,000 tons of HAP, 300,000 tons of VOC (a precursor to both PM 2.5 and ozone formation) and 1.7 million tons of methane (a GHG and a

... Moved (insertion) [1] Formatted Table Formatted: CenteredPage 19 of 566

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 f rom 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 Re gulatory Impact Analysis ( RIA )
. 4 For the NSPS, reduced exposure to HAP and climate effects are co

- benefits. For the NESHAP, reduced VOC emissions, PM 2.5 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 (CO 2 ), 550 tons of nitrogen oxides ( NO x ), 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 CO 2 - 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 **Category NAICS code**  **1 Examples of regulated entities**  Industry . . . . 211111 Crude Petroleum and Natural Gas Extraction 211112 Natural Gas Liquid Extraction 221210 Natural Gas Distribution 486110 Pipeline Distribution of Crude Oil 486210 Pipeline Transportation of Natural Gas Federal government

. . . . Not affected

. State/local/tribal government . . . . Not affected

.

1 North American Industry Classification System. This table is not intended to be exhaustive, but rather is meant to provide a guide for re aders regarding entities likely Moved (insertion) [2] Formatted: Font: 10 pt Formatted: Font: 10 pt, No underline, Font color: Auto

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. Deleted: PROPOSED Formatted: Font: Bold, No underline, Font color: Auto Formatted Table Formatted: Font: Bold Formatted: Font: Bold, No underline, Font color: Auto Formatted: Font: Bold Formatted: Font: Bold, No underline, Font color: Auto Formatted: Font: Bold

Formatted: Line spacing: single, Tab stops: 0", Left + 0.5", Left + 1", Left + 1.5", Left + 2", Left + 2.5", Left + 3", Left + 3.5", Left + 4", Left + 4.5", Left + 5", Left + 5.5", LeftPage 20 of 566 to be affected by this actio n. If y ou have any questions regarding the applicability of this action to a particular entity, consu lt ei ther the air permitting autho rity 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 vessel s 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 in clude 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 Formatted: Font color: Auto Deleted:

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Deleted: na tural gas

- driven pneumatic controllers (including replacement of an existing device ).Page 21 of 566 pneumatic controllers which commenced construction after August 23, 2011 , at natural gas processing plants

. The NSPS applies to centrif ugal compressors with wet seals and reciprocating compressors located in the natural gas production and processing segments. The NSPS also applies to equipment leak s from onshore natural gas processing plants and to storage vessels l ocated 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 actio n will also be available on the World W ide Web (WWW). Following signature by t he Administrator, a copy of the action will be posted on the EPA’s website at the following address: http://www.epa.gov/airquality/oilandgas

. Additional information is available on the EPA’s RTR web site at htt p://www.epa.gov/ttn/atw/rrisk/oarpg.html . This information includes the most recent version of the rule, source Deleted: oil and

Deleted: new or modified

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Deleted: , Deleted: and storage vessels Formatted: Font color: Auto

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Deleted: Residual Risk and Technology Review (RTR) WebPage 22 of 566 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 **[INSERT DATE 60 DAYS AFTER PUBLICATION IN THE FEDERAL**
**REGISTER ]**  **.** Under CAA se ction 307(d)(7)(B), only an objection to this final rule that was raised with reasonable specificity du ring the period for public comment (inclu ding any public hearing) can be raised during judicial revie w. This section also provides a mechanism for the EP A to convene a proceeding for reconsideration “[i]f the person raising an objection can demonstrate to the Administrat or that it was impracticable to raise such objection within [th e period for public comment] or if the grounds for such objec tion arose aft er 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[.]” An y person seeking to make such a demonstration to us should submit a Petition for Reconsideration to the Office of the Administ rator, Environmental Protection Agency, Room 3000, Ariel Rios Building, 1200 Pennsylvania Ave.,
NW , Washington, D.C. 20004, with a copy to the person listed in the preceding **FOR FURTHER INFORMA TION CONTACT**  section, and the Deleted: U.S.

Deleted: .,Page 23 of 566

Associate General Counsel for th e Air and Radiation Law Office, Office of General Counsel ( Mail Code 2344A), Environmental Protection Agency, 1200 Pennsylv ania Ave., NW, Washington, D.C. 20004. Note, under CAA sect ion 307(b)(2 ), the requirements established by this final rule m ay not be challenged separately in any civil or criminal procee dings 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 shou ld be developed, identify the facilities within each source category to be covered and set the emission level of the standards. Deleted: **and NSPS**

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Deleted: new source performance standards (NSPS).Page 24 of 566

CAA section 111 (b)(1)(B) requires the EPA to “ at least every 8 years revi ew 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 availab le 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 B SER, 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 Deleted: ‘‘

Deleted: revise’’

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Deleted: best system of emission reductionPage 25 of 566 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 Administrato r determines it is not feasible to prescribe or enforce a standard of performance. Typically, sources remain free to s elect any control measures that will meet the emission limits. Upon promulgation, an NSPS becomes a national s tandard 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 ref lect 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. Formatted: Font color: Auto

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Deleted: maximum achievable control technology (MACT)Page 26 of 566

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 othe r modifications, (2) enclose systems or processes to eliminate emissions, (3) capture or treat pollutants when released from a process, stack, storage or fugitive emissions point, (4) are design, equipment, work practice or operational standards (including requirements for operator training or certification) or (5) are a combination of the above. CAA section s 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 determine s 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
met hodology 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 Deleted: section

Deleted: ¶Page 27 of 566 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 wit h 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 c ontrol technologies) ” no less frequently than every 8 years, under CAA section 112(d)(6). In conducting this review, the EPA is not obliged to completely recalculate the prior MACT determination. NRDC v.
EPA , 529 F.3d 1077, 1084 (D.C. Cir. 2008). The second stage in standard

- setting focuses on reducing any remaining “ residual ” risk according to CAA section 112(f). This provision requires, first, that the EPA prepare a Report to Congress discussing (among other things) methods of calculating risk po sed (or potentially posed) by sources after Formatted: No underline, Font color: AutoPage 28 of 566

i mplementation of the MACT standards, the public hea lth significance of those risks and the EPA’s recommendations as to legislation regarding such remaining risk. The EPA prepared and submitted this report ( Resi dual 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 s ection 112(f)(2) expressly preserves our use of a
two

- step process for developing standards t o 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 publi c 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 cons ideration costs, energy, safety and other relevant factors). Deleted: ,

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If the MACT standards f or 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 pr omulgate 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, t he 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. 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

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 signi ficant degradation of environmental qualities over broad areas. Formatted: No underline, Font color: Auto

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States Court of Ap peals 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
not ified 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 ri sk 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 Deleted: subsection

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Deleted:Page 31 of 566 facility would have if he or she were exposed to the maximum po llutant concentrations for 70 years. The a gency 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 t he exposed population. ” The a gency 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 de fine “ 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 Deleted: Agency

Deleted: AgencyPage 32 of 566 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 ba sed 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 “ consi deration 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 o f maximum individual lifetime cancer risk, but does not constitute a rigid line for making that determination. The a gency 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 Deleted: AgencyPage 33 of 566

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 indivi dual lifetime risk range and associated incidence within, typically, a 50

- kilometer (km) exposure radius around facilities, the science policy assumptions and estimation uncertainties associated with the risk measures, weight of the scientific evidence for human health effects, other quantified or unquantified health effects, effects due to co

- location of facilities and co

- emission of pollutants. ” Id

. In some cases, these health measures and factors taken together may provide a more realistic description o f 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 inqui ry 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 a gency again considers all of the health risks and other health information considered in the first step. Beyond that information, additional factors relating to the Deleted: Agenc yPage 34 of 566 appropriate level are considered, including costs and economic impacts of controls, techn ological feasibility, uncertainties and any other relevant factors. Considering all of these factors, the a gency will establish the standard at a level that provides an ample margin of safety to protect the public health, as required by CAA section 1 12(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 c omplaint in the United States District Court for the District of Columbia and alleg ed 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

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. Deleted: Agency

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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.
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 technic al 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, consider ing 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 con trol 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 Deleted:Page 36 of 566

each other and other regulatory requirements currently under review for oil and gas facilities. In this analysis, we looked
at how the different control requirements that result from these requirements interact, including the different regulatory deadlines and control equipment requirements that result, the different reporting and recordkeeping requirements and opportunities for states to account for reductions resulting from this rulemaking in their State Implementation Plans (SIP). The requirements analyzed affect criteria pollutant s , HAP and metha ne 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 o il and n atural g as sector NSPS and NESHAP amendments are expected to result in significant reductions in Deleted: pollutant

Moved (insertion) [4] Moved up [4]: As a result of the sector

- based approach, this rulemaking will reduce conflicting and redundant requirements. Deleted: facilitate s Deleted: streamlining ofPage 37 of 566 existing emissions and prevent new emissions from expansi ons of th is industry. These emissions include HAP, VOC (a precursor to both PM 2.5 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

c limate effects. One HAP of particular concern from the oil and natural gas sector is benzene, which is a known human carcinogen. PM 2.5 is associated with health effects , including premature mortality for adults and infants, cardiovascular morbidity, such as heart attacks, hospital admissions a nd 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 SO 2 emissions from sweetening Deleted: the

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Moved (insertion) [5]

Moved up [5]: 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. Formatted: No underline, Font color: Auto, Subscript

Moved (insertion) [6] Moved up [6]: **IV. Summary of the Final NSPS Rule**  **¶** A.

Moved (insertion) [7]Page 38 of 566 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, reconstructio n 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 establish ing standards in this final ru le. Table 3 summarizes the 40 CFR part 60, subpart OOOO standards. Further discussion of these changes may be found below in this section and in sections V and IX of this preamble

. TABLE 3. SUMMARY OF 40 CFR PART 60, SUBPART OOOO EMISSION
STANDARDS
**Affected Facility Pollutant**  **Standard Compliance Dates** 
Hydraulically fractured wildcat and delineation wells VOC Route flowback emissions to

completion combustion device **[INSERT DATE 60 DAYS AFTER DATE OF**  **PUBLICATION IN THE FEDERAL REGISTER]**  Hydraulically fractured low pressure wells, non

wildcat and non

delineation wells VOC Route flowback emissions to

completion combustion device **[INSERT DATE 60 DAYS AFTER DATE OF**  **PUBLICATION IN THE FEDERAL REGISTER]** 

All other hydraulically

fractured gas wells VOC Route flowback emissions to

completion combustion device Prior to January 1, 2015

All other hydraulically

fractured gas wells VOC Use REC and route flowback emissions to completion combustion device On or after January 1, 2015 Moved up [7]: We are revising the existing NSPS, which regulate VOC emissions from equipment leaks and SO 2 emissions from sweetening units at onshore gas processing plants. In addition, we are pro mulgating 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

. ¶ Deleted: oil Deleted: gas Deleted: all Deleted: in this industry (production, processing, transmission, storage, and distribution), including those Deleted: To the extent there are operations not covered by the currently listed category, pursuant to section 111(b), we have modified the list to include all operations Deleted: industry as mentioned above Deleted: 1.Page 39 of 566

Centrifugal compressors with wet seals VOC Reduce emissions by 95 percent **[INSERT DATE 60 DAY S**  **AFTER DATE OF PUBLICATION IN THE**  **FEDERAL REGISTER]**

Reciprocating compressors VOC Change rod packing after 26,000 hours or after 36 months **[INSERT DATE 60 DAYS AFTER DATE OF**  **PUBLICATION IN THE FEDERAL REGISTER]**  Continuous bleed natural

gas - driven pneumatic controllers at natural gas processing plants VOC Natural gas bleed rate of zero **[INSERT DATE 60 DAYS AFTER DATE OF**  **PUBLICATION IN THE FEDERAL REGISTER]**  Continuous bleed natural

gas - driven pneumatic controllers with a bleed rate greater than 6 sc fh

between wellhead and natural gas processing plant VOC Natural gas bleed rate less than 6 scfh **[INSERT DATE 1 YEAR AFTER DATE OF**  **PUBLICATION IN THE FEDERAL REGISTER]** 
Storage vessels with VOC

emissions equal to or

greater than 6 tpy VOC Reduce emissions by 95 percent **[INSERT DATE 1 YEAR AFTER DATE OF**  **PUBLICATION IN THE FEDERAL REGISTER]** 
Equipment leaks at onshore natural gas

processing plants VOC LDAR program **[INSERT DATE 60 DAYS AFTER DATE OF**  **PUBLICATION IN THE FEDERAL REGISTER]** 

Sweetening units at onshore natural gas

processing plants SO 2 Reduce SO 2 emissions based on sulfur

feed rate and sulfur content of acid gas **[INSERT DATE 60 DAYS AFTER DATE OF**  **PUBLICATION IN THE FEDERAL REGISTER]** 

1. Standards for G as W ell A ffected F acilities 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 Formatted: Font color: Auto Deleted: gas well affected facilities

Formatted: Underline

Deleted: continuous Deleted: of gas to the salesPage 40 of 566

refractured gas wells for which well completion operations are conducted: (1) W ildcat (exp l oratory) and delineation gas wells; (2) non

- wildcat an d 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 w ells ), subcategory (2) wells (low pressure gas wells) and for w ell 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 Deleted: wildcat

Deleted: reduced emissions completion (REC),

Deleted: gathering

Deleted: all

Deleted: category

Deleted: **[INSERT DATE TWO YEARS AFTER DATE OF PUBLICATION IN THE FEDERAL**  **REGISTER]** ,

Deleted: gathering Deleted:

.

Deleted: **[INSERT DATE TWO YEARS AFTER DATE OF PUBLICATION IN THE FEDERAL**  **REGISTER]** Formatted: Font: Calibri, 11 pt, No underline, Font color: Auto Deleted: category Deleted: using

Deleted: if possible Deleted: For category (1) wells ( exploratory and delineation wells ) and category (2) wells (low pressure wells) , the final rule contains an operational standard that requires the use of a completion combustion device. However, the final rule does not prohibit the use of REC for completion of these wells. ¶ Deleted: limited toPage 41 of 566 following refracturing operations at various times over the life of the well. As we explained in the proposa l 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 increase s during the refracturing and completion operation. In response to comment, we further clarify this point in the final rule, including providing a specific modification provis ion for well completions in lieu of the General Provisions in 40 CFR 60.14
. For a more detailed explanation, please s ee 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 tha t 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 comp letions 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 Deleted: We have determined that

Deleted: operations Deleted: an existing well ( i.e. , a well existing prior to August 23, 2011) Deleted: exis ting

Deleted: Therefore, the final standards apply to

Deleted: at new gas wells that are fractured or refractured as well as completions associated with fracturing or refracturing of existing gas wells.

Deleted: fracturing or Deleted: existing Deleted: ( i.e. , wells existing before August 23, 2011) **,** Deleted: wellhead, Deleted: bore, casing Deleted: tubing, and any conveyance through which gas is vented to the atmosphere . It Deleted: extend Deleted:

.Page 42 of 566
result, are not affected facilities under the NSPS if the completion operation is conducted with the use , immediately upon flowback, of emission control techniques otherwise required on or after January 1, 2015, for new wells and satisfies other requirements, including notification, recordkeeping and reporting requirements. In the final rule, we provide for a streamlined notification process for well completions at gas well affected facilities consisting of an email pre

- notification no later than 2 days in advance of impending completion operations. The email must include information that had been part of the 30

- day advance notification, as described in the proposed rule, including contact information for the owner and operator, well identification, geographic coordinates of the well and planned date of the beginning of flowback. In the final rule, the record keeping 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 identifyingPage 43 of 566

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. T he operator retains a digital image of each R EC 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 F acilities The final rule requires measures to redu ce 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 operationa l standards for reciprocating compressors in the final rule require replacement of the rod packing based on
usage. Moved (insertion) [8]

Deleted: 2. Standards for compressor affected facilities ¶ Moved up [8]: The final rule requires measures to reduce VOC emissions from centrifugal and reciprocating compressors.

Deleted:

Deleted: between the wellhead and

Deleted: Compressors located in the transmission and storage segment are not affected facilities.

Moved (insertion) [9]

Moved up [9]: ¶ The operational standards for reciprocating compressors in the final rule require replacement of the rod packing based on usage.Page 44 of 566 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 t o 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 A ffecte d F acilities We are also finalizing pneumatic co ntroller 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 plan ts, 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, e ach continuous bleed, natural gas

- driven pneumatic controller that emits more than 6 scfh is an affected facility if it is Deleted: **[INSERT DATE 60 DAYS**  **FOLLOWING DATE OF PUBLICATION IN**  **THE FEDERAL REGISTER]** , or on Deleted: rod Deleted: When the hours of operation reach 26,000 hours (equivalent to 36 months of continuous usage) , the owner or operator is required to change the rod packing immediately. Alternatively, o wners or operators can elect to change the rod packing every 36 months in lieu of monitoring compressor operating hours. Formatted: Font color: Auto Deleted: pneumatic controller affected facilit ies Formatted: Underline Deleted: to reduce emissions from individual Deleted: controllers that vent continuously to the atmosphere and are Deleted: Pneumatic Deleted: in the transmission and storage segment and distribution segme nts are not affected facilities . Each Deleted: Deleted: device Deleted: . Accordingly, the final standards apply to each newly installed pneumatic controller (including replacement of an e xisting controller ).Page 45 of 566 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 p neumatic 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 g as - 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 processin g 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 o f gas per hour for an individual pneumatic controller

. T he 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 dis cu ssed 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 V essels The final rule contains VOC standards for new , modified or reconstructed storage vessels located in the oil and natural gas Deleted: standard cubic feet per hour for each individual pneumatic controller.

Deleted: , which would reflect the emission level achievable from the use of low bleed natural gas - driven pneumatic controllers. In both cases, the Deleted: for certain critical applicat ions based on functional considerations

Formatted: Font color: Auto Deleted: Formatted: Font color: Auto Deleted: storage vessels Formatted: Underline Deleted: orPage 46 of 566 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 magnitud e 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 char acteristics 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 P rocessing P lants Deleted:

-
Deleted: installed

Deleted: installation, or in situations where a storage vessel currently emitting less tha n 6 tpy experiences an increase in throughput due to an additional well coming on line Deleted: other factor

Moved (insertion) [10]

Moved up [10]: If the storage vessel requires control, the fi nal rule provides an additional 30 days for the control device to be installed and operational. Deleted: installation, or in situations where an existing storage vessel is replaced

Formatted: Font color: Auto Deleted: Formatted: Font color: Auto Deleted: affected facilities located at onshore nat ural gas processing plants Formatted: UnderlinePage 47 of 566 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 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 A ffected Facilities at Onshore Natural Gas Processing P lants The final rule regulates SO 2 emissions from natural gas processing plants by requir ing affected facilities to reduce SO 2 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 w ere made to adapt the subpart LLL language to subpart OOOO. The final rule also increased the
SO 2 emission reduction standard from the subpart LLL requirement of 99.8 percent to 99.9 percent for units with sulfur production rate of at least 5 long tons per day. This change is based on reanalysis of the original data used in the subpart LLL BSER analysis. B. What are the effective and compliance dates for the final
NSPS? The revisions to the existing NSPS standards and the new NSPS standards promulgat ed in this action are effective on Deleted: leak detection and repair ( Deleted: )

Formatted: Font color: Auto Deleted:

Formatted: Font color: Auto Deleted: sweetening unit affected facilities at onshore natural gas processing plants

Formatted: Underline Deleted: is a revision to the current standard, which Deleted:

Deleted: beingPage 48 of 566
**[INSERT DATE 60 DAYS AFTER DATE**  **OF PUBLICATION IN THE FEDERAL REGISTER]**  . Affected facilities must be in compliance with the final standards on the effective date, **[INSERT DATE 60 DAYS**
**AFTER DATE OF PUBLICATION IN THE FEDERAL REGISTER]** 
. **V. Summary of the Significant Changes to the NSPS S**  **ince 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 impr ove clarity, while fully preserving or improving the public health and environmental protection required by the CAA.
A. Gas Well Affected F acilities We have revised the requirements for gas well affected facil ities 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)

w ildcat (exploratory) and delineation gas wells; (2) non

- wildcat Deleted: **s ince** 

Deleted: described

Deleted: is making from the

Deleted: While our approach and methodology to establishing the standards remain the same,

Deleted: ,

Deleted: well affected facilities

Deleted: In the final rule, we are revising the requirements for gas well affected facilities. In the proposed subpart OOOO, the rule requirements applied to gas well affected facilities that commenced construction, modification or reconstruction after August 23, 2011Page 49 of 566

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 emplo y 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

- del ineation 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 **[INSERT DATE 60 DAYS**  **AFTER DATE OF PUBLICATION IN THE FEDERAL REGISTER]**  are required to control flowback emissions by using
REC with combustion or by routing emissions to a completion Deleted: RECs

Deleted: category

Deleted: **[INSERT DATE TWO YEARS AFTER DATE OF PUBLICATION IN THE FEDERAL**  **REGISTER].**

Deleted: if possible

Deleted: category

Deleted: category

Deleted: perform

Deleted: in combinationPage 50 of 566

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 fl owback 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 li ght of the comments received, Deleted: Additionally, we are finalizing our proposed definition of modification as it pertains to well completion operations follow ing fracturing or refracturing. The final rule provides clarification of what we consider to be a modification for gas well affected facilities by specifying that well completion operations following hydraulic fracturing or refracturing at gas well facilities in existence before August 23, 2011 are considered modification s with respect to the gas well affected facility and are therefore subject to the requirements of the NSPS

. ¶ In the proposed rule,

Formatted: Indent: First line: 0.5"

Deleted: For

Deleted: RECs.Page 51 of 566 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 Deleted:

.
Deleted: by

Deleted: first Deleted: month of all anticipated Deleted: operations during that month

Deleted: We have also added a requirement that the owner or operator notify the Administrator of the actual date of each well completion operation by email no t earlier than 3 days or later than 2 days prior to the wel l completion operationPage 52 of 566 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. T he operator reta ins 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 C ompressor Affected F acilities 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 Moved (insertion) [11]

Deleted: In the final rule, we have also added a recordkeeping requirement for each gas well facility for which an exemption from combustion requirements is claimed. Owners and operators are now required to record the location of the well; the specific exemption claimed; the starting and ending date of the period the well operated under the exemp tion; and an explanation of why the well meets the claimed exemption. ¶ Moved up [11]: 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.

Deleted: reciprocating compressor affected facilities Deleted: in response to comments requesting clarification Deleted: compressors Deleted:

. We have clarified that the NSPS does Deleted: apply toPage 53 of 566 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 compressor s with wet seals reduce emissions by 95 .0 percent. The standard can be achieved by capturing and routing emissions from the wet seal fluid degassing system to a control device that reduces VOC emissions by 95 .0 percent. Testing, monitoring, recordkeeping, reporting and notification requirements associated with the control devices have also been added. In contrast to the proposed rule, in the final rule, centrifugal compressors with dry seals are not affected facilities. More detailed discussion of this change is presented in section IX.D of this preamble. As proposed, owners or operators of reciprocating compressor affected facilit ies were required to change rod packing after 26,000 hours o f 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 Deleted: natural gas Deleted: and storage se gment

Deleted: We are not requiring that

Deleted: , as we proposed, due to

Deleted: Instead, we are requiring

Deleted: percent. Centrifugal compressors with dry seals are not affected facilities.Page 54 of 566 instead of tracking compressor hou rs 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 A ffected F acilities 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 bl eed rate greater than 6 scfh for which construction, modification or reconstruction commenced after August 23, 2011

. A t natural gas processing plants, individual continuous bleed natural gas

operated pneumatic controller s for which construction, modification or reconstruction commenced after August 23, 2011,

are affected facilit ies 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, Deleted:

.

Moved (insertion) [12]

Moved up [12]: Refer to section IX .D o f this preamble and the Responses to Comments document, available in the docket, for detailed discussion regarding these changes. ¶ C. Deleted: controller affected facilities

Deleted: controller that vents continuously to the atmosphere.

Deleted: be regulated by the

Deleted: Cont rollersPage 55 of 566

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 **[INSERT DATE OF PUBLICATION IN FEDERAL REGISTER]**  before the bleed rate limit is effective for an aff ected 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 curr ent 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 emi ssions 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, Deleted: In the prop osed rule, a Deleted: facility installed after August 23, 2011 was subject to the requirements. The final rule now applies to pneumatic controller affected facilities installed after **[INSERT DATE OF PUBLICATION IN THE FEDERAL**  **REGISTER].** All new , modified , and reconstructed pneumatic controllers

Deleted: in order toPage 56 of 566

rather than those installed only during the reporting period. I n 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 change s. D. Storage V essel A ffected F acilities 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 mob ile (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 h ave revised the final rule such that storage vessels th at Deleted: on

Deleted: installed

Moved (insertion) [13]

Moved up [13]: Refer to section IX .C of this preamble and the Responses to Comments document, available in the docket, for detailed discussion regarding these changes. Deleted: vessel affected facilities Moved (insertion) [14]

Moved up [14]: We have modified the definition of “storage vessel” to exclude surge contr ol vessels, knockout vessels and pressure vessels designed to operate without emissions to the atmosphere. Deleted: a motor vehicle Deleted: stationary once it is

Deleted: ,Page 57 of 566

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 st orage vessels in the proposed rule pointed to 4 0 CFR part 63, subpart HH (the Oil and Natural
Gas P roduction 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 Deleted: less than Deleted: not required Deleted: be controlled.

Deleted: installed

Deleted: installation, or in situations where a storage vessel currently emitting less than 6 tpy experiences an increase in throughput due to an additional well coming on line or other factor

Moved (insertion) [15]

Moved up [15]: If the storage vessel requires control, the final rule provides an add itional 30 days for the control device to be installed and operational. Deleted: For Deleted: installation, or in situations where an existing storage vessel is replaced,

Deleted: oil Deleted: natural gas productionPage 58 of 566
60, subpart OOOO and mo dified 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 **[INSERT DATE OF PUBLICATION IN FEDERAL REGISTER]**  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 determ ining 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 est ablish the need for a control device and procure and install the equipment. Refer to section IX .E of this preamble and the Responses to Comments document, available in the docket, for detailed discussion regarding these changes.
E. Equipment Leaks Affected Facilities and Sweetening Unit Affected
F acilitie s a t O nshore Natural G as P rocessing 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) Moved (insertion) [16]

Moved up [16]: Refer to section IX .E of this preamble and the Responses to Comments document, available in the docket, for detailed discussion regarding these changes. ¶ E. Deleted: leaks Formatted: No underline, Font color: Auto

Deleted: and sweetening unit affected facilitie sPage 59 of 566

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 identifica tion 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 N otification, Recordkeeping and Reporting

R equirements In response to comment expressing concern with the burdens associated with demonstrating and monitoring compliance, w e have

re analyzed 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 Formatted: No underline, Font color: Auto Deleted: plant affected facilities ¶ We have not made any changes since proposal to the requirements for affected facilities and sweetening unit affected facilities

Deleted: for the final rule. Deleted: section IX .F of this preamble and

Deleted: notification, recordkeeping and reporting requirements

Deleted: We have a nalyzed

Deleted: throughout

Deleted: under section Deleted:Page 60 of 566 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 f inal 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 avo id 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 requir ements are considered to have met the advance notification requirements of the NSPS. Additionally, i n lieu of the standard annual reporting requirements, the final rule allows submission of an annual report for gas well affected facilities that consist s on ly of a list, with identifying information of all affected gas wells completed, electronic or hard copy photographs documenting RECPage 61 of 566 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 re garding 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 standards for previously unregulated source BTEX emission limit: New sources

– 4.66x10 - 6 g/scm

- ppmv Existing sources

– 3.28x10 - 4 g/scm

ppmv

“ A ssociated equipment” Revised definition to exclude all storage vessels N/A Valves

– equipment Revised definition of leak LDAR for valves must be applied at 500 ppm Deleted: ,
Moved (insertion) [17]

Moved up [17]: 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. Deleted: G Moved (insertion) [18] Moved up [18]: **VI. Summary of the Final NESHAP Rules**  ¶ A. Deleted: amendments for Deleted: FacilitiesPage 62 of 566

leaks

All affected sources Eliminated exemption from compliance during periods of startup, shutdown and malfunction Standards apply at all times

P ursuant to CAA section s 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 developmen ts 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

se ction 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 Deleted: section

Deleted: “ Deleted: ” Deleted: and storage vessels Deleted: controlled under

Deleted: havePage 63 of 566 the new MACT standard for small glycol dehydrators) provide an
amp le 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 s tandards at all times and made other revisions relative to periods of startup, shutdown and malfunction. Lastly, the final rule revises and adds certain testing and monitoring and related notification, recordkeeping and reporting requirements and makes certain other minor technical revisions to the NESHAP. 1. Standards for S mal l Glycol Dehydration U nits In this final rule, we have established MACT standards under CAA section s 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 3.28x10 - 4 grams BTEX/standard cubic meters (scm)

- parts per million by volume Deleted: , including

Deleted: includes modification Deleted: addition of

Deleted: , as well as

Deleted: Our review under section 112(f)(2) did not result in revision to the standards. Formatted: Font color: Auto Deleted: glycol dehydration unit process vents Formatted: Underline Deleted: for the first time Deleted: for “ Deleted: ” Deleted: under

Deleted: ¶

Deleted: the subcate gory ofPage 64 of 566 (ppmv) and that new affected sources meet a BTEX limit of 4.66 x10 - 6 grams BTEX/scm

- ppmv. 2 . Standards for equipment leaks
In t he 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 R equirements The final rule revise s 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 repla cement. 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 conjuncti on 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 the y become subject to the provisions of this subpart or by **[INSERT DATE 1**  **YEAR AND 60 DAYS**  **AFTER DATE OF PUBLICATION IN THE FEDERAL REGISTER]**  **,** whichever is later

. Deleted: 2. Standards for storage vessels ¶

In the final rule, we have also established for the first time MACT standards for certain storage vessels that were not previously regulated under the initial NESHAP. The standard is the same as that promulgated in the initial NESHAP for the other storage vessels ( i.e. , 95 percent emission reduction). Thus, the storag e vessel requirements will apply to all storage vessels at major sources, not just to those storage vessels with hydrocarbon liquid throughput equal to or greater than 79,500 liters per day

. In addition, we have amended the definition of associated equipme nt to exclude all storage vessels, and not just those with the PFE, from being considered “associated equipment.” This means that emissions from all storage vessels, and not just those from storage vessels with the PFE, are to be included in the major sour ce determination. ¶ 3 Deleted: leak detection and repair Deleted: 4 Formatted: Font color: Auto Deleted: recordkeeping Formatted: Font color: Auto Deleted: reporting requirements Formatted: Underline Deleted: or Deleted: of Deleted: addition, in Deleted: and storage vessels that do not have the PFE in the final amendments to 40 CFR part 63, subpart HH Deleted: small glycol dehydration Deleted: and storage vessels Deleted: becoming Deleted: HH (as revised in this final rule) Deleted: the date of publication of the final rule in the Federal Register , Formatted: Font: Bold, No underline, Font color: AutoPage 65 of 566

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 p eriod. 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 d escription 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 PA RT 63, SUBPART HHH

**Affected**

**Source Nature of Change**  **Standard**

Small glycol dehydrators Established MACT standards for previously unregulated source BTEX emission limit: New sources

– 5.44x10 - 5 g/scm

- ppmv Existing sources

– 3.01x10 - 4 g/scm

ppmv

All affected sources Eliminated exemption from compliance during periods of startup, shutdown and Standards apply at all times Moved (insertion) [19]

Deleted: Newly a ffected sources under 40 CFR part 63, subpart HH that plan to be area sources by the major source compliance dates will be required to submit a notification describing their schedule for the actions planned to achieve area source status. ¶ Moved up [19]: The final amendme nts to the NESHAP also include additional requirements for the contents of the periodic reports.

Deleted: facil itiesPage 66 of 5 66

malfunction P ursuant 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 malfunct ion. 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, o ur review s under CAA section s 112(d)(6) and 112(f)(2) did not result in any revision s to the standards

. 1. Standards for Glycol D ehy dration U nits In this final rule, we have established MACT standards for small glycol dehydration units in the Natural Gas Transmission Deleted: “ Deleted: ” Deleted: controlled under

Deleted: including

Deleted: includes modification

Deleted: addition of

Deleted: Our review under section 112(f)(2) did not result in revision to the standards

.

Formatted: Font color: Auto Deleted: glycol dehydration units Formatted: Underline Deleted: for the first time Deleted: “ Deleted: ”Page 67 of 566
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 x10 - 4 grams BTEX/scm

ppmv and new affected sources are required to meet a BTEX limit of 5.44 x10 - 5 grams BTEX/scm

- ppmv. 2. Notification, Recordkeeping and Reporting R equirements The final rule revise s certain recordkeeping requirements of 40 CFR part 63, subpart HHH. Specifically, facilities using carbon adsorbe rs 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 operati on ( i.e. , process equipment) or the air pollution control equipment and monitoring equipment. In conjunction with the promulgation of the MACT standards for small glycol dehydration units , the final rule requires that owners and operators of such affected units submit an initial notification within 1 year after the unit becomes subject to the provisions of this subpart or by **[INSERT DATE 1**  **YEAR AND 60 DAYS**  **AFTER DATE OF PUBLICATION IN THE FEDERAL REGISTER] ,**  whichever is later

. Deleted: ¶

Formatted: Font color: Auto Deleted: recordkeeping Formatted: Font color: Auto Deleted: reporting requirements Formatted: Underline

Deleted: or Deleted: of Deleted: in 40 CFR part 63, subpart HHH Deleted: small glycol dehydration Deleted: becoming Deleted: HHH Deleted: the date of publication of the final rule in the Federal Reg ister , Formatted: Font: Bold, No underline, Font color: Auto Deleted: . Affected sources under 40 CFR part 63, subpart HHH that plan to be area sources by the compliance dates will be required to submit a notification describing their schedule for the actions planned to achieve area source statusPage 68 of 566

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 re quired 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

m alfunction 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 t his rule is **[INSERT DATE 60 DAYS** 
**AFTER DATE OF PUBLICATION IN THE FEDERAL REGISTER]** 
. The compliance date for n ew 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, **[INSERT DATE 60 DAYS AFTER DATE OF PUBLICATION IN THE FEDERAL REGISTER]**  , whichever is later

. The compliance date for e xisting small gl ycol dehydration units that are subject to MACT for the first time ( i.e. , those Deleted: are

Deleted: of

Deleted: revisions to the MACT standards being promulgated in this action are Deleted: on

Formatted: Indent: First line: 0.5"

Deleted: and storage vesselsPage 69 of 566 that commenced construction before August 23, 2011 ) is **[INSERT**
**DATE 3**  **YEARS AND 60 DAYS**  **AFTER THE DATE OF PUBLICATION IN THE**  **FEDERAL REGISTER]**
. An affected source at a p roduction field facility that constructed before August 23, 2011, that was previously determined to be an area source but become s a major source on **[INSERT DATE 60 DAYS AFTER THE**  **DATE OF PUBLICATION IN THE FEDERAL REGISTER]**  due to the amendment to the associated equipment definition in 40 CFR part 63, subpart HH, has until **[INSERT DATE 3**  **YEARS AND**  **60 DAYS AFTER THE DATE OF PUBLICATION**  **IN THE FEDERAL REGISTER]** 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 **[INSERT**
**DATE 1**  **YEAR AND 60 DAYS**  **AFTER THE DATE OF PUBLICATION IN THE**  **FEDERAL REGISTER]**
. **VII. Summary of the Significant Changes to the NESHAP**  **s ince**  **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 Deleted: 3 years after the date of promulgation of the standards, Deleted: **THREE**

Deleted: The compliance date for n ew Deleted: sources (those that commence construction or reconstruction on or after August 23, 2011) is immediately upon initial startup or the effective date of the standards, **[INSERT DATE 60 DAYS AFTER DATE OF PUBLICATION IN THE**  **FEDERAL REGISTER]** , whichever is later

. ¶ The compliance date for Deleted: facilities Deleted: were Deleted: sources Deleted: become Deleted: sources on Formatted: Font: Not Bold, No underline, Font color: Auto Deleted: is 3 years after Deleted: promulgation of

Deleted: standards

Deleted: **THREE YEARS**Page 70 of 566

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 revisi ons 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, s ubpart 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 standard s 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). Deleted: many Deleted: and thoughtful

Formatted: Adjust space between Latin and Asian text, Adjust space between Asian text and numbers Deleted: While our

Deleted: remain the same, the Deleted: modify the

Deleted: and extend

Deleted: vessel requirements to all

Formatted: No underline, Font color: Black, Pattern: Clear (White) Deleted: tanks at major sources, while fully preserving, or improving, the public health Formatted: No underline, Font color: Black, Pattern: Clear (White) Deleted: environmental protection required by Formatted: No underline, Font color: Black, Pattern: Clear (White) Deleted:

.

Deleted: Facilities

Deleted: Small glycol dehydration unitsPage 71 of 566 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 requir ements 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 s mall 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 1.10x10 - 4 g BTEX/scm

ppmv and for new affected sources was a BTEX limit of 4.66 x10 - 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 dehydrat ion units of 3.28x10 - 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 x10 - 6 grams BTEX/scm

- ppmv. The process for developing these emissions limitations i s 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 Deleted: the

Deleted: is

Deleted: 2. Large glycol dehydration unit 0.9 Mg/yr benzene compliance alternative ¶ We hadPage 72 of 566 concerns with how we established the proposed standards for this subcategory. In response to such comments, we have re

- evaluated the propos ed MACT standards and concluded that we need (and intend to gather) additional data on these sources in order to analyze and establish MACT emission standard s for this subcategory of storage vessels under section 112(d)(2) and (3) of the C AA. See the Response to Comments document for additional discussion. 2. Changes Made to Amendments Proposed Under the Authority of
CAA S ection 112(f)(2)
We proposed to eliminate the 0.9 Mg/yr benzene compliance option for large glycol dehydration unit s 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
comment s , 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 Deleted: unit process vents. This was due to our estimate of the Maximum Individual Risk (MIR) Deleted: under Deleted: 0.9 Mg/yr benzene Deleted: to be 400

- in

- 1

- million. Our estimates of the source category maximum Deleted: have changed since proposal due to information received during the comment period. For the two facilities determined to have the highest MIRs based on
Deleted: , we found that the actual emissions used for each facility were incorrect and the multipliers used for th e allowable calculation were too high. After correcting the multipliers for each facility,Page 73 of 566

learned th at the risk assessment supporting the proposed rule erroneously included several area sources , which are not subject
to 40 CFR part 63, s ubpart 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 section s 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 40 0

- in

- 1 million 4 based on allowable emissions and 40

- in

- 1 million based on actual emissions that were estimated in the proposed rule

. As th e result of our revised risk analysis, we have determined that a pproximately 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

4 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 e missions at the 0.9 Mg/yr level, its risk would be 3

- in

- 1 million. Deleted: became 3 for the highest facility and le ss than 1 for the second highest facility

. ¶ Based on actual emissions estimates Deleted: , the estimated MIR Deleted: now Deleted: 3 Deleted: 40 Deleted: estimated in the proposed rule. We also estimate that the MIR Deleted: the MACT

Deleted: level is now 10

- in

- 1 million, compared to 400

- in

- 1 Deleted: The total Formatted: Indent: First line: 0.5"

Deleted: (0.007 excess cancer cases per year based on the lower end of the benzene URE range), Deleted: . 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. The estimatesPage 74 of 566 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 1 3 case s 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 Deleted: and

Deleted: benzene REL) are unchang ed. Facility

- wide risk estimates are also unchanged from the proposed rule

Deleted: In accordancePage 75 of 566 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. T he acute modeling scenario is worst

- case because of the confluence of peak emission rates and worst

- case dispersion conditions. Also , the genera lly 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 G as Production source category . In fact, oil and natural gas production operations contribut e 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

- widePage 76 of 566 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 w ith 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 distri bution 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. 5

5 We reach the same conclusion e ven if we do not consider the new MACT for small glycol dehydrators in our acceptability determination. Deleted: oil and natural gas production is acceptable.Page 77 of 566

In ma king 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

s tandards 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, s ubpart HH is 10

- in

- 1 million. We have not identified any emission control options that would reduce emissions and risk a ssociated with s ubpart 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 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. Deleted:

Formatted: Indent: First line: 0.5" Deleted: determining whether risk is acceptable, we considered the available health information, as described above. In this case, because the MIR is less than 100

- in

- 1

- million, and because a number of other factors indi cate relatively low risk concern (e.g., low cancer incidence, low potential for adverse environmental effects or human health multi

- pathway effects, chronic and acute noncancer health impacts unlikely), we conclude that the risk is acceptable. ¶ Although we have concluded that risks from this source category are acceptable, risk estimates for individuals in the exposed population are above 1

- in

- 1

- million. Consequently, we considered whether the MACT standards (including those promulgated today) provide an Deleted: . In this analysis, we investigated available

Deleted: that might reduce the risk associated with emissions from the source category and considered this information along with all of the health risks and other health information considered in the risk acceptability determination. ¶

... Deleted: after corrections, the MIR is 10

- in

- 1 million for the major source category. The source of the

... Deleted: would be less than 1

- in

- 1

- million . Because this unit is subject to a standard under the

... Deleted: 6 . This facility has a MIR of 10

- in

- 1 mil lion driven by

... Deleted: 7 . The estimated annual costs for this option would be $97,000. The cost effectiveness

... Deleted: concluding that the MACT standards (including those promulgated today) provide an ample

... Deleted: benzene Deleted: subpart HH amendments. Large glycol dehydration units now Deleted: option of compliance Deleted: either Deleted: emission reduction limitation or reducing actual annual benzene Deleted: to less than 0.9 Mg/yr. Deleted: 3.Page 78 of 566 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

. 8 A LDAR program equivalent to subpart VV can achieve emission reductions of approximately 39 percent with capital and annual costs of $237,700 and $ 79,419 per facility, respectively. Therefore, such a program for the 639 facilities would be expected to reduce emissions by 249 tons of HAP with to t al capital and annual costs of $ 152 million and $ 50.7 million, respectively. The cost effectiveness would be approximately $ 204 ,000 per ton of HAP. A LDAR program equivalent to 40 CFR part 60, subpart VVa can achieve emission reductions of approximately 4 3 percent overall with capital and annual costs of $241,000 and $ 82,9 00 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

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 , April 17, 2012.Page 79 of 566
$ 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 catego ry 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 determinatio n, 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 stand ards to satisfy the requirements of CAA section 112(f). 3. Changes Made to Standards Proposed Under the A ut hority of CAA Section 112(d)(6)Page 80 of 566 As discussed in detail in the preamble for the proposed rule (76 FR 52784), w e conducted a technology review for glycol dehydration units, storage vessels and equipment leaks under the authority of CAA section 112(d)(6). We assessed development s in practices, processes and control technologies sources for those regulated under the in itial 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 vess els. 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 mad e to the equipment leak standards proposed under the authority of section 112(d)(6) of the CAA. 9
4. Other Changes to the Proposed R ule
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
pass es , the prescribed manufacturers performance t est the final

9 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

. Formatted: Font color: Auto Formatted: Underline Deleted: lowering Deleted: allowance for combustion control devices that are tested under, and pass, Deleted: ,Page 81 of 566

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 t he 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
Na tural Gas Transmission and Storage (subpart HHH) source category? 1. Changes Made to Amendments Proposed Under the Authority of
CAA S ections 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

. Deleted: Consistent with the changes in Deleted: to address

Deleted: , we are removing

Deleted: from the

Deleted: No significant changes since proposal were made to the storage ves sel and equipment leak standards. ¶ Deleted: sections X .C and X. D of this preamble and

Deleted: facilities

Formatted: Font color: Auto Deleted: SmallPage 82 of 566

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 uni t

- specific BTEX emission limit of 6.42x10 - 5 grams BTEX/scm

- ppmv for existing sources and a BTEX limit of 1.10x10

- 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 x10 - 4 g BTEX/scm

- ppmv and for new affected sources is a BTEX limit of 5.44 x10 - 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. Cha nges to Amendments Proposed Under the A ut hority 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 comment s , we learned that the risk assessment supporting the proposed rule

erroneou sly included some sources that have permanently shut down, and several area sources , which are not subject to 40 CFR Deleted:

.

Deleted: the MACT standards

Deleted: existing small glycol dehydration units is

Deleted: 2. Large glycol dehydration unit 0.9 Mg/yr benzene compliance alternative ¶

Deleted: had Deleted:

. This was due to our estimate of the MIR Deleted: under Deleted: 0.9 Mg/yr benzene Deleted: be Deleted: Our estimates of the source category maximum cancer risks have changed since proposal due Deleted: information received during the comment period. We re

- examined our Deleted: determined that the two facilities Deleted: 10 that we identified as the risk drivers at proposal are Deleted: of HAP andPage 83 of 566

part 63, s ubpart 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 a pproximately 1,100 people are est imated to have cancer risks at or above 1

- in

- 1 million, compared to 2,500 people estimated in the proposed rule. Total estimated cancer incidence from the source category is 0.001 excess cancer cases
per year , or one case in every 1 , 000 years. This estimate is unchanged from the proposed rule because the incidence from a small number of sources typically does not affect total incidence reported to one significant figure. The estimate from the proposed rule of maximum chronic non

- cancer TOSHI value (0.2) is unchanged, driven by benzene emissions from fugitive

sources . The maximum acute non

- cancer hazard quotient value ( 4 , based on the benzene REL ) changed from the prop osed 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 Deleted: of this major source category that is Deleted: subject of the Deleted: )(2) review. ¶ Based on actual emissions estimates

Deleted: , the estimated MIR is now

Deleted: (5

- in

- 1 million based on the lower end of Deleted: benzene URE range), compared to Deleted: estimated in the proposed rule. We also estimate that the MIR Deleted: the MACT

Deleted: levels is now Deleted: (5

- in

- 1 million based on the lower end of the benzene URE range) compared to 90

- in

- 1 million Deleted: The total

Deleted: (0.003 excess cancer cases per year based on th e lower end of the benzene URE range), Deleted: 1000 Deleted: . Approximately 2,200 people are estimated to have cancer risks at or above 1

- in

- 1 million, compared to 2,500 people estimated in the proposed rule. The

Deleted: is now estimated to be 0.06, compared to 0.4 in the proposed rule Deleted: is now estimated to be Deleted: ( Deleted: ), compared to 5 Deleted: (also basedPage 84 of 566 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 effec ts 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 fo r 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 propo sal is the fact that the facility

- wide risk is driven by emissions Deleted: benzene REL). Facility

Deleted: estimates arePage 85 of 566 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 stora ge operations contribut e 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 da ta 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 signific ant 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 dist ribution of risks in the exposed population and the uncertainty of our risk calculations in determining whether th e risk posed by emissions from natural gas transmission and s torage is acceptable

. In this case, because the MIR is well below 100

- in

- 1

- millio n, and because a number of other factors indicate relatively low risk concern, includingPage 86 of 566 low cancer incidence, low potential for adverse environmental effects or human health multi

- pathway effects, and unlikely chronic and acute noncancer health impacts, w e 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. 11 In making our proposed ample margin of safety determination under CAA s ection 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 th e 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, whi ch is fugitive emissions. As a result, we are retaining the 0.9 Mg/yr compliance option in the final rule.

11 We reach the same conclusion e ven 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.Page 87 of 566

We have determined that the risks associated with the level of emissions allowed by the MACT standards are driven by fugitive emissions ( i.e. , leak s). 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 g as 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

. 12 A LDAR program equivalent to subpart VV can achieve emissio n reductions of approximately 51 percent with capital and annual costs of $361,800 and $142,600 p er facility, respectively. Therefore, such a program for 212 facilities would be expected to reduce emiss ions by 95.4 tons of HAP and have total capital and annual costs of $76.7 million and $30.2

12 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. Deleted: corrections to the risk assessment do not change ourPage 88 of 566 million, respectively. The cost effective ness would be
appr oximately $317 ,000 per ton of HAP. A LDAR program equivalent to 40 CFR part 60, subpart VVa can achieve emissio n 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 exp ected 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 effective ness would be approximatel y $224 ,000 per ton of HAP. These additional control requirements would reduce the MIR from the source c ategory 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,

un certainties 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 co nclude that the costs of the options analyzed are not reasonable considering the emissions reductions and risk Formatted: Indent: First line: 0.5" Deleted: judgment of risk acceptability Deleted: Although we have concluded that risks from this source category are acceptable, risk estimates for individuals in the exposed population are above 1

- in

1

- million. Consequently, we considered whether the MACT standards (including those promulgated today) pr ovide an ample margin of safety. In this analysis, we investigated available emissions control options that might reduce the risk associated with emissions from the source category and considered this information along with all of the health risks and othe r health Deleted:

. ¶ As stated above, after corrections, the MIR is 20

- in

- 1 million for the major source category. The so urce of the emissions driving this risk at this facility is fugitive emissions. As we explained in the proposal preamble, under the ample margin of safety analysis, we investigate available emissions control options that may reduce the risk associated with emissions from the source category and considered this inf ormation, along with all of the health risks and other health information considered in the risk acceptability determination. We considered requiring a LDAR program to reduce fugitive emissions, which our revised assessment identifies as the risk driver fo r this source category. Requiring an LDAR program equivalent to NSPS subpart VV would reduce emissions approximately 1 percent, which would equate to 0.2 tons Deleted: 13 . The estimated annual Deleted: for this option would be $97,000. The cost effectiv eness would be $485,000 per ton of HAP reduced. ¶ The additional LDAR program requirement would not reduce the MIR for this source category based on both actual and allowable emissions Deleted: the factors discussed above regarding acceptable risk Deleted: a LDAR program discussed above Deleted: emissionPage 89 of 566 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 A ut hority of CAA Section 112(d)(6) As discussed in detail in the preamble for the proposed rule (76 FR 52784), w e conducted a technology review for glycol dehydration units under the authority of CAA section 112(d)(6).
We did not identify development s in practices, processes and control technologies for large glycol dehyd ration 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). 14 Further discussion on our technology review analysis can be found in section X.C of this preamble, and in the Response to Comments document. 4. Other C hanges to the Proposed R ule
We are revising the emission reduction efficiency demonstration using the manufacturer ’ s performance test from

14 See footnote 6. Deleted: this work practice. As a result, we are concluding Deleted: (including those promulgated today

Deleted: (considering cost, technical feasibilit y, and other factors) Deleted: for this source category.

Deleted: Based on Formatted: Font color: Auto Deleted: above corrections and analysis, we are retaining Deleted: 0.9 Mg/yr benzene compliance option in Deleted: final subpart HHH amendments. Large Deleted: now have the option of compliance with either

Deleted: limitation or reducing actual annual benzene emissions to less than 0.9 Mg/yr. ¶ 3. Other Changes ¶ We are lowering the emission reduction allowance for combustion control devices that are tested under, and pass, Deleted: ,Page 90 of 566
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 pass es , 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 Distri ct 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 Provisi ons Deleted: , as

Deleted: Consistent with the changes in Deleted: to address

Deleted: , we are removing

Deleted: , recordkeeping

Deleted: from

Formatted: Font: Calibri, 11 pt

Deleted: startup, shutdown and malfunction (SSM). Formatted: No underline, Font color: AutoPage 91 of 566
Rule,” that the EPA promulgated under section 112 of the C AA. When incorporated into CAA s ection 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 abs ence 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 s ection IX of this preamble for the NSPS and in s ection 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, w e believe that operations and Deleted: Section

Formatted: No underline, Font color: Auto

Deleted: ,

Deleted: Section

Deleted: Section X

Deleted: WePage 92 of 566

emissions do not differ f rom 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 s ource’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 section s 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 s ection 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 s ection 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 Deleted: ,

Deleted: and 63.2 Deleted: section

Deleted: Section Deleted: the

Deleted: new source performance standards ( Deleted: ) Deleted: best system of emission reduction ( Deleted: ). Deleted: SectionPage 93 of 566

than the a verage emission limitation “achieved” by the best performing 12 percent of sources in the category. N othing in CAA section 112 directs the a gency 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 a gency to consider malfunctions as part of that analysis. CAA s ection 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 “b est 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 accou nting for the frequency, degree and duration of various malfunctions that might o ccur. As such, the performance of units that are malfunctioning is not “reasonably” foreseeable. See, e.g. , Sierra Club v . EPA , 167 F. 3d 658, 662 (D.C. Cir. 1999) (“[T]he EPA typically has wide latitude in determining the extent of data

- gathering necessar y to solve a Deleted: There is nothing

Deleted: that Deleted: Agency

Deleted: Agency

Deleted: Section

Deleted: ,

Formatted: No underline, Font color: Auto Formatted: No underline, Font color: Auto Formatted: No underline, Font color: AutoPage 94 of 566 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 . Cos tle , 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 thi rd 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 l evels that are achieved by a well

- performing

non - mal functioning source. Similarly, i n 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 Deleted: ”). See Formatted: No underline, Font color: Auto Formatted: No underline, Font color: Auto Formatted: No underline, Font color: Auto

Deleted: InPage 95 of 566

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 Exc essive 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
P roduction MACT standards ; 40 CFR 63.1271 for sources subjec t to the Natural Gas Transmission and S torage MACT standards (defining “affirmative defense” to mean, in the context of an enforcement proceeding, a response or defense put forward by a defen dant, 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 ne cessary to establish this affirmative defense; a source subject t o the Oil and Natural Gas P roduction or Natural Formatted: No underline, Font color: Auto

Deleted: Sept.

Deleted: Feb.

Formatted: No underline, Font color: Auto

Deleted: oil Deleted: natural gas production Deleted: , or Deleted: natural gas transmission Deleted: storage

Deleted: oil and natural gas production facilities or natural gas transmissionPage 96 of 566

Gas T ransmission 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 63.7 62 and a source subject to the Natural G as T ransmission and S torage NSPS must prove by a preponderance of the evidence that it h as 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 definiti on 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 G as P roduction MACT standards, 40 CFR 63.1 272 for sources subject to the Natural Gas Transmission and S torage MACT standards, and 40 CFR 60.5415 (h) for the Standards of Performance f or Crude Oil and Natur al Gas Production, Deleted: natural gas transmission Deleted: storage facilities Deleted: standards
Formatted: No underline, Font color: Auto

Deleted: an exceedance

Deleted: limit

Deleted:

Deleted: ere

Deleted: monitoring equipment,

Deleted: oil and natural gas produc tion facilities

Deleted: natural gas transmission Deleted: storage facilities Deleted:Page 97 of 566

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 expeditio usly 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 j udicial 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 assesse d in accordance with s ection 113 of the CAA ( see also 40 CFR p art 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 regulation s , 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 stan dards 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 Deleted: ,

Deleted: the applicable emission standards were being exceeded...”

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Formatted: No underline, Font color: Auto Formatted: No underline, Font color: Auto Formatted: No underline, Font color: AutoPage 98 of 566 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 enforce able 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 Ess ex Chemical v. Ruckelshaus , 486 F.2d 4 27, 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’ sta ndard 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 suppor t 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 af firmative defense, the EPA has formalized its Formatted: No underline, Font color: Auto

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Formatted: No underline, Font color: AutoPage 99 of 566 approach to upset events. In a Clean 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);

s ee , 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 I X for the NSPS , preamble section

X for the NESHAP and the Re s ponse to Comments document for both the NSPS and the NESHAP, available in the docket, for detailed discussion s regarding these changes. B. How do the NSPS and NESHAP provide for compliance assurance? The final rule includes various notification, re cordkeeping 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 Formatted: No underline, Font color: Auto

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Deleted: .C and X. D Deleted: , Deleted: Reponses Deleted: a Deleted: discussionPage 100 of 566 community and regulators. More detailed in formation on public comments received and the EPA’s responses are included in

s ection s 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 operat or 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 r ecords 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 N SPS, including gas wells, compressors, pneumat ic controllers, storage vessels and gas processing plants, must report any deviation from the NSPS requirements during the reporting period. Each annual report must includ e 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 Deleted: RTC

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Formatted: Underline Deleted: NSPS ¶ Deleted: each month a single Deleted: of all Deleted: completions for Deleted: upcoming month Deleted: No t earlier than 3 days or later than 2 days before each well completion, the owner or operator must notify the appropriate regulatory agency via e

- mail of the impending completion. Records of each well completion that document how the completion operation was conducted are retained for 5 years

.

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Deleted: and document periods of noncompliance

Deleted: ,
Deleted: reports Deleted: include certain details ofPage 101 of 566 conducted during the repo rting 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 f or 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. T he 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 record s as part of the annual report.

For centrifugal compressors with wet seal systems, the annual report must include identification of each affected facility co nstructed, 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 Deleted: . For compressors, pneumatic controllers, Deleted: storage vessels, Deleted: reports must include certain

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Deleted: facilities that werePage 102 of 566 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 Electro nic 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 manufactur er’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 Deleted: Section

Deleted: Formatted: UnderlinePage 103 of 566 malfunction or operation of the air pollution control equipment and monitoring equipment. In conjunction with the final MACT standards for small glycol deh ydration 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 **[INSERT DATE 1 YEAR AFTER DATE OF PUBLICATION IN THE FEDERAL REGISTER]**  , 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 y ear after becoming subject to subpart HHH or by **[INSERT DATE 1 YEAR AFTER DATE OF PUBLICATION IN THE FEDERAL REGISTER]**  , 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 sc hedule for carbon adsorbers, if applicable; and data related to the manufacturer’s performance tests conducted Deleted: and storage vessels that do not have the PFE in the final amendments to 40 CFR part 63, subpart HH Deleted: affected small glycol dehydration units and storage vessels

Deleted: If owners and operators of affected small glycol dehydration units and storage vessels plan to become area sources by **[INSERT DATE 3 YEARS AFTER DATE OF PUBLICATION**  **IN THE FEDERAL REGISTER]** , is required to submit in the initial notification a brief, nonbinding description of a schedule for the planned action(s) to achieve area source status.Page 104 of 566 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 p art 63, subpart HH and 40 CFR part 63, subpart HHH, in the final amendments, periodic reports are required to include periodic test results and information regarding any carbon replacement events that occurred during the reporting period. Owners and operat ors 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 emis sions 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 s ection VIII.C below

. 2. Innovative Compliance A pproaches 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 Deleted: ,

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Formatted: Font color: Auto Deleted: compliance approaches Formatted: Underline Deleted: potentialPage 105 of 566 compliance burden and enhance transparency. Specifically, we asked for suggestions on: (1) r egistration of wells and advance notification of planned completions; (2) u se 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 rece ive 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 th e response to comments . While we considered these suggestions, we did not adopt them in the final rule, for reasons explained further in the R esponses to Comments document. C. What are the requirements for submission of performance test data to the EPA? Deleted: RTC

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Deleted: RTC document. S ome of these suggestions , however, may be useful for sources to consider in complying with the ru le

.Page 106 of 566

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 tak ing 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

. Deleted: , Deleted: In conducting these required reviews, the EPA has found it ineffective and time consuming, not only for us, but also for regulatory agenci es 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 da ta 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. Deleted: In this action, as Deleted: improve Deleted: , the EPA is requiring the electronic submittal of select performance test data Deleted: production, transmission, distribution, and storage Deleted: required by the rules covered under this action to the EPA’s WebFIRE database. The WebFIRE database was constructed to sto re performance test data for use in developing emission factors. A description of the WebFIRE database is available at h ttp://cfpub.epa.gov/oarweb/index.c fm?action=fire.main

. Deleted: above Deleted: using the Deleted: The submitted report is submitted through the EPA’s Central Data Exchange (CDX) network for storage in the WebFIRE database making submittal of data very straightforward and easy. Formatted: No underline, Font color: Auto Deleted: website Formatted: No underline, Font color: Auto Deleted: The ERT contains a specific electronic data entry form for most of the commonly used the EPA reference methods. Deleted: listing Formatted: No underline, Font color: Auto Deleted: We believe that industry will benefit from this new electronic data submittal requirement. Having these data, the EPA will be able to deve lop improved emission factors, make

...Page 107 of 566

The major advantage s 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 enhanc es 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, t he 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 Moved down [20]: 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. Deleted: 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. When the EPA has performance test data in hand, there will likely be fewer or less substantial data collection requests in conjunction with prospective req uired residual risk assessments or technology reviews. This results in a reduced burden on both affected facilities (in terms of reduced manpower to respond to data collection requests) and the EPA (in terms of preparing and distributing data collection re quests and assessing the results). ¶ 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 ma king 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

... Deleted: , Deleted: , Deleted: , Deleted: , Deleted: comments concerning applicability Formatted: Font color: Auto Deleted: constitute Formatted: Font color: Auto Deleted: modification Formatted: UnderlinePage 108 of 566

**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) T here 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 opine d 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 (D.C. Cir. 2005). However, according to the commenter, the Su preme 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 Deleted: there

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Formatted: No underline, Font color: AutoPage 109 of 566 provides several catego ries 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 wit hout 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 not being “changes” is that they all contemplate that the plant will continue to be operated in a manner consistent with its ori ginal design and , thus , is not a “new” facility. We also received a number of comments objecting to consideration of recompletion activities 15 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 expe nditure” while others argue that they are maintenance activities excluded in 40

15 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 act ions 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 refrac tured. Formatted: No underline, Font color: Auto

Deleted: **Response:** CAA section 111(b) requires that the EPA establish NSPS for new sources in a listed source category. Section 111(a) defines new sources to include sources that undergo modification. As the commente r notes, 111(a)(4) defines modification to include any physical change which increase emissions. We need not address the relevance of the New York v. EPA , 413 F.3d 3, 40 (D.C. Cir. 2005) or Environmental Defense v. Duke Energy Corp. , 127 S. Ct. 1423, 1434 (2007) in this package or whether those decision compel the position we are taking with respect to recompletions. ¶ To be clear, we do not in this package question the general appropriateness of the NSPS general provisions at 40 CFR 60.14(e), including our prior identification of activities that the EPA generally does not consider to be “modification” for purposes of establishing NSPS. As the commenter notes, 60.14(e) is intended to exclude routine and minor activities , such as routine maintenance and repai r or an activity that requires insignificant expenditure. See , e.g. , 40 CFR 60.14(e)(1) and (2)

. ¶ However, as the general provisions themselves recognize, the general NSPS definition of modification may not be appropriate in all cases. Specifically, the General Provision at 40 CFR 60.14(f) allows the EPA to promulgate special provisions in any specific subpart to supersede any conflicting modification provision in 60.14(e). Well completions involving hydraulic fracturing are not the kind of minor or routine activities that the EPA had intended to exclude when it promulgated section 60.14(e), which more appropriately address the minor activities in typical stationary sources, such as a plant or a facility. ¶ As explained in the proposal, recompletion s fitPage 110 of 566

CFR 60.14 others note that we have not traditionally regulated temporary “construction” activities. 16 **Response:** In this final rule, the EPA addresses modifications in the contex t 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 c ompletions 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 modific ation 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

16 We disagree with the commenter. Fracturing and refracturing are not maintenance activit ies . On the contrary, these are essential process es that allow production of gas from shale and other formations, either during the initial development of a we ll 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.Page 111 of 566
of gas we lls 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
app ropriateness 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 emission s 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 depa rting from the General Provisions’ definition of modification. Specifically, we are providing in the final rule at 40 CFR 6 0.5365: (h) The following provisions apply to gas well facilities that are hydraulically refractured.Page 112 of 566
(1) A gas well facility that conducts a well completion operation following hydraulic refracturing is not an affected facility, provided that the requirements of § 60.5375 are met. For purposes of this provision, the dates specified in § 60.5375(a) do not apply, and such facilities , as of the effective date of this rule, must meet the requirements of
§ 60.5375(a)(1)

– (4)
. (2) A well completion operation following hydraulic refracturing at a gas well facility not conducted pursuant to § 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 completionPage 113 of 566 operation by the us e , immediately upon flowback, of emission control techniques otherwise required for new wells, as discussed more below. 17
**Cons istency w**  **ith the Definition of M odification**  This provision is consistent with the statutory definition of modification contained in CAA 111(a)(4)
. 18 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. Physical Change Uncontrolled completion following refracturing of gas wells fits well within the sta tutory 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

17 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 listi ng 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 )
.
18 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. Deleted: fracturing

Deleted: Given the significant, although short term, increase in emissions and the cost effective nature of the control on such emissions, we have concluded that coverage of refracturing activities is appropriate even if it requires departing from the General Prov ision definition of modification. We note that the EPA learned from the comment that some hydraulic fracturing operations may be excluded under 60.14(e)(2) because their expenditures do not meet the regulatory definition of “capital expenditure.” Pursuant to 60.14(f) and for the reasons descri b ed above, the EPA is adding a special provision in NSPS subpart OOOO that modification occurs when a fractured or refractured well undergoes a completion and clarifying that this specific provision supercedes any con flicting modificationPage 114 of 56 6 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 I ncrease 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 refracturin g 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 emission s that were not present priorPage 115 of 566

to such activities. Data in comments received also confirm that these uncontrolled refracturing activities result in significant VOC emissions. Our data indicate very low VOC emissions from gas wells (2.6 tpy on average) at th e 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. 19 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 immedi ately prior to the physical change. See 57 FR 32314, 32330 (Jul y 21, 1992) (explaining that , under CAA section 111(a) , an

19 One c ommenter 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, 2 005). 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 t o the change." See , also , 57 FR 32 314, 32330 (July 21, 1992) (adopting 40 CFR 60.14(h) and contrasting the provision with the pre

- existing test).Page 116 of 566 emission increase is based on current potential emissions rather than original design capacity). Accordingly, under historical regulat ions, 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 t here 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 pr oduction increases or declines. However, flowback emissions following refracturing are orders of magnitude greater than the production phase emissions. Moreover, adoption of a prior fracturing activity as the baseline for comparison here is inappropria te. 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. 20 That is, these emi ssions would not have (and could not have) occurred without the physical

20 Our data show that the magnitude of ongoing VOC emissions from a producing gas well is approximately 2.6 tp y 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.Page 117 of 566 change. Accordingly, we conclude that reliance on the prior fracturing activity as a baseline is inappropriate. 21 **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 pas t, 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 effo rt” and has been previously recognized by the United Stat es 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

21 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 wo rk practice standard. However, nothing in CAA 1 11(a)(4) and 40 CFR 60.2 requires quantification of the amount of emission increase, only that there be an increase as a r esult of the physical change. In addition , the commenter’s argument would appear to app ly equally to any time we set a work practice.Page 118 of 566

emissions fro m increasin g. 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, 54 996 (September 9, 2010) (“However, sources always have the option of adding sufficient NO x 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 ca se, 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 mod ification 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 forPage 119 of 566

new source s will not be co nsidered 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 environment al 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 physic al 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 o ccasional 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 thePage 120 of 566 physical 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, wit h 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** Alt hough 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 defi nition in order to clarify the a gency’s intent as it relates to well co mpletions. For example, we included “natural gas” in the proposed definition for “modification” in recognition that our proposed work practice requirements for well completions usePage 121 of 566 natural gas as a surrogate for VOC. We consider natural gas to be an approp riate 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 o f 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 c ommon understanding of this term and, as a result, Deleted: 60.14(e)
. WePage 122 of 566 it may be interpreted to cover more than the fracturing activities the EPA intended to cover. 22 In summary, as a result of the comments and considerations discussed above , the final rule provides that we ll 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 a ffected 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 requireme nts to avail itself of this provision. We believe this

22 We are not considering “workovers” to be modifications because: (1) T hey include truly routine activities; (2) in most instances we would anticipate only a small emissions increase, if any; and (3) we have n o 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. Formatted: Indent: First line: 0.5", Adjust space between Latin and Asian text, Adjust space between Asian text and numbers

Deleted: this change to be a l ogical outgrowth of the proposal as our description and analysis evidenced a clear intent to cover all such activitiesPage 123 of 566
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 p reamble

. 2. Regulation of M ethane and Other P ollutants
**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 (NO X ) 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 impor tant sources of NO X

or offer a l egal 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 t his rule, we are not taking final action with respect to regulation of methane. Rather, we intend to continue Formatted: Font: Calibri

Formatted: Font color: Auto Deleted: methane Formatted: Font color: Auto Deleted: other pollutants Formatted: Underline Formatted: No underline, Font color: Auto

Deleted: , Deleted: , Deleted: particulate matter Deleted: nitrogen oxides, Deleted: eight Deleted: **Response:** Section 1 11 of the CAA does not require that the EPA assess every single pollutant in a listed source category when promulgating NSPS or performing the subsequent 8

- year review. Section 111(a)(1) requires that the standard of performance reflect the application of the best system of emission reductions which, taking into consideration the cost of achieving such emission reductions, any non - air quality health and environmental impact and energy requirements, the Administrator determines has been adequately demonstrat ed. It does not require that the standard address every single pollutant. As implemented over many years by the EPA, the NSPS program has established standards that do not necessarily set emission limits for all pollutants or even all regulated pollutants emitted by sources within the relevant source category. Instead, the NSPS generally focus on specific pollutants of concern for a particular source category. For instance, the NSPS promulgated for the oil and gas category regulate VOC and SO 2 emissions at processing plants

.Page 124 of 566 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, t his program requires annual reporting of greenhouse gases ( GHG ) from large emissions sources and fuel suppliers in the United States . P etroleum and natural gas facilities will report annual methane and carbon dioxide (CO 2 ) emissions from equipment leaks and venting, and emissions of CO 2 , 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

cov er 85 percent of the total GHG emissions from the U nited
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 emi ssions from petroleum and natural gas systems and will allow petroleum and natural gas facilities to track their own emissions, compare them to similar faciliti es and aid in identifying cost

- effective opportunities to reduce emissions in the future.Page 125 of 566 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 be tter position to characterize (1) the extent of methane emissions from these sources that will remain after imposition of controls required by this rule; and (2) whether additional measures are available and appropriate for addressing such emission s . With regard to other pollutants, including PM, H 2 S and NO X , many of the sources of PM and NO X 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
approac h is consistent with what the a gency 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 NO X from sources found in this category. These engines and turbines are found in a variety of locations in this category i ncluding gathering and boosting stations, natural gas processing plants and natural gas transmission and Deleted: Secti on 111(b)(1)(B) requires that the EPA review and, “if appropriate,” revise, NSPS at least every eight years unless Deleted: Agency determines that such review is not appropriate in light of readily available information on the efficacy of the standard. Pursuant to this provision, the EPA periodically reviews and revises the standards of performance, as appropriate, to reflect improvements in methods for reducing emissions. The EPA also believes that it has discretion under section 111(b)(1)(A) to revise an NSPS to add standard s for pollutants not previously regulated for that source category. However nothing section 111(b)(1)(A) suggests that it imposes such duty on the EPA. ¶ Specifically, the definitions of “stationary source” and “modification” do not require that the EPA assess and regulate every pollutant, as the commenter contended. The definition of “stationary source,” which refers to sources that emit or may emit any pollutant, simply indicates that any source that emits a po llutant may be subject to listing under section 111. Similarly, the definition of modification, which refers to change that results in increase of the amount of any pollutant or emission of pollutant not previously emitted, simply means that such activity could trigger NSPS applicability for an existing source . Neither provision

... Deleted: for methane are the same as those for VOC, which the EPA has previously regulated and Deleted: further reduction in this NSPS review. Although the VOC requirements in this rule would also achieve Deleted: reduction in methane emissions , the EPA currently does not have sufficient information at this Deleted: to assess Deleted: would Deleted: even with the expanded VOC Deleted: and Deleted: For the reason s stated above, the EPA is continuing its assessment of methane emissions, including gathering and reviewing

... Deleted: 3. Expanded scope of the source c ategory ¶Page 126 of 566 storage facilities. In addition, some mobile source regulations (40 CFR 1039) cover nonroad engines such as those used on drilling rigs, electrical gen erators 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 NO X or PM emissions from these units. Given the broad coverage of the PM and NO X so urces 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

H 2 S, the VOC control requirements in the final rule achieve
reductions of H 2 S a co

- benefit in cases where H 2 S 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 H 2 S 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 suggestin gPage 127 of 566 other control technologies that could be applied to control H 2 S 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. Howe ver, as mentioned above, the VOC control measures provided in the final rule for well completions, storage vessels, pneumatic controllers and compressors greatly reduce any H 2 S emissions along with the VOC emissions
controlled. 3. Expanded Scope of the S ource C ategory
**Comment:** One commenter states that , i n 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 5274 5 , 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 , i n a relat ed context, the CAA requires that the E PA engage in consultation with s tate governors and air pollution control agencies, suggesting that Deleted: "[

Deleted: ." Deleted: Fed. Reg. Deleted: Aug. Deleted:

.

Deleted: StatePage 128 of 566 more than a preamble reference is needed in order to expand the category list and impose NSPS requirement s 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 N atural G as 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. 23 As we explained in the preamble to the proposed rule, when the EPA initially listed this source category, it did so in a document w here it described its listings as broad

. 76 FR at 52745. 24 Contrary to commenters assertions, the EPA has viewed this source category listing very broadly . Specifically, when promulgating the first sets of standards of performance f or this source category, we stated that the source category “encompass [es] the operations of

23 For the same r eason, 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. 24 While not required to do so, we have included the Background Information Document f or 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. Deleted: thus to Deleted: entire categories of Deleted: that had not previously been subjected to such requirements.

Deleted: As explained in the preamble to the proposed rule, the EPA believes Deleted: oil Deleted: natural gas Deleted: all

Deleted: The

Deleted: described Deleted: listed Deleted: , toPage 129 of 566 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 o il 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 O il and N atural G as 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 tha t 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 Formatted: Font color: Auto

Deleted:

. The EPA promulgated Deleted: existing NSPS (subparts KKK and LLL) “based on Deleted: Administrator’s decision that

Formatted: Font: Not Italic, No underline, Font color: Auto Formatted: Font: Not Italic, No underline, Font color: Auto Deleted: For the reasons stated Deleted: , we believe Deleted: oil Deleted: natural gas

Formatted: No underline, Font color: Auto

Formatted: No underline, Font color: Auto Formatted: No underline, Font color: AutoPage 130 of 566 original listing, we need not address what steps would be necessary were we to expand the scope of the listing. B. Major Comments C oncerning Well C ompletions 1. Applicability and E xemptions a. Well E xemptions
**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 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 Deleted: Even if the original listing was not this broad , section 111(b)(1)(A) provides the EPA authority to revise the list of categories , which we explained in the proposal we believe reasonably includes the ability to modify the scope of existing source categories

. Section 111(b)(1)(A) does not set forth criteria for the EPA’s revision to the list , thus giving the EPA broad discretion. The information that the EPA has reviewed during this rulemaking continues to support the finding that this industry causes or contributes to air pollution which may reasonably be anticipated to endanger public health or welfare. Therefore, to the extent that the original listing of t he oil and gas source category had not covered all operations in this industry, the EPA is revising the listed category to include those operations. While the commenter suggests that the EPA cannot amend a source category in a preamble , the commenter point s to no directly applicable provision demonstrating why the EPA cannot do so, and does not explain why the EPA’s interpretation is inconsistent with the plain language of the CAA
. ¶ Rather, the commenter claims that 111(f)(3)suggests that amending a 111(b) listing cannot, or should not, be done in a preamble. By its terms, 111(f)(3)does not apply here. S ection 111(f)(3) requires the EPA to consult with State Governors (1) before promulgating standards for a listed source category for which the EPA had not proposed regulations before November 15, 1990 or (2) before listing a category under section 111(f). Because the EPA listed this source category in 1979 and

... Deleted: comments concerning well completions

Formatted: Font color: Auto Deleted: exemptions

Formatted: Underline Formatted: Font color: Auto Deleted: exemptions Formatted: Underline Deleted: category Deleted: gathering Deleted: gathering Deleted: NSPS Deleted: gatheringPage 131 of 566
cost to fracture, complete and produce the well , including installing a flow line, will be incurred. If the well logs i ndicate 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 requirement s. b. Threshold for Low Pressure (Low V olume) G as Wells and Wells with Low or No VOC E missions
**Comment:** One commenter expresse s support for the REC requirements and urge s 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 imp osition 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 we llhead 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 re servoir and line pressures across the United States makes setting a specific pressure threshold difficult. Deleted: is

Deleted:

.

Formatted: Font color: Auto Deleted: low pressure (low volume) wells

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Formatted: Font color: Auto Deleted: low Formatted: Font color: Auto Deleted: no Formatted: Font color: Auto Deleted: emissions Formatted: Underline

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**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 p ressure 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 issue s 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 E PA 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. Deleted: is compri sed of

Deleted: for which the gathering line pressure at the sales meter (in psia)is greater than Deleted: 443 Deleted: psia) Deleted: 092 Deleted: plus 497 psia

Deleted: gathering

Deleted: gatheringPage 133 of 566 As noted above, a commenter recommended specific approaches to developing a pressure threshold , including s pecifying 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 thi s 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 Deleted: four

Deleted: sales

Deleted: The EPA reviewedPage 134 of 566

for wells that fall below the pressure threshold , the EPA has determined that the BSER for reducing V OC 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

. The refore, in the final rule, for non

- wildcat and

non - delineation wells with a pressure drop below th e 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 r econsidering 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. C ommenters also provide, as examples , some wells with l ow 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 Deleted: and

Deleted: flaring

Deleted: technically feasible and cost

- effective

Deleted: at or above this

Deleted: are required

Deleted: use R EC . Wells with a pressure drop below this differential are considered low pressure wells in which combustion of the flowback Deleted: is required

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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. Fo r 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 presen ted in the gas composition memo 25 available in the docket and in an article 26 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

25 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
. 26 Rice, Dudley, Composition and Origins of Coalbed Gas , U.S. Geological Survey, Denver, Colorado. Deleted: ,

Deleted: coal bed methane (CBM) wells. However, best

Deleted: data show that

Deleted: With respect to the suggestion that the EPA develop a specific threshold for Deleted: and exempt wells belowPage 136 of 566 it would be inappropriate to provide a categorical exclusion for such wells. 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

c oncentration threshold described above can be determined, to ensure compliance with the rule , an operator would have to determine with certain t y 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 Deleted: threshold , the EPA

Deleted: the information provided by commenters is not sufficient to warrant a change in the EPA’s VOC emissions estimates or to develop a Deleted: threshold. In any event

Deleted: certainly

Deleted: sales

Deleted:

.Page 137 of 566 full completion process through multiple gas composition analyses. Taking into account the variability in VOC concentrations across reservoir types, the EPA’s cost analysis illustrate s t hat 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 G as W ell
**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 havi ng 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.” Deleted: on average,

Deleted:

Deleted:

Deleted: However,

Deleted: ,Page 138 of 566 In the final rule, in response to the comments we received, the EPA has revised the definition to exclude the phrase “at the

mou th 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 tar get 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) H igh

- 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 Deleted: have modified the provisions in the final rule that require REC for all hydraulically fractured gas well completions. As discussed abouve, w e have created three subcategories of

Deleted: : (1) wildcat (Page 139 of 566 nationwide regulation. We believe the NSPS, being a national rule, should contain a single definition applicable nationwide. However, s tates 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 U nited S tates , 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 CO 2 ]. . .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 prin cipal production of which at the mouth of the well isPage 140 of 566 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 revis ion: “ 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 productio n 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. 27 As a result, the final rule will not affect drilling of oil wells. d. Availability of Infrastruc ture 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.

27 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 141 of 566

**Response:** As ex plained 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, dependi ng 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 d ue 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, Deleted: ) and Deleted: , (2) non

- wildcat and non

delineation Deleted: (see further discussion below), and (3) all other wells. For each well completion operation at category (3) non - wildcat and non - delineation wells with hydraulic fracturing begun on or after **[INSERT DATE TWO YEARS AFTER DATE OF PUBLICATI**  **ON IN THE FEDERAL REGISTER]**  , the s tandards require a reduced emission completion (REC) in Deleted: with the use of

Deleted: to control gas not suitable for entering the gathering line. For w ell completion operations at non - exploratory and non

- delineation wells with hydraulic fracturing begun prior to **[INSERT DATE TWO YEARS AFTER DATE OF**  **PUBLICATION IN THE FEDERAL REGISTER]**  , the final rule requires the control of emissions using REC orPage 142 of 566 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 CO 2 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 CO 2 for fracturing. We provided in the proposed rule, and fur ther 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 m aterial 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.Page 143 of 566 Section 60.5375(a)(3) in the final rule provides: “ y ou 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.
C ompletion combustion devices must be equipped with a reliable

con tinuous 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 CO 2 in the flowback gas has no b earing 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 E quipment
**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 Formatted: Indent: First line: 0.5"

Deleted:

.

Deleted: For category (1) wells ( exploratory and delineation wells ) and category (2) wells (low pressure wells) , the final rule contains an operational standard that requires the use of a completion combustio n device. However, the final rule does not prohibit the use of REC for completion of these wells. ¶

Formatted: Font color: Auto Deleted: should not prescribe equipment Formatted: UnderlinePage 144 of 566 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 an d 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 T rain ed P ersonnel
**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 no t readily available; they assert that Deleted: sections

Deleted: The EPA has further clarified Section 60.5375(a)(2) to include the possibility of routing recovered gas and utilizing it as a fuel source. A commen ter has suggested that the rule require a best management practice plan to determine when to implement reduced emission completions across a development area. Because completion emissions occur at the well rather than at the area level, the EPA does not be lieve that use of a BMP is appropriate.

Formatted: Font color: Auto Deleted: equipment

Formatted: Font color: Auto Deleted: trained personnel

Formatted: Underline Deleted:

Deleted: ,Page 145 of 566 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 r ule 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 Progra m 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 si gnificant 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 decrea se in the Deleted: ,

Formatted: Font: Not Bold, No underline, Font color: Auto

Deleted: and

Deleted: RECs

Deleted: ,
Deleted: RECs

Deleted: The

Deleted: will undoubtedly add

Deleted: If

Deleted: is

Deleted: Any resultingPage 146 of 566 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 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 28 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. 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 perfor m 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 .

28 Available at: http://www.epa.gov/gasstar/documents/reduced_emissions_completions.pdf

. Deleted:

.

Deleted:

. The E PA therefore belie ves that

Deleted: to

Deleted: is

Deleted: Unfortunately

Deleted: Few

Deleted: are available to quantitatively evaluate Deleted: Meanwhile, according

Deleted: RECs

Deleted: RECs Deleted: RECs Deleted: . The 12.5 RECs/year/unit is reasonably consistent wit h the commenter’s cost analysis, which assumes individual REC units are leased for one

- month periods and perform a single REC within that periodPage 147 of 566 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 re flects 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 1 1 , 3 00 REC will be required national ly 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
RE C required by state regulations. Assuming a REC unit performs 12.5 REC /year, as is asserted by the commenter, about 9 00 units would be required. This implies a current shortfall of about 6 00 units, based upon the numbers and assumptions provided by the commenter. The commenter states that industry can deliver about 50 units per quarter, Deleted: RECs

Deleted: RECs

Deleted: recompletions. As discussed more below, the EPA has reevaluated the assumption that on average each fractured gas well is re

- fractured every 10 years, which equates Deleted: approximately 10% of fractured gas wells being re

fractured each year Deleted: the NSPS

Deleted: require approximately 10,500 RECs to Deleted: annually.

Deleted: RECs

Deleted: 840

Deleted: 540Page 148 of 566

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 ad opt 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 complia nce 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 typica lly 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 Deleted: one Deleted: Deleted: Under

Deleted: 3.75

Deleted: the Deleted: 2

Deleted: one

Deleted: RECs

Deleted: current Deleted: might be

Deleted: 2.75

Deleted: An additional option to building new REC equipment to meet demand is to increase

Deleted: flow back

Deleted:

-Page 149 of 566 days, it is reasonable to conclude that each REC unit can perform more tha n 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 buildup time by about 1 quarter. As is shown in Scenarios C and G , increasing the utilization rate of REC to 1 4 to 18 REC /unit/year with industry supplying new units beginning wit h 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 11,30 1 11,30 1 11,30 1 11,30 1 11,30 1 11,30 1 11,30 1 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. **Scenario A**  **B C**  **D E**  **F G**  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 Deleted: RECs
... EC /year/unit to 14

- ... to

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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** 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

ru le 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. T his 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 th at producers will take advantage of scale economies and use REC Formatted

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... FormattedPage 151 of 566 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 NO x 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 NO x 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 Deleted: in order Deleted: , while not losing

Deleted: This

Deleted: price

Deleted: reduced emission completion technologies.Page 152 of 566 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 refractur ing , 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 sup ply 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 combustio n option they provide. 4. Cost and Emissions C alculations
**Comment:** Some commenters request the EPA to ful ly 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 , Formatted: Font color: Auto Deleted: emissions calculations

Formatted: Underline
Deleted:

Deleted: ThePage 153 of 566 based on drilling and re

- fracture records from an industry

r epresentative. 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 i nformation 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 recompletio n 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 F acility
**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 inc rease in emissions. Therefore, in the Deleted: ¶ The EPA has received data Deleted: the percent

Deleted: to be re

- fractured per year, referred to Deleted: recompletions. This new information showed Deleted: 01

Deleted: The EPA evaluated this new information against the assumptions in the proposed rule analysis, determined that this information represents best available data and concluded that the impact s analysis needed updating to more accurately reflect the number of wells recompleted in a given year. Based on Deleted: estimated the recompletion Deleted: be
Formatted: Font color: Auto Deleted: affected facility Formatted: Underline

Deleted:

.Page 154 of 566

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 C om ments Concerning Pneumatic C ontrollers 1. Definition of A ffected F acility
**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 whi ch 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

c ontroller 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 natural gas emissions. According to the commenter, a gas

- powered controller is a reliable alternative for safe plant oper ation during emergencies, and the commenter suggests that the final rule include an exception to allow gas plants to use natural gas

- driven pneumatic contr ollers for emergency plant shut down and subsequent startup. Deleted: comments concerning pneumatic controllers Formatted: Font color: Auto Deleted: affected facility Formatted: Underline

Deleted: ,

Deleted: (§

Deleted: shut downPage 155 of 566 With regard to high

- bleed pne umatic 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 whe re 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 fl ow is not sufficient for low

- bleed pneum atic 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, wil l allow for excessive emissions and is not enforce able. **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 li mited to, response time, safety and actuation of valves. These functional exemptions to the requirement address the commenters’ concerns of safety, Deleted: and

Deleted: ,

Deleted: §

Deleted: ,

Deleted: notes that Deleted: pneumatic controller standards do not apply if you demonstrate, Deleted: the Administrator’s satisfaction, that Deleted: high Deleted: controller is necessary based on operational requirements of the controller . As examples, the demonstration may Deleted: is Deleted: ,Page 156 of 566

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 isolate d 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 Deleted: , and otherwise non

- routine situations.

Deleted:

Deleted: sectorPage 157 of 566 pneumatic devices have zero emissions and , thus , should not be included in the proposed rule.
One comment er 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 d evices 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 29 to address a number of the comments described above. Specifically, for pneumatic controllers at gas processing plants where the standard is z ero bleed rate, we have defined the

29 The NSPS does not cover pneumatic controllers in the distribution segment. The EPA did not a ddress those controllers in the proposed rule. Although the EPA had proposed standards for pneumatic controllers in the transmission and storage segment , f or reasons explained in section IX . C
. 2 of this preamble, the EPA did not include such standards in th e final rule. Deleted: ,

Deleted: The Deleted: is changing Deleted: definitionPage 158 of 566 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 scf h 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 , w e 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 excl ude from the NSPS coverage owners and operators who are already using (including replacement) pneumatic controllers that meet the applicable st andards, thus, relieving them from the cost and other burdens related to compliance. Regarding the comments related to solar

- powered controllers, fuel

- cell powered controllers, mechanically

controlled devices and no - bleed devices where ver electricity is available , we considered these types of devices in the BSER analysis , as discussed in t he 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 , Deleted:

Deleted: controllers

Deleted: several issues raised by commenters, including the applicability of Deleted: applicability of Deleted: not related to control, applicability of Deleted: , and applicability of no

bleed controllers. The emission limits in the final rule would effectively eliminate the use of high

- bleed pneumatic controller s for new Deleted: and modified continuous bleed Deleted: . Also , to ease the burden on future replacement of or modification to continuous bleed controllers in natural gas service that bleed below Deleted: emissions limit , the final rule requires only that these controllers be tagged as such, so that they can be tracked separately from devices above the emission limit , which have requirements to ensure Deleted: As stated in the proposed rule’s Technical Support Document, it is assumed that a no

- bleed controller meets the definition of a low

- bleed controller for purposes of the em issions limit. The EPA also confirms that the rule requirements for pneumatic controllers list the industry sectors covered by the regulation (see §60.5430), which addresses a commenter’s request for clarification about distribution sector devices.

Deleted: effective.Page 159 of 566

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 with in 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 pla nts or upstream of processing that exceed s 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 conte nt varies widely and that , in most cases, Deleted:

Deleted: exceed

Deleted: ,Page 160 of 566 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 . Accor ding 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 th at 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 nat ural 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, m easuring the VOC content of a pneumatic controller’s bleed gas adds cost burd en to companies and , to the Deleted: coal bed methane

Deleted: VOCs

Deleted: VOCs

Formatted: Adjust space between Latin and Asian text, Adjust space between Asian text and numbers Deleted: is using

Deleted: Measuring

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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 comme nter 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 trans mission 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 qu alify as low

- bleed. This commenter further note s that bleed rates are not specified for pneumatic Deleted: In the Technical Support Document the EPA has provided cost effectiveness calculations for setting the pneumatic device emission limits. Deleted: 2. Controllers in the transmission and storage segment ¶Page 162 of 566 controllers or are inconsistently represented without distinguishing between the continuous bleed stream and the actuation stream rates within the gas consump tion specifications. **Response:** In the proposed rule, for pneumatic controllers 30 in the production segment other than gas processing plants , th e 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. 31 Owners and operators would demonstrate compliance based on information in the manufacturers’ specifications for the pneumat ic 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 manufacturer s’ 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’

30 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. 31 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.Page 163 of 566 specifica tions. 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 sugg ests 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 process ing plants) during the “adjustment period” mentioned above.
I n 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, s ubpart 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 , asPage 164 of 566 those terms are defined in subpart W, over a 3

- year period ( i.e. , 1/3 of t heir 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 d ifficulty 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 r ate. Therefore, beginning the second year, the BSER remains t he 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 natu ral gas processing plants. ForPage 165 of 566 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 c ommenters, 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 gas

- driven pneumatic controllers of different bleed

- rates without informatio n 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 comment s 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 sub ject to the pneumatic controllers NSPS in this final rule. 2. Controllers in the Transmission and Storage S egment
**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.Page 166 of 566

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 complete ly 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 adm inistrative costs in two ways: M andatory 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 a lone 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 Deleted:

.

Deleted: mandatory

Deleted: revisingPage 167 of 566 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 ou r 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, wh ile higher VOC content natural gas is used in the segments we are regulating. Also, for the reasons explained in the previous response to comment, n o VOC threshold will be included in this regulation

. 3. Cost and Emissions C alculations
**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 Formatted: Indent: First line: 0.5"

Deleted: to

Deleted: , and the EPA will collect

Deleted: under Subpart W

Deleted: greenhouse Deleted: reporting rule to inform a decision on potential future action. No

Deleted: given the arbitrary nature of defining one using availab le data Formatted: Font color: Auto Deleted: emissions calculations Formatted: UnderlinePage 168 of 566 replaced (unless an exemption is granted) once a well becomes subject to the new rule. **Response:** The commenter incorrectly claim s 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 m ethodology 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 c ontroller. 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 C ompressors 1. Compressors in the Transmission and Storage Segment Deleted: Technical Support Document

Deleted: of

Deleted: and consider Deleted: not Deleted: w ould need to be replaced. A Deleted: rate threshold of 6 scfh

Deleted: established in the rule Deleted: p roduction sector

Deleted: comments concerningPage 169 of 566

**Comment:** One commenter stated that the a gency 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 note d that s ome 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 achie ving 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 th e EPA adequately considered administrative burdens associated with reporting, recordkeeping Formatted: No underline, Font color: Auto

Formatted: No underline

Deleted: 1.Page 170 of 566 and permitting. The commenter said the trivial, incremental emissions reductions that would result from the rule failed to justify the associated complianc e costs a nd that t he 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, an other commenter said the EPA should suspend rulemaking and expand its fact

- finding to include a statistically significant sampling of affected sources

. One commenter suggest ed that the EPA exclude centrifugal compressor facilities that compress natural gas that is less than 10 percent , weight basis, VOC. The commenter stated that c ompression of gas that does not contain VOC should not be subject to standards for VOC. The commenter believes t his is consistent with equipment leak rules which do not regulate

c omponents that are not in VOC service. **Response:** The EPA agrees with the comment er that natural gas in the transmiss ion and storage segment has low

- VOC content. The EPA notes that cost and other compliance burden s are important consideration s in a rulemaking. We estimate d the VOC emissions reductions from these units located in the transmission and storage segment to b e 14.1 tpy for reciprocating compressors and 6.6 tpy for centrifugal
compressors , which is well below the level emitted by othe rPage 171 of 566

affected facilities in this se gment . 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 sou r ces, and the relatively low level of VOC emitted from these sources, we have concluded that additional evaluation of these compliance and burden issu es 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 S eals Versus W et S eals
**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 c ommenters provide information on situations where dry seal systems for centrifugal compr essors 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 Formatted: Font color: Auto Deleted: seals versus wet seals Formatted: UnderlinePage 172 of 566 some existing compressors due to housing design or operational requirements. Commen ters 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 c ontrols capable of meeting a 95

- percent VOC control efficiency or routing ca ptured 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 f uel 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.
Commenter s generally concurred that a 95

- percent reduction in emis sions 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 Deleted:

Deleted: ,

Deleted:

Deleted:

-Page 173 of 566 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 E PA 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 s eal

- oil gas to the comp ressor 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 inform ation, 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 $22,00 0. The estimated cost includes an intermediate Deleted: ,
Deleted:

Deleted: new

Deleted: , Deleted: ,Page 174 of 566 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 s egment . 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 D efinition
**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 constructio n” in the NSPS context to a rel ocated compressor, because the a gency 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. Deleted: ,

Deleted:

-
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- Deleted: 134

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**Response:** The EPA traditionally defines the term “commence

con struction ,” 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 de viation from our traditional view. Upon reviewing the comments and re

- ev a luating 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 deviatio n 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. 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 C omments C oncerning Storage V essels 1. Applicability Threshold Metric
**Comment:** Numerous commenters objected to the EPA’s proposed use of liquid throughput to determine which storage vessels Deleted: **Response:** As provided in the NSPS General Provisions at 40 CFR 60.14(e)(6), relocation of an existing affected facility is not modification. Based on information received from commenters, the EPA acknowledges that each compressor’s manufacture date can be tracked, and the EPA is revising the rule defining new source reciprocating compressors based on the equipment manufacture date. ¶

Deleted: comments concerning storage vessels

Formatted: Font color: Auto Deleted: threshold metric

Formatted: UnderlinePage 176 of 566 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 c ontrols 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 th roughputs 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, there fore, not appropriate for determining the standards’ applicability. However, the EPA has received no comment contesting the EPA’s conclusion that regulating storage vessels emitti ng 6 tpy or more of VOC is cost effective and appropriate (the basis of our p roposed throughput limit). Accordingly, in Deleted:

Deleted: **Response:** The EPA agrees with the commenters that applicability should be based on V OC emissions instead of liquid throughput and that the use of a VOC emissions threshold is more flexible approach, ensuring that controls will be required only on those storage vessels where they can be applied cost

-Page 177 of 566 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 applie d 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

em issions equal to or greater than 6 tpy or greater were cost effective to control at $3, 4 00/ton of VOC

. The final rule requires each facility to determine its own emission factor and calculate the es timated emissions from each storage vessel. 2. Definition of A ff ected F acility
**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 Deleted: tank

Deleted:

. Due to the large variability Deleted: emission factors from different shale formations Deleted: do not think it is appropriate Deleted: use an average emission factor for all tanks. Instead, the

Formatted: Font color: Auto Deleted: affected facility Formatted: Underline

Deleted: ,

Deleted: In the final rule, we have adopted aPage 178 of 566 this subpart and which units are not and describes a storage vessel using terminology similar to that used in 40 CFR 63, subpart HH. We believe it is importan t 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 standar d 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. Additiona lly , 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 , Deleted: found i n other rules, which excludes pressure vessels, as they are regulated in NESHAP subpart HH. However, we adopted several differences necessary for the oil and gas source category. First, we have chosen not to exclude all tanks permanently attached to motor vehicles. Since there are many tanks in this source category that travel from site to site, we did not feel it was appropriate to exclude all of these tanks from control requirements. Instead we have

Deleted: tank

Deleted: considered to be stationary and Deleted: Second

Deleted: tanks

Deleted: there are no separate standards Deleted: wastewater tanks in subpart OOOO, whereas other rules typically exclude them because they are regulated under different requirements. ¶ The final rule applies the storage vessel NSPS to each individual storage vessel (as opposed to a tank farm or some other collection of storage vessels) that emits Deleted: , regardless of the material that the tan k is storing or the location of the tank

. Deleted: the NSPS

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.Page 179 of 566
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” definit ion 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 whe ther 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 vehicle s” 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. Cze rniak to Ken Comey, Flint Hills Re sources L.P., September 2, 2004 )
. According to the commenter, this renders most so

called frac tanks, Baker tanks, International Organization for Deleted: tanks.

Deleted: sector

Deleted: tanks

Deleted:

Deleted: .)

Deleted: ISOPage 180 of 566

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 th e 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 defin ition 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 temporari ly, 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 vessel s are not justified for temporary

s torage vessel s . The commenter provides recommended language for the definition of “storage vessel” that addresses this and other Deleted:

. Deleted: tank

Deleted: tanks

Deleted: ,

Deleted: §

Deleted: tank

Deleted: tanks

Deleted: tanks

Deleted: tanks

Deleted: tanksPage 181 of 566 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 parti cular, 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 recei ve 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 conventio nal tank trucks that are Deleted: tanks

Deleted: NSPS applies only to stationary sources. For the reasons stated below

Deleted: cons idered stationary

Deleted: stationary

Deleted: tanks

Deleted: However, we disagree

Deleted: the mobility aspect of the storage vessel would render Deleted: not to be cost effectivePage 182 of 566 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 ins tall controls

. 3. References to MACT S tandards
**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 vessel s . 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 technique s 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 Unit ed States Court of Appeals for the District of Columbia Circuit Formatted: Font color: Auto Deleted: standards Formatted: Underline

Deleted: tanks

Deleted: Contrary to the se assertions , Deleted: proposed BSER determination Deleted: not calculated Deleted: the existing MACT standard for major source storage vesselsPage 183 of 566 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 thi s 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 E PA 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 r eduction 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 Deleted: ,
Deleted:

Deleted: Rather,

Deleted: notesPage 184 of 566

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 th at the cost of the performance tests, monitoring, recordkeeping, etc

. , that are required through cross

- references to 40 CFR 63, s ubpart HH were not adequately co nsidered by the EPA in the cost

- effectiveness determination for 40 CFR part 60, s ubpart 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 remove d 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 t he incorporation process , we made minor revisions
to the subpart HH requirements , as appropriate for subpart OOOO.
For ex ample, we removed references to glycol dehydrators and paragraphs listed as “reserved.” Deleted: considering that there are efficient and cost effective controls Deleted: Further, the determination that a 95 percent level of control is BSER for this emission source was determined prior to adopting the subpart HH requirements. The two control devices we analyzed are known to be commonly used for these emission sources in this industry. We found both to be cost effective, thus establishing 95 percent control as BSER. We note also that the ref erenced section of subpart HH (section 63.766( b) ) requires that the storage vessel be equipped with “a cover that is connected, through a closed

- vent system that meets the conditions specified in §63.771(c), to a control device or combination of control devices that meets any of the conditions specifi ed in §63.771(d).” Subsection 63.771(d) goes on to specify a wide range of control devices th at the source may use to achieve BSER (95 percent control). Other control techniques that the commenter claims are “marginally less effective” would not be BSER pr ecisely because they are less effective, regardless of the cost of those controls. We believe that the wide range of controls allowed under the proposed rule is sufficient to meet the diverse requirements of this industry. ¶ Deleted:

. Deleted: Deleted: (RTU) Deleted: RTC Deleted: decided to remove Deleted:

. Deleted: instead incorporate the appropriate Deleted: language Deleted: This Deleted: included an evaluation of whether Deleted: make sense in the context of Deleted: The requirements that we incorporated into subpart OOOO were those that Deleted: believe are necessary to assure regulatory agencies and the public that compliance with the emission limitations is achieved.Page 185 of 566 4. Availability of C ontrol E quipment
**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 th e 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. **Resp onse:**  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 vess el 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 pr ogram would require an “adjustment period” for manufacturers to be ready to supply the operators with the correct equipment they need. Formatted: Font color: Auto Deleted: control equipment

Formatted: Underline

Deleted: installation, and the number of affected oil and gas wells.

Deleted: **Response:** ThePage 186 of 566

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 performed if testing consultants are available to conduct the testing. We bel ieve 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 additi on, 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 byPage 187 of 566

the same consultant sho rtage 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 abov e. 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 provide s for a 1

- year phase

- in beginning **[INSERT DATE OF PUBLICATION IN THE**  **FEDERAL REGISTER]** 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 concent rated development areas or 90 days elsewhere in the state. The EPA believes that 60 days is a reasonable Deleted: For this reason, the EPA has decided to follow

Deleted:Page 188 of 566 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 o f 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 n o 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 o perator 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 N otification, Recordkeeping and Reporting R equirements 1. 30

- Day N otification and Annual R eports
**Comment:** Multiple commenters state that the 30

- day advance notifica tion of well completions under 40 CFR 60.5420(a) should Formatted: Indent: First line: 0" Deleted: Deleted: In addition, we note that the final rule no longer cites to the control requirements of subpart HH as discussed above

. Deleted: Regarding the number of storage vessels associated with thousands of existing oil and natural gas wells in existence , we note that the final rule app lies only to new, reconstructed and modified storage vessels emitting at least 6 tpy of VOC . In addition, our analysis shows that at the final applicability threshold of 6 tpy of VOC, the required controls are cost effective. ¶ F. Major comments concerning equipment leaks ¶ **Comment:** The EPA received varied opinions regarding use of the optical gas imaging (OGI) detection systems. Certain commenter s state that the use of optical imaging in all areas of the proposed sector rule, not just gas processing facilities, would be beneficial in reducing emissions and simplifying the LDAR program, and some of these commenters support the use of auditory, visual, and olfactory inspections , at a minimum, to minimize the fugitive emissions from equipment leaks. Some commenters assert that Method 21 and existing systems should remain the primary monitoring method for LDAR programs, though OGI and other technical advances are useful and could supplement existing programs. According to these commenters, infrared images cannot provide quantitative measur es of the amounts of leaking gas, infrared optical imaging cameras only detect extremely large leaks, and well

designed and implemented LDAR programs provide demonstrated emissions reductions. ¶ Several commenters state that implementing an OGI

- only altern ative work practice (AWP) is consistent with the monitoring requirements for the mandatory GHG reporting under 40 CFR Part 98 subpart W and using such an approach to satisfy both LDAR and

...
Formatted: Font color: Auto Deleted: day notification Formatted: Font color: Auto Deleted: annual reports

Formatted: Underline Deleted: §Page 189 of 566

be removed from the final rule. Commenters assert that this an d 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 completion s following fracturing and completions fol lowing 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 d ays 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 notificat ion 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. Deleted: §

Deleted: completion

Deleted: recompletion operations

Deleted: ,Page 190 of 566

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 commenter s add that the best method for compliance is for an owner or operator to maintain necessary records and to have t he 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 affec ted 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 c ommenter 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 requ ired if they are requested by the EPA. Deleted: ),Page 191 of 566 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 cert ain notification, recordkeeping and reporting requirements in the G eneral
P rovisions 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 a n advance notice via email to the EPA or delegated 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. Deleted: , Deleted: general provisions

Deleted: continuous bleed natural gas driven Deleted: ,
Deleted: sections Deleted: 60.7(a)( Deleted: ), Deleted: 60.7(a)( Deleted: The EPA does not believe that 30

- day notification prior to a well completion conflicts with proprietary business information. The EPA does not believe that 3 days is sufficient time for inspectors to visit and observe a well completion. To lessen the burden Deleted: the 30

- day notification requirement for Deleted: EPA wil l Deleted: require a single bulk 30

- day notification, which will include future estimated dates of well completions plus Deleted: earlier than 3 days or late Deleted: The EPA is not limiting the 30

- day bulk report to a written format. The rule language is flexible so that electronic communication

Deleted: is allowed. ¶ To lessen the reporting burden, the EPA is eliminating

Deleted: to list all affected facilities in Deleted: annual report. The EPA will revisePage 192 of 566

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 reg ulators. 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 affe cted 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. T he 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. Operator s 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 Formatted: Adjust space between Latin and Asian text, Adjust space between Asian text and numbers Deleted: rule

Deleted: require Deleted: only new or modified affected facilities

Deleted: be listed in the

Deleted: HoweverPage 193 of 566 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

certificat ion 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 an d 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 applic ations 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 availa ble to the public is a desirable goal, we did not identify any reporting programs or electronic databases that may be used for Formatted: Font: 11 pt

Deleted: ,Page 194 of 566 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 R epo rting R equirements
**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 requiremen ts 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 enfo rcement 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 requirem ents. Formatted: Font color: Auto Deleted: recordkeeping

Formatted: Font color: Auto Deleted: reporting requirements

Formatted: Underline Deleted: ,Page 195 of 566

**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, recordk eeping and reporting requirements are unduly burd ensome 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 notifica tion, 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 re moved or otherwise revised proposed reporting requirements that the EPA believes to be duplicat iv e

or unnecessary , including, but not limited to, those raised in the comments . These changes will streamline the repor ting 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 Deleted: RTC

Deleted: ,

Deleted: The EPA also agrees that

Deleted: that

Deleted: all of Deleted: ,

Deleted: and

Deleted: and

Deleted: deleted duplicate and

Deleted: reports throughout the affected subparts

Deleted: sections

Deleted: ),Page 196 of 566

revised the rule language such that only continuous bleed natural gas controllers ins talled, modified or replaced during the reporting period are reported in the annual report. In additio n, the EPA has revised the 30

- day individual notification requirement for well completions , as discussed above

. 3. Electronic R eporting of Emissions D ata
**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 commente rs 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 T oxics Release Inventory , and available to the public. These commenters believe that c ommunities 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 enforcemen t 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 reporting could be structured and implemented

. Several commenters oppose the implementation o f electronic reporting at this time and are concerned that an ERT will result Deleted: ,

Formatted: Font color: Auto Deleted: reporting Formatted: Font color: Auto Deleted: emissions data

Formatted: Underline

Deleted: the

Deleted: TRI

Deleted: thatPage 197 of 566 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 need ed 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 . T he e

- GGRT is not designed to accept all of the types of information required to be reported under the final Deleted:

.Page 198 of 566 rule, and significant modification of the system would be required t o 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 determinatio ns, 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 lo cate, 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
t est 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. D ata 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 Deleted: ,

Deleted: ,

Deleted: Electronic Reporting Tool ( Deleted: ). Deleted: Compliance and Emissions Data Reporting Interface ( Deleted: ). Deleted: Central Data Exchange ( Deleted: )Page 199 of 566 storage in the WebFIRE database mak ing 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 tes t 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 Deleted:

Deleted: 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. Moved (insertion) [20]

Deleted: ,Page 2 00 of 566 process rather than a manual data assessment making review and evaluation of the data and calcul ations 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 fo r 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
par ticular 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 N**  **ESHAP 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 C oncerning Previously Unregulated Sources Deleted:

Deleted: Major comments concerning appli cabilityPage 201 of 566

**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 v iolates 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 c ommenter opines that, absent an

up - to

- date analysis based on current emission controls, an appropriate beyond

- the

- floor determination cannot be made.Page 202 of 566

T wo 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 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 availa ble, 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 calcul ate the MACT for all sources in this se ctor 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 demonstratin g 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 Moved (insertion) [21]Page 203 of 566

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 glyc ol dehydrators, storage vessels and equ ipment 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 developmen t of the original MACT standards. 76 FR 52,768. 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 tech nological 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 redu ctions, 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 inPage 204 of 566
the legacy EPA dataset and has adva nced 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 h ow 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 progres sed 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 quest ionable 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 controll ed similar source emissions or the average of the top 12 percent of the currently best controlled sources. The commenter states that , while the Moved (insertion) [22]

Deleted: 1. P reviously unregulated sources ¶Page 205 of 566 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 section s 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) requir es 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 ‘re view, 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 co mmenter’s request that we re

calculate those standards based on current emissions data is outside the scope of this rulemaking. We did, however, conduct aPage 206 of 566 CAA section 112(d)(6) technology review for subpart HH and determined that there have been no develop ments 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 s ubpart 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 a gency used to set the proposed MACT standards for small glycol de hydrators, 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
1 12(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 inf ormation if it determines that the information it has is sufficient for it to calculate the MACT standards consistentPage 207 of 566 with the requirements of CAA section 112. Although the available emissions information is over a decade old, the available controls for re ducing 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

. 32 We , therefore , believe the data we have are still representative o f the performance of the small dehydrators. Moreover, we believe that the c ollection 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 g lycol dehydrators, w e considered using
more current available data , like the 2005 NEI, however, th e NEI dataset lacks specific information that we believe is relevant to identify ing 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

-

32 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.Page 208 of 566 controlled glycol dehydrator at a well site with high inlet HAP content may have higher HAP emissi ons 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 subca tegory. 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 previou sly unregulated sources in the oil and natural gas s ector and the commenter asserts that CAA sections 112 (c ) and 112(k) (Urban Air Toxics Strategy) support their position reg arding th e 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.
A dditionally, the commenter states that historical regulation has also not limited emissions from a number of other emission Deleted: Oil Deleted: Natural Gas Sector Deleted: 111, Deleted: ), Deleted: this

Deleted:Page 209 of 566
sources ( i.e. , wells, pneumatic devices, compressor seals, valves , or flanges or other production equipment located at oil and gas p roduction 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:** T h is rule establishes MACT standards for major sources of small glycol dehydrators that were left unregulated in the 1999 MACT rule. As explained further below, i n 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
St andards 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 Deleted: . However, the commenter believes that Deleted: has not satisfied section 112(d)(2)

- (3) of the Clean Air Act and that the EPA needs to calculate the MACT limit based Deleted: the best

- performing sources that currently exist. Additionally, according to the commenter, the EPA discovered more uncontrolled emissi on points than it is planning to control. Deleted: commenter recommends Deleted: **Respo nse:**  As the commenter notes, historical regulation of HAP emissions from the oil and gas sector has not covered all emission sources in this sector. Congress expressly limits the EPA’s authority to regulate HAP emissions from this sector. For instance,Page 210 of 566 considerations are those associated with initially establishing a MACT standard, an d 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 ag ency had proposed MACT standards under CAA section s 112(d)(2) and (3) for the subcategory of storage vessels without the PFE, we are not finalizing those standards here . Bas ed 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 st andard under CAA section s 112(d)(2) and (3) of the CAA.

T he 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 determini ng 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 Formatted: Indent: First line: 0.5", Adjust space between Asian text and numbers

Deleted: Section 112(k) (

Deleted: Urban Air Toxic Strategy) noted Deleted: is designed to address areaPage 211 of 566

source , it is not clear whether emissions from the sources identified by the commenter can be addressed by a major source
NESHAP. 33

The commenter also references CAA s ection 112(k) (and the Urban Air Toxic Strategy) . CAA section 112(k) is designed to address area source emissi ons 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 comment er 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 R eview
**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, T exas ) with a cancer MIR greater than 100

- in

- 1 million based on MACT

33 Even if the commenter were to identify an unregulated emission point under the NESHAP, it ca n always petition the a gency to revise the 1999 MACT standards

. Deleted: emissions in urban areas. Section 112(n)(4)(B) limits the EPA’s authority to list and regulate area sources under section 112(k) to only areas that meet certain population threshold and only upon making the r equisite adverse effect finding. In light of the above Deleted: and to what extent Deleted: noted in the comment ( e.g. , well completions, pneumatic controllers, or other production equipment) Deleted: effectively controlled under section 112. Deleted: However, where appropriate, the Agency continues to take actions to further reduce emissions from this sector. In this final rule, the EPA is promulgating MACT standards for major sources of glycol dehydrators and storage vessels that were left unregulated in the original NESHAP. In addition, the EPA is promulgating NSPS to address VOC emissions from emission sources noted in the comment. Control of VOC emissions from these sources will likely result in incidental HAP emission reductions as well. ¶

Deleted: comments concerning Deleted: risk review

Deleted: TX Deleted: TXPage 212 of 566

allowable emissions. The commenter notes that s ince 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 P roduction MACT source categ ory 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 c orrect, 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 co nclusion that ris ks from the Oil and Natural Gas P roduction source category are unacceptable. **Response:** We have reviewed our risk results for the Oil and Natural Gas Production source category and agree 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 cat egory 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 Deleted: Since

Deleted: ONG production

Deleted: ONG production

Deleted: . The NEI facility information for Hawkins Gas Plant was not Deleted: and the multiplier used for the allowable calculation was too high. After correcting the multiplier Deleted: MIR for this facility is 3

- in

- 1 million . For Deleted: Kathleen Tharp 2 facility, Deleted: actual emissions value was and Deleted: allowable multiplier used were too high , resulting in an incorrect MIR . After corrections were made,Page 213 of 566

sta ndards , as well as the MACT standards for small glycol dehydrators established in this final rule, we hav e determined the risks for the O il and Natural Gas P roduction 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) I t 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 Deleted: MIR for this facility is below 1

- in

- 1 million . After making these changes, and further reviewing our risk results, we

Deleted: that the highest rem aining cancer risk for ONG is 14

- in

- 1 million for a glycol dehydrator at the Vintage Deleted: facility in Ventura, CA. We find this level of risk Deleted: . We then considered whether this revised standard (existing MACT plus small dehydrator MACT) provides Deleted: Since this unit is a small dehydrator (this unit has a desig n throughput of 1 MMSCFD), it will be subject to the small dehydrator BTEX limit in the final rule. We determined the applicable BTEX limit for this unit under the final MACT provisions and determined that the resulting MIR is less than 1

- in

- 1 million . We conclude that this provides an ample margin of safety. Deleted: In addition, w e are including the 0.9 Mg/yr benzene compliance alternative in the final amendments for subpart HH. See additional discussion above in section VII.A. ¶ Deleted: it

Deleted: concludes Deleted: Deleted: of the proposed removal ofPage 214 of 566 removing the 0.9 Mg/yr benzene compliance alternative for natural gas transmission and st orage 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. R ather, 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 transmissi on 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 sma ll dehydrators is based on a 95

- percent reduction from an uncontrolled baseline level. According to the commenter, i f 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 th at 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 Deleted: is

Deleted: The

Deleted: %

Deleted:

Deleted: %

Deleted: If

Deleted: %. The

Deleted: %Page 215 of 566 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. T he 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 er rors, 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 gl ycol dehydrators in this final rule, we have determined that the risks for the Oil and Gas Transmission and S torage major source category are acceptable and that the MACT standards ( including those promulgated here ) provide an ample margin of safety. Furth er, 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 Deleted: the two facilities Deleted: 34 Deleted: identified as Deleted: drivers are area sources and not part of Deleted: that is the subject of this section 112(j)(2) review

. We are

Deleted: in the final amendments for subpart HH H . See additional discussion above in section VII.BPage 216 of 566 Mg/yr benzene compliance alternative does not reduce risks for this major s ource 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 R eview
**Comment:** One commenter states that, in conducting an 8

- year review, the EPA must “ look back” at the earlier standard and ascertain whether: ( 1) T he 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) T he 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 c alculation 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 Deleted: comments concerning the previously unregulated sources ¶ **Comment:** T wo commenters do not believe that the dataset used is representative of currently operating small glycol dehydrators. ¶ Moved up [21]: 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. Deleted: 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 pe rmit 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 t est data. The commenter believes that, by relying on an incomplete and outdated dataset to set MACT floors and limits, Formatted: Font color: Auto Deleted: EPA has ignored data demonstrating trends in practices, processes and technologies and the resulting improved performance that section 112(d) mandates. The commenter asserts that the EPA ignores the potential HAP emissions that the control devices themselv es emit by failing to collect such emissions data from facilities that have installed control devices. The commenter argues that the EPA must

... Formatted: Underline

Deleted: 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

... Moved up [22]: 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

...

Deleted: 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

... Deleted: the Deleted: thePage 217 of 566

agency; ( 3) costs or other factors have changed in a way that would s ubstantially 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 tha n 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, proces ses, 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, w e reviewed a variety of sources of data, including data obtai ned in subsequent air toxics rules to see if any practices, processes and control technologies considered in these actions could be applied to emission sources in the source categories at issue here . We also consulted the EPA ’ s R easonably Available C ontrol
T echnology (RACT)/B est A vailable Control T echnology Deleted: Deleted:

Deleted: We disagree with Deleted: commenter’s interpretation of section 112(d)(6) requirements. While we appreciate Deleted: commenter’s ideas Deleted: how Deleted: 112(d)(6) analysis

Deleted: conducted, nowhere does 112(d)(6) require any such “look back”Page 218 of 566
(BACT)/Lowest Achievable Emission R ate (LAER) Clearinghouse (RBLC)

a nd the Natural Gas STAR program. At proposal, w e 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 develop ment; 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 argum ent was posed to the District of Columbia Circuit, and the Court “[did] not think that the words ‘review, and revise as necessary’ can be const rued 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 Deleted: “look around” analysis as the commenter contends.

Formatted: Indent: First line: 0.5"

Deleted: D.C.

Deleted: that

Formatted: No underline, Font color: AutoPage 219 of 566 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 discretio n 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 Petrole um 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, Deleted: 2 . Gl ycol dehydration units and storage vessels ¶Page 220 of 566 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 t he 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 th e 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
tec h nol o gies for reducing emissions from large glycol dehydrators and storage v essels with PFE . 35 Accordingly, we are not revising these standards under CAA section 112(d)(6 ). 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

35 See footnote 25

.Page 221 of 566 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 rev ised 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 E PA’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.
On e commenter states that the EPA must examine advances in vapor recovery unit technology and reconsider floating roof Deleted: both newly controlled emission points , and the EPA must determine a proper beyond

- the

- floor MACT level forPage 222 of 566 technology for tanks containing liquids that do not have the

PFE . The commenter contends that the EPA imprope rly 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 achieve d 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 ass erting 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 decisio ns 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 Deleted: potential for flash emissions.

Deleted: **Response:** We disagree with the commenter. The EPA has determined that the technology review provisions for NESHAP under section 112(d)(6) must take into account the cost of controls. In the technology review process, we evaluated additi onal control options for storage vessels and found that none was cost effective. In addition, none of the storage vessels at the major sources used to evaluate the MACT floor used floating roofs. ¶ E. Major comments concerning notification, recordkeeping and reporting requirements ¶Page 223 of 566 were in existence and considered by the EPA at the time the EPA promulgated the original MACT standards for storage vessels. 36 37 In addition, we are not finalizing control requireme nts 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 significant ly
more cost effective. As explained in th e 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. 38

D . Major C omments Concerning Notification, Recordkeeping and Reporting R equirements 1. Annual R eports
**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

36 See footnote 25. 37 See EPA Legacy Docket A

- 94

- 04 MACT floor memos II

- A

- 006 and

- 007. 38 See footnote 25. Formatted: Font color: Auto Deleted: reports Formatted: UnderlinePage 224 of 566 final rule require the annual report to include a statement signed by a senior o fficial 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 ou tlets, 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. Th erefore, 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 ele ctronic 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 Reportin g of Emissions D ata Several commenters raised similar issues regarding reporting of emissions data under the NES HAP as under the NSPS, described supra , and our responses there apply equally here. Deleted: ,

Formatted: Font color: Auto Deleted: reporting Formatted: Font color: Auto Deleted: emissions data

Formatted: Font: Bold Deleted: **Comment:** Deleted: NESAHP Formatted: Font: Not Italic, Font color: AutoPage 225 of 566 Please see comments and responses in section IX . F .3 of this preamble

. **XI .**  **W hat are the cost, environmental**  **and econo mic 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 e mission reductions based on the control technologies selected by the engineering analysis. These emission reductions are based on the estimated population in 2015. The primary basel ine used for the impacts analysis of our NSPS for completions of hydraulically fractured natural g as Deleted: G.3

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Deleted: 1,300 tpy

Deleted: Under the final NSPS, we have estimated that the emissions reduc tions will be 290,000 tpy VOC for affected facilities subject to the NSPS. Deleted: The control strategies likely adopted to meet the final NESHAP amendments and the final NSPS will result in concurrent control of HAP, methane and VOC emissions.Page 226 of 566

wells takes into account REC conducted pursuant to state regulations covering these operations and estimates of REC performed voluntarily. To account for R EC 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 Natura l 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 volun tary 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. 39 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 )
.

39 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 g as 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 a ctivity), and the fact that REC can actually increase natural gas recovered from natural gas wells (offering a clear incentive to conti nue the practice), led the agency to conclude that it was appropriate to estimate these particular voluntary actions in the baseline for this rule.Page 227 of 566 Additionally, in the RIA, we provide summary

- level estimates of emissions reductions and engineering compliance costs fo r a case where no voluntary REC are assumed to occur. This alternative case is presented in order to show impacts i f conditions were such that REC were no longer performed on a voluntary basis, but , rather , wer e 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 alter native 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 th at 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 c ombined total about 12,000 tons , 1.0 million tons and 190,000 tons, respectively. If voluntary action is not deducted Deleted: 20,000 tpy, 1.7 million tpy, and 300,000 tpyPage 228 of 566 from the NSPS baseline, the emissions reductions achieved by the final NSPS in HAP, methane a nd VOC are estimated at 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 fra ctured 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 an d 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 reco ver hydrocarbon products, such Deleted: ,Page 229 of 566

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 sa vings of about $ 11 million (in 20 08 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 compl y 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 sour ces 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, su bpart 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 so urce category is estimated to be approximately $ 180 ,000 . These estimated annual costs include: (1) The cost of capital, (2) Deleted: 60,000

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Deleted: 360Page 230 of 566 operating and maintenance costs, (3) the cost of monitoring, inspection, recordkeeping and reporting (MIRR) and (4) any associate d 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 est imated 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 revenu es 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 Deleted: 340

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from natural gas and condensate recovery are approximately $ 180 million in 2008 dollars. Using the engineer ing cost estimates, estimated natural ga s product recovery and natural gas product price assumptions, the net annual engineering cost savings is estim ated for the final
NSPS to be about $ 1 5 million . Totals may not sum due to independen t rounding. If voluntary action is not deducted from the baseline, capital costs for the NS PS 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. A t $4.22/Mcf, the price forecast reported in the 2011 Annual Energy Outlook in 2008 dollars, the annualized cost s avings 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 Deleted: product Deleted: 350

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- $36 Deleted: , which would approximately double the estimate of net cost savings of the final NSPSPage 232 of 566 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 esti mates 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 produ ction 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

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Deleted: increase slightly (about 60 billion cubic feet or 0.3 percent) and average Deleted: to decre ase slightly ($0.05 per Mcf in 2008 dollars or 1.2 percent at the wellhead for onshore producers in the lower 48 states) for 2015, the year of analysis. This increase Deleted: production and decrease in wellhead price is largely a result of Deleted: increased natural gas and condensate recovery as a result of complying with the NSPS Deleted: ($ Deleted: in 2008 dollars Deleted: producers Deleted: ) Deleted: the year of analysis, 2015 Deleted: will decrease slightly (about 10 bcf or 0.4 percent) Deleted: significantly.Page 233 of 566

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 exis ting 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) ( PM 2.5 ) and ozone formation) and 1. 0 million tons of methane (a GHG and a precursor to global ozone formation ). These pollutants are associated with substantial health effects, welfare effects and climate effects. With the data available, we are not able to provide credible health benefit estimates for the reduction in exposure to HAP, ozone and PM 2.5 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 i ndustrial sector with the data currently available. 40 In

40 Previous studies have estimated the monetized benefits

- per - ton of reducing VOC emissions associated with t he effect that those emissions have on ambient PM 2.5 levels and the health effects associated with PM 2.5 exposure (Fann, Fulcher, and Hubbell, 2009). While these ranges of benefit

- per - ton estimates provide useful context for the break

- even analysis, the ge ographic distribution of VOC emissions from the oil and gas sector are not consistent Deleted: Total CO 2 e emissions from energy - related sources are expected to increase about 540 thousand metric tons CO 2 e or about 0.01 percent under the final NSPS, according to the NEMS analysis. This increase is attributable largely to natural gas consumption increases, although these increases are estimated to be partially offset by declines in petroleum and coal consumption. This estimate doe s not include CO 2 e reductions from the implementation of the controls; these reductions are discussed in more detail in the benefits section that follows. ¶ We did not estimate the energy economy impacts of the final NESHAP amendments using NEMS, as the exp ected costs of the rule are not likely to have estimable impacts on the national energy economy. ¶ Deleted: 20 Deleted: 300 Formatted: No underline, Font color: Auto, Subscript Deleted: 7

Deleted: PM (2.5 microns and less) (

Formatted: No underline, Font color: Auto, Subscript Deleted: )Page 234 of 566 addition to health improvements, there will be improvements in visibility effects, ecosystem effects and climate effects, as well as additional product recovery. Although we do not have sufficient information or modeling available to provide quantitative estimates for this rulemaking, we include a qualitative assessment of the health effects associated with exposure to HAP, ozone and PM 2.5 in the RIA for this rule. These qualitative effects are brie fly 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 PM 2.5 and ozone formation. As documented in previous analyses (U.S. EPA, 2006 41 and U.S. EPA, 2010 42 ), exposure to PM 2.5 and ozone is associated with significant public

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 V OC emissions across all sectors. Coupled with the larger uncertainties about the relationship between VOC emissions and PM 2.5 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.

41 U.S. EPA. RIA. National Ambient Air Quality Standards for Particulate Matter , Chapter 5. Office of Air Quality Planning and Standards, Research Triangle Park, NC. October 2006. Available on the Internet at <http://www.epa.gov/ttn/ecas/regdata/RIAs/Chapter%205

-- Benefits.pdf>.

42 U.S. EPA. RIA. National Ambient Air Quality Standards for Ozone . Office of Air Qu ality 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>. Formatted: No underline, Font color: Auto, Subscript

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health effects. PM 2.5 is associated with health effects, including premature morta lity 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 respira tory symptoms, as well as visibility impairment. 43 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. 44 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. Accordin g to the

43 U.S. EPA. Integrated Science Assessment for Particulate Matter (Final Report) . EPA

- 600

- R

- 08

- 139F. National Center for Environmental Assessment

— RTP Division. December 2009. Available at <http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=216546>.

44 U.S. EPA. Air Quality Criteria for Ozone and Related Photochemical Oxidants ( Final) . EPA/600/R

- 05/004aF

- cF. Washington, DC: U.S. EPA. February 2006. Available on the Internet at http://cfpub.epa.gov/ncea/CFM/recordisplay.cfm?deid=149923. Formatted: Font: 10 pt Formatted: Font: 10 pt, Not Superscript/ Subscript

Formatted: Font: 10 pt Formatted: Font: 10 pt, Not Superscript/ SubscriptPage 236 of 566 Intergovernmental Panel on Climate Change (IPCC) 4 th 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 tota l methane emissions from all sources and account for about 5 percent of all CO2 e emissions in the United States, with natural gas systems being the single largest contributor to United States anthropogenic methane emissions. 45 Methane, in addition to other GHG emissions, contributes to warming of the atmosphere, which, over time, leads to increased air and ocean temperatures, changes in precipitation patterns, melting and thawing of global glaciers and ice, increasingly severe weather events, such as hurricanes of greater intensity and sea level rise, among other impacts. This rulemaking requires emission control technologies and regulatory alternatives that will significantly decrease HAP and VOC emissions from the oil and na tural 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 emi ssions annually by about 1. 0 million short tons or about 19 million metric tons

45 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. Deleted: 7 Deleted: 33

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CO 2 e. After considering the secondary impacts of this rule as previously discussed, such as increased CO 2 emissions from well completion combustion and decreased CO 2 e emissi ons because of fuel

- switching by consumers, the methane reductions become about 18 million metric tons CO 2 e. 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 CO 2 e when petroleum refineries and petroleum transportation are excluded because these sources are no t 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 cl imate benefits of taking approximately 4 million typical passenger cars off the road or eliminating electricity use from about 2 million typical homes each year. 46 The EPA recognizes that the methane reductions from this rule will provide for significan t 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

46 U.S. EPA. Greenhouse Gas Equivalency Calculator available at: http://www.epa.gov/cleanenergy/energy

- resources/calculator.html , accessed 0 4 / 09 /12. Deleted: 31

Deleted: 13

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Deleted: Formatted: Font color: Black Deleted: 02/13 Formatted: Font color: BlackPage 238 of 566 of direct model estimates from the interagen cy 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 CO 2 equivalents using the GWP of methane, then multiplied these CO 2 equiv alent 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 CO 2 emissions in a given year (or from the alternative perspective, the benefit to society of reducing CO 2 emissions by 1 ton). For more information about the social cost of carbon, see the Support Document: Social Cost of Carbon for Regulatory Impact Analysi s Under Executive Order 12866

. 47 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 mea n social cost of carbon at the 3

- percent discount rate results in an estimate of about $ 44 0 million in 2015. 48

47 Interagency Working Group on Social Cost of Carbon (IWGSC). 2010. Technical Support Document: Social Cost of Carbon for Regulatory Impact Analysis Under Executive Order 12866 . Docket ID EPA

- HQ

- OAR

2009

- 0472

- 114577. http://www.epa.gov/otaq/climate/regulations/scc

tsd.pdf , accessed 02/12/12. 48 The ratio of domestic to global benefits of emission reductions varies with key parameter assumptions. See Interagency Working Group Formatted: No underline, Font color: Auto, Subscript

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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 ar e 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 relativ e to CO 2 (about 12 years compared to CO 2 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 lifet imes 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 b enefits 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

on Social Cost of Carbon. 2010. Technical Support Document: Social Cost of Carbon for Regulatory Impact Analysis Under Executive Order 12866
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benefits of methane reductions in most cases. 49 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 th e 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 fro m the IPCC Second Assessment Report , and with the US GHG Reporting program

. See the Regulatory Impact Analysis for further details. 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 unti l the Interagency Social Cost of Carbon Work Group develops values for non

- CO 2 GHG.

49 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. Deleted: proposal

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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 t otal 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 t o 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 method ology from Fann, Fulcher, and Hubbell (2009), 50 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 PM 2.5 precursor, but emission reductions in s pecific areas are valued from $280 to $7,000 per ton in 2008 dollars. As a result, even if VOC emissions from oil

50 Fann, N., C.M. Fulcher, B.J. Hubbell. The influence of location, source, and emission type in estimates of the human heal th benefits of reducing a ton of air pollution . Air Qual Atmos Health (2009) 2:169

- 176. Deleted: 14,000

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Formatted: No underline, Font color: Auto, SubscriptPage 242 of 56 6 and natural gas operations result in monetized benefits that are substantially below the national average, there is a reasonable chance that t he 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.
**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 i s 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) f or 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 R IA 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. Deleted: ¶

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Table 7 shows the results of the cost and benefits analysis for these final rules.
TABLE 7 . SUMMARY OF THE M ONETIZED 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 Final NESHAP**  **Amendments Final NSPS and**  **NESHAP 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 methane 420 tons of methane 1.0 million tons of 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 Deleted: 3

Deleted: 3 Deleted: , Moved up [1]: AND NET BENEFITS FOR THE FINAL OIL AND NATURAL GAS NSPS AND NESHAP AMENDMENTS IN 2015 (MILLIONS OF 2008$) 1 ¶ ¶

Formatted Table Formatted: Centered Deleted: Total Costs 3

...

Formatted Table Deleted: Non

- monetized Benefits 4

...

Deleted: ,Page 244 of 566 imply that there are no benefits or co - benefits of the ru les; 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 n egative 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, PM 2.5 and ozone exposure, visibility a nd 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 (CO 2 ), 5 50 tons of nitrogen oxides ( NO x ) , 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 m inor secondary disbenefits , but the EPA was unable to estimate these secondary disbenefits . The net CO 2 - 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 has 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 Moved up [2]: ¶ 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. Formatted: Font: 10 pt

Formatted: Font: 10 pt, No underline, Font color: Auto Deleted: ¶

Formatted: No underline, Font color: Auto, Superscript Formatted: No underline, Font color: Auto, Subscript Deleted: ¶ 5 Formatted: No underline, Font color: Auto, Not Superscript/ Subscript Formatted: No underline, Font color: Black Deleted: these Formatted: No underline, Font color: Black Deleted: rules Formatted: No underline, Font color: Black Formatted: No underline, Font color: Auto, Subscript Deleted: 90,000 Deleted: for the NESHAP and 31 million metric tons for the NSPS. Deleted: PRA
Deleted: ICR document s prepared by the EPA has been assigned EPA ICR number s 2437.01, 2438.01, 2439.01, and 2440.01

Deleted: information collection requirements are not enforceable until OMB approves them.

Deleted: ,Page 245 of 566
all ope rators 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 t hose 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 satis fied. 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 caus ed by poor maintenance and / or careless operation) and where the source took necessary actions to minimize emissions. In addition, the source must meet Deleted:Page 246 of 566 certain notification and reporting requirements. For example, the source must prepare a written root cau se 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. T o 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 estim ate 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 adv antage of the affirmative defense. Deleted: ,

Deleted: ,Page 247 of 566 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 circu mstances 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 im portant to note that the 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 malf unction (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 expecte d 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 Deleted: and onePage 248 of 566

of three such occurrences for all source s 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 r evise 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** Deleted: occurrence

Deleted: record

- keeping

Deleted: 2.4

Deleted: 61,249

Deleted: 2.1

Deleted: 22

Deleted: 08

Deleted: ,

Deleted:

Formatted: Indent: First line: 0"

Deleted: ICRs

Formatted: Font: Bold, No underline, Font color: AutoPage 249 of 566 **Register** to display the OMB control numbers for the approved information collection requirements co ntained 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 certif ies 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 t his 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 tran sport 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 enterpr ise 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 Deleted: as Amended by the Small Business Regulatory Enforcement Fairness Act (RFA) of 1996 (SBREFA), 5 U.S.C. 601 et seq.Page 250 of 566 comparing compliance costs to entity revenues. The baseline us ed 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 usi ng 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 r eductions 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 Deleted: 120

Deleted: 94Page 251 of 566
revenues. Meanwhile, four firms ( 3 percent) are likely to have impacts greater than 1 percent. Three of these four firms are likel y 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 a mendments , 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 sm all 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) Deleted: seven Deleted: 6 Deleted: seven

Deleted: Amendments Deleted: 54 Deleted: 108 Deleted: 50

Deleted: 45 of the 54 (83 percent) are likely to have impacts of less than 1 percent in terms of the ratio of annualized compliance costs to revenues. Meanwhile, nine firms (17 percent) are likely to have impacts greater than 1 percent. Three of these nine firms are likely to have impacts greater than 3 percent. While these nine firms might receive significant impacts from the final NESHAP amendments, they represent a very small slice of the oil and gas industry in its entirety, less than 0.2 percent o f the estimated 6,427 small firms in NAICS 211. Deleted: SISNOSE.

Deleted: 153 Deleted: 169 Deleted: 91Page 252 of 566 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 on well

related compliance costs to be significantly miti gated. 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 l ong 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

. Deleted: 16 Deleted: 9 Deleted: Six Deleted: 16

Deleted: 160

Deleted: 95 percent) in the sample are likely to have impacts of less than 1 percent. Nine firms (5 Deleted: , while only three of these nine are likely to have impacts greater than 3 percent

Deleted: and recompletionsPage 253 of 566 Although this final rule wil l 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 of 1995

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 gove rnments 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 Deleted: Our current baseline for the impact s analysis of our NSPS for gas well completions takes into account reduced emission completions conducted pursuant to state regulations covering these operations. However, based on public comments and reports to the EPA's Natural Gas Star program, the EPA acknowledges that some producers conduct well completions using REC techniques voluntarily. However, the EPA normally does not account for voluntary actions in baseline emissions estimates when we analyze potential impacts of our regulatory actions, since there is no assurance that such voluntary emission reduction measures will continue in the future. As such, emissions reductions obtained from RECs implemented voluntarily are not reflected in our baseline emissions estimates. ¶ Formatted: Adjust space between Latin and Asian text, Adjust space between Asian text and numbers, Tab stops: Not at 0" + 0.5" + 1" + 1.5" + 2" + 2.5" + 3" + 3.5" + 4" + 4.5" + 5" + 5.5" + 6" + 6.5"

Formatted: Indent: First line: 0", Tab stops: Not at 0" + 0.5" + 1" + 1.5" + 2" + 2.5" + 3" + 3.5" + 4" + 4.5" + 5" + 5.5" + 6"Page 254 of 566 on the distribution of power and responsibilities among the various levels of government, as speci fied 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 per mitting burden borne by the States. These provisions will result in fewer sources becoming affected facilities under the NSPS while achieving emission reductions beginning **[INSERT DATE 60 DAYS AFTER THE DATE OF PUBLICATION IN**  **THE FEDERAL REGISTER]** 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 (6 5 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 dire ct compliance costs incurred by tribal governments, or the EPA consults with tribal officials early in the process of Deleted: Thus, Executive Order 13132 does not apply to this action

.Page 255 of 566 developing the proposed regulation and develops a tribal summary impact statement. The EPA has concluded that this action will not have t ribal 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 m eetings 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 Trib al 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 cal l 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. Deleted: consulted

Deleted: Outreach was

Deleted: An outreach and

Deleted:

Deleted: All these tr ibes counted this as information only, not consultation. There were no issues raised during this call. The tribes were listening to the presentation and the call was ended without comment.Page 256 of 566 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 do cket.
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 disp roportionate 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 existi ng 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 Deleted: the n

Deleted:

Deleted:

Deleted:

Deleted: As required by section 7(a), the EPA’s Tribal Consultation Official has certified that the requirements of the Executive Order have been met in a meaningful and timely manner. A copy of the certification is included in the docket for this action. ¶Page 257 of 566

This action is not a “significant energy action” as defined in Execu tive 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 t he 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 su ch, 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 the se determination s 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 lar ge 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. Deleted: ( Deleted: ) ),

Deleted: ¶

Deleted: The basis for the determination is as follows. Deleted: We use the NEMS to estimate the impacts of the final NSPS on the United States energ y system. The NEMS is a publically available model of the United States energy economy developed and maintained by the Energy Information Administration of the U.S. DOE and is used to produce the Annual Energy Outlook, a reference publication that provides detailed forecasts of the United States energy economy. ¶

Deleted:

Deleted: NSPS.Page 258 of 566 We use the NEMS to estimate the impacts of the combined final rules on the United States energy system. The NEMS is a publically available model of the United States energy economy developed and maintained by the Energy Information Administration of the DOE and is used to produce the Annual Energy Outlook, a reference publication that provides det ailed forecasts of the United States energy economy.

B ased on public comments and reports to EPA's Natural Gas
S TAR 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 accoun t for REC performed in regulated states, the EPA subsumed emissions reductions and compliance costs in states where these

com pletion

- 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 f or economic and/or environmental objectives as a normal part of business. To account for emissions reductions and Deleted: The analysis

Deleted: impacts f or

Deleted: that includes the additional product recoveryPage 259 of 566 costs arising from voluntary implementation of pollution controls , the EPA used information on total emission reductions reported to the EPA b y 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 doc ket, 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 fin al 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 produ ction 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 se veral 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, Deleted: estimated to increase (about 60 billion cubic feet or 0.3 percent) and natural gas prices to decrease ($0.05/Mcf or 1.2 percent at the wellhead for producers in the lower 48 states) Deleted: of analysis Deleted: estimated

Deleted: ($

Deleted: less than Deleted: producers Deleted: ) in 2015, the year of analysis.Page 260 of 566 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 NTTAA of 1995, Public Law 104

– 113, 12(d) (15 U.S.C. 272 note) directs the EPA to use VCS in its regulatory activities unless to do so would be inconsistent with applicable law or ot herwise impractical. Voluntary consensus standards are technical standards ( e.g . , materials specifications, test methods, sampling procedures, and business practices) that are developed or adopted by VCS bodies. The NTTAA directs the EPA to provide Congress, through OMB, explanations when the EPA decides not to use available and applicable VCS. This final action does not involve technical standards. Therefore, the EPA is not considering the use of any 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

. Formatted: Font: Not Italic, Font color: AutoPage 261 of 566 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
Stat es. 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 popul ations without having any disproportionately high and adverse 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 aver ages. The development of demographic analyses to inform the consideration of environmental justice issues in the EPA rulemakings is an evolving science. Deleted: EJPage 262 of 566 The EPA conducted a demographic analysis, focusing on populations within 50 km of any facility in eac h 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 docume nted 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 assessment s 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 ar e 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. Deleted: noncancerPage 263 of 566 To promote meaningful involvement, the EPA conducted three public hearings on the proposal. The hear ings were held in Pittsburgh, Pennsylvania, o n September 27, 2011, Denver, Colorado, on September 28, 2011 , and Arlington, Texas, on September 29, 2011. A total of 261 people spoke at the t hree 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 offici als.
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 bef ore a rule may take effect, the ag ency 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 re port containing this final rule and ot her required information to the United S tates Senate, the United
States Ho use of Representatives, and the Co mptroller General of the United States pr ior to publication of the final rule in the **Federal Register** . A major rule c annot 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 Deleted: PA

Deleted: CO Deleted: TX

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be effective on **[INSERT DATE 60 DAYS AFTER THE DATE OF PUBLICATION IN THE FEDERAL REGISTER]**  **. Oil and Natural Gas Sector: New Source Performance Standards and**  **National Emission Standards for Hazardous Air Pollutants Reviews**  **— page**  Page **265** of **566 List of**  **Subjects in 40 CFR Part 60** Environmental protection, Air pollution control, Reporting and recordkeeping requirements, Volatile organic compounds. **List of Subjects in 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:

____________________________ Lisa P. Jackson, Administrator. Deleted: ¶ Section Break (Next Page) **Oil and Natural Gas Sector: New Source Performance Standards and**  **National Emission Standards for Hazardous Air Pollutants Reviews**  **¶ ¶** Page **266** of **566** For the reasons set out in the preamble, title 40, chapter I of the Co de of Federal Regulations is amended as follows: PART 60

— [AMENDED] 1. The authority citation for part 60 continues to read as follows: Authority: 42 U.S.C. 7401, et seq . 2. Section 60.17 is amended by: a. Revising paragraph (a)(7); and b. Revising paragraphs (a)(91) and (a)(92) to read as follows: § 60.17 Incorporations by reference.
* * * * * (a) * * * (7) ASTM D86

– 78, 82, 90, 93, 95, 96, Distillation of Petroleum Products, IBR approved for §§ 60.562

– 2(d), 60.593(d), 60.593a(d), 60.633(h) and 60. 5401(h).
* * * * * (91) ASTM E169

– 63, 77, 93, General Techniques of Ultraviolet Quantitative Analysis, IBR approved for §§ 60.485a(d)(1), 60.593(b)(2), 60.593a(b)(2), 60.632(f) and 60.5400(f). (92) ASTM E260

– 73, 91, 96, General Gas Chromatography Procedu res, IBR approved for §§ 60.485a(d)(1), 60.593(b)(2), 60.593a(b)(2), 60.632(f), 60.5400(f) and 60.5406(b). Deleted: ¶ Formatted: Line spacing: single Formatted: Different first page headerPage 267 of 566

* * * * * Subpart KKK

— Standards of Performance for Equipment Leaks of VOC From Onshore Natural Gas Processing Plants for Which Construction, Reconstr uction, or Modification Commenced After January 20, 1984, and on or Before August 23, 2011 3. The heading for Subpart KKK is revised to read as set out above. 4. Section 60.630 is amended by revising paragraph (b) to read as follows: § 60.630 Applicabili ty 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 requi rements of this subpart.
* * * * * Subpart LLL

— Standards of Performance for SO 2 Emissions From Onshore Natural Gas Processing for Which Construction, Reconstruction, or Modification Commenced After January 20, 1984, and on or Before August 23, 2011

5. The heading for Subpart LLL is revised to read as set out above. 6. Section 60.640 is amended by revising paragraph (d) to read as follows: § 60.640 Applicability and designation of affected facilities.
* * * * *Page 268 of 566 (d) The provisions of this subpart apply to each affected facility identified in paragraph (a) of this section which commences construction or modification after January 20, 1984, and on or before August 23, 2011.
* * * * * 7. Add subpart OOOO to part 60 to read as follows:

**Subpart OOOO —**  **Standar ds of Performance for Crude Oil and Natur**  **al 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 contro ller 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 unit s 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 operatio ns from my sweetening unit affected facilities at onshore natural gas processing plants? Deleted: **,**

Deleted: VOC

Deleted: VOCPage 269 of 566

60.5408 What is an o ptional 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 affec ted 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 s ystems ? 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 pl ants? 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 f or 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? Deleted: demonstrate compliance atPage 270 of 566

60.5423 What additional recordkeeping and reporting requiremen ts apply to my sweetening unit affected facilities at onshore natural gas processing plants? 60.5425 What part s 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 Ini tial SO 2 Emission Reduction Efficiency (Z i ) Table 2 to Subpart OOOO of part 60

– Required Minimum SO 2 Emission Reduction Efficiency (Z c ) Table 3 to Subpart OOOO of part 60

– Applicability of General Provisions to Subpart OOOO

**Subpart OOOO —**  **Standards of Performance for Crude Oil and Natur**  **al Gas Production, Transmission**  **and Distribution §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)

an d sulfur dioxide (SO 2 ) emissions from affected facilities that

commence construction, modification or reconstruction after August 23, 2011. **§60.5365 Am I subject to this subpart?** You are subject to the applicable provisions of this subpart i f 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 Formatted: No underline, Font color: Auto, Subscript Formatted: No underline, Font color: Auto, Subscript

Deleted: **,**

Deleted: onshore

Deleted: commenced

Deleted: If

Deleted: that commenced

Deleted: , Deleted: your af fected facility is subject to the applicable provisions of this subpart. Deleted: A

Deleted: A

Deleted: defined asPage 271 of 566 between the wellhead and the point of custody transfer to the natural gas transmission and storage segment. For the purposes of this subpart, your centrifugal compressor is considered to have commenced construction on the date the compressor is installed (excluding relocation) at the facility. 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. For the purposes of this subpart, your reciprocating compressor is considered to have commenced construction on the date the compressor is installed (excluding relocation) at the facility. 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) (i) 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 which commenced construction after August 23, 2011, and is located between the wellhead and the poin t of custody transfer Deleted: a

Deleted: facility, except that a centrifugal compressor located at a well site (as defined in §60.543 0) is not an affected facility under this subpart. Deleted: of original manufacture.

Deleted: A

Deleted: defined as

Deleted: a

Deleted: facility, except that a reciprocating compressor located at a well site (as defined in §60.5430) is not an affect ed facility under this subpart. Deleted: of original manufacture.

Deleted: A

Deleted: defined as Deleted: Deleted: that vents continuously (bleeds) to the atmospherePage 272 of 566

to the natural gas transmission and storage segment and not located ata natural gas processing plant

. (ii) Each pneumatic controller affected facility, which is a single continuous bleed natural gas

- driven pneumatic controller which commenced construction after August 23, 2011, and is located at a natural gas processing plant. (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 §§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. Equ ipment not located at the onshore natural gas processing plant site is exempt from the provisions of Deleted: a Deleted: facility.

Deleted: A Deleted: defined as Deleted:

. ¶

(f) Compressors and equipment (as d efined Deleted: §60.5430) located at onshore Deleted: plants. ¶

(1) Each compressor in VOC service Deleted: in wet gas service is an affected facility Deleted: 2

Deleted: 3 Deleted: , as defined in §60.5430,

Deleted: 4 Deleted: (as defined in §60.5430) Deleted: tank

Deleted: (as defined in §60.5430)Page 273 of 566

§§ 60.5400, 60.5401, 60.5402, 60.5421 and 60.5422 of this subpart. ( 3 ) The equipment within a process unit o f an a ffected facilit y 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 un it 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 (H 2 S) in the acid gas (expressed as sulfur) are required to compl y with recordkeeping and reporting requirements specified in §60.5423(c) but are not required to comply with §§60.5405 through 60.5407 and paragraphs 60.5410(g) and 60.5415(g) of this subpart. (4) Sweetening facilities producing acid gas that is completel y reinjected into oil

- or - gas - bearing geologic strata or that is otherwise not released to the atmosphere are not subject Formatted: Font: Not Bold, No underline, Font color: Auto

Deleted: 5) Affected facilities

Deleted: paragraphs Deleted: )(1) and (f)(2

Formatted: No underline, Font color: Auto, SubscriptPage 274 of 566
to §§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 § 60.5375 are met.
For purposes of this provision , the dates specified in
§ 60.5375(a) do not apply, and such facilities , as of the effective date of this rule, must meet the requirements of
§ 60.5375(a)(1)

– (4)
. (2) A well completion operation following hydraulic refracturing at a gas well facility not conducted pursuant to
§ 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. **§60.5370 When must I comply with this subpart?** (a) You must be in compliance with the standards of this subpart no later than **[INSERT DATE 60 DAYS AFTER DATE OF**  Deleted: and §§

Deleted: §

Deleted: For

Formatted: No underline, Font color: Black

Deleted: subpart Deleted: operations Deleted: paragraphs (h)(1) through (h)(4) Deleted: section are modifications, but do

Formatted: Indent: First line: 0.5", Don't adjust space between Latin and Asian text, Don't adjust space between Asian text and numbers Deleted: (1) A well completion operation following hydraulic fracturing or refracturing at a gas well facility that commenced construction, modification, or reconstruction on or before August 23, 2011. ¶

(2) A well completion operation following hydraulic fracturing or refracturing at a gas well facility that commenced construction, modification, or reconstruction after August 23, 2011. ¶

(3) A well recompletion operation that occurs after August 23, 2011 at a fractured or refractured gas well facility. ¶

(4) A refracturing operation that occurs after August 23, 2011 at a gas well facility. ¶ Formatted: Don't adjust space between Latin and Asian text, Don't adjust space between Asian text and numbersPage 275 of 566
**PUBLICATION IN THE FEDERAL REGISTER]** or upon startup, whichever is later. (b) The provisions for exemption from compliance during periods of startup, shutdown and malfunctions provided for in 40 CFR 60.8(c) do not apply to this subpart. (c) You are exempt from the obligation to obtain a permit under 40 CFR part 70 or 40 CFR part 71, provided you are not otherwise required by law to obtain a permit under 40 CFR 70.3(a) or 40 CFR 71.3(a). Notwithstanding the previous sentence, you must continue to comp ly with the provisions of this subpart. **§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 paragraph s (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. F or each new well completion operation with hydraulic fracturing begun on or after Deleted: ,

Deleted: g

Deleted: , as defined in §60.5430,

Deleted: **[INSERT DATE TWO YEAR S**  **AFTER DATE OF PUBLICATION IN THE FEDERAL**  **REGISTER]** , Deleted: paragraph

Deleted:

.Page 276 of 566
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
mater ial 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 practicable. (3) 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 completio n 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. Deleted: **[INSERT DATE TWO YEAR S**  **AFTER DATE OF PUBLICATION IN THE FEDERAL**  **REGISTER]** , Deleted: a)(3

Deleted: and route the recovered gas into a gas gathering line or collection system

Deleted: gathering

Deleted: gathering

Deleted: flaringPage 277 of 566 (4) You have a general duty to safely maximize resource

rec overy 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 th e well completion operation and must contain the records specified in §60.5420(c)(1)(iii). (c) You must demonstrate initial compliance with the standards that apply to gas well affected facilities as required by §60.5410. (d) You must demonstrate continuous compliance with the standards that apply to gas well affected facilities as required by §60.5415. (e) You must perform the required notification, recordkeeping and reporting as required by §60.5420. (f) (1) For each gas well affected facility specified in paragraphs (f)(1)(A) and ( B ) of this section, you must comply with the requirements of paragraphs (f)(2) and (3) of this section. (A) Each well completion operation with hydraulic fracturin g at a gas well affected facility meeting the criteria for a wildcat or delineation well

. Deleted: ,
Deleted: (f) (1) For each

Deleted: , you must comply with the requirements of paragraph s (a)(3) and (b)

- (e) of this section.Page 278 of 566
( B) E ach 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 waterw ays. 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 mainta in records specified in §60.5420(c)(1)(iii) for wildcat , delineation and low pressure
gas wells. **§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. Deleted: 2) For each

Deleted: non - wildcat Deleted: low pressure Deleted: , you

Deleted: the requirements of Deleted: 3 Deleted: )

- ( Deleted: also Deleted: or Deleted: wells Deleted: Formatted: Font: Calibri, 11 pt

Deleted: , as applicablePage 279 of 566 (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 §60.5411(b) and is connected through a closed vent system that meets the requirements of §60.5411 (a) to

a co ntrol device that meets the conditions specified in §60.5412
. (b) You must demonstrate initial compliance with the standards that apply to centrifugal compressor affected facilities as required by §60.5410. (c) You must demonstrate continuous compliance with the standards that apply to centrifugal compressor affected facilities as required by §60.5415. (d) You must perform the required notification, recordkeeping, and reporting as required by §60.5420. **§60.5385 What standards apply to reciprocating comp ressor**  **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 (a)(2) of this section. (1) B efore the compressor has operated for 26,000 hours. The number of hours of operation must be continuously monitoredPage 280 of 566 beginning upon initial startup of your reciprocating compressor affected facility, or **[INSERT DATE 60 DAYS AFTER DATE**  **OF PUBLICATION IN THE FEDERAL REGISTER]**  , 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

r equired by §60.5410. (c) You must demonstrate continuous compliance with standards that apply to reciprocating compressor affected facilities as required by §60.5415. (d) You must perform the required notification, recordkeeping, and reporting as require d by §60.5420. **§60.5390 What standards apply to pneumatic controller affected facilities?**  For each pneumatic controller affected facility you must comply with the VOC standards, based on natural gas as a surrogate for VOC, in either paragraph (b) or (c) of this section, as applicable. Pneumatic controllers meeting the conditions in paragraph (a) are exempt from this requirement. Deleted: previous

Deleted: installationPage 281 of 566 (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 controlle r as required in §60.5420(c)(4)(iv). (c)(1) Each pneumatic controller affected facility constructed, modified or reconstructed on or after **[INSERT DATE 1**  **YEAR AFTER PUBLICATION IN THE FEDERAL REGISTER]** 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 inform ation Deleted: demonstrate, to the Administrator’s satisf action,

Deleted: factors such as

Deleted: new, reconstructed or modified Deleted: installed after August 23, 2011, Deleted: (as defined in §60.5430 Deleted: new, reconstructed or modif ied Deleted: installed after August 23, 2011,

Deleted: controlled

Deleted: new, reconstructed or modified Deleted: installed Deleted: August 23, 2011, Formatted: Font: Bold, No underline, Font color: Auto

Deleted: new, reconstructed or modified Deleted: installed after August 23, 2011, **[**Page 282 of 566 that allows traceability to the records for that controlle r as required in §60.5420(c)(4)(iii). (d) You must demonstrate initial compliance with standards that apply to pneumatic controller affected facilities as required by §60.5410. (e) You must demonstrate continuous compliance with standards that apply to pneumatic controller affected facilities as required by §60.5415. (f) You must perform the required notification, recordkeeping, and reporting as required by §60.5420, except that yo u are not required to submit the notifications specified in §60.5420(a). **§60.5395 What standards apply to storage vessel affected facilities?**  Except as provided in paragraph (d) of this section, y ou
must comply with the standards in this section no later than **[INSERT DATE 1**  **YEAR AFTER PUBLICATION IN THE FEDERAL REGISTER]** for each storage vessel 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 Deleted: controlled

Deleted: You must

Deleted: ) (

Deleted: You mustPage 283 of 566 production, y ou 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 p racticable 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 of 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 t han 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 §60.5411(b) and is connected through a closed vent system that meets the requirements of §60.5411 (a) to a control device that meets the conditions specified in §60.5412. Deleted: installation, modification or reconstruction

Deleted: installation, modification or recons truction

Deleted: You must

Deleted: upon installation, modification or reconstruction

Deleted: installation, modification or reconstruction Deleted: 3Page 284 of 566
( 2 ) If you use a floating roof to reduce emissions, you must meet the requirements of §60. 112b(a)(1) or (2) and the relevant monitoring, inspection, recordkeeping, and reporting requirements in 40 CFR part 60, su bpart 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 §60.5410. ( 2 ) You must demonstrate continuous compliance with standards that apply to storage vessel affected facilities as required by §60.5415. ( 3 ) You must perform the required notification, recordkeeping, and reporting as required by §60.5420. ( d ) 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. **§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 § § 60.482

- 1a(a), (b), and (d ), 60.482

- 2a, and 60. 482

- 4a through 60.482

- 11a, except as provided in §60.5401. Deleted: 4 Deleted: vapor recovery device Deleted: 5411
.

Deleted: (b)

Deleted: standard Deleted: already

Formatted: Font: Bold Deleted: (c) You must demonstrate initial compliance with standards that apply to storage vessel affected facilities as required by §60.5410. ¶

(d) You must demonstrate continuous compliance with standards that apply to storage vessel affected facilities as required by §60.5415. ¶

(e) You must perform the required notification, recordkeeping, and reporting as required by §60.5420. **¶** Deleted: **VOC** Deleted: each compressor in VOC service or in wet gas service and Deleted: (as defined in §60.5430), Deleted: § Deleted: ),§ Deleted: §Page 285 of 566 (b) You may elect to comply with the requirements of §§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 emiss ion 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 §60.5402 of this subpart. (d) You must comply with the provisions of §60.485a of this part except as provided in paragraph (f) of this section. (e) You must comply with the provisions of §§60.486a and 60.487a of this part except as provided in §§60.5401, 60.5421, and 60.5422 of this part. (f) You must use the following provisi on instead of §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 co nsidered 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,Page 286 of 566 procedures that conform to the methods described in ASTM E169

- 63, 77, or 93 , E168

- 67, 77, or 92, or E260

- 73, 91, or 96 (incorporated by reference as specified in §60.17) must be used. **§60.5401 What are the exceptions to the equipment leak**  **standards for affected facilities at onshore natural gas processing**  **plants?** (a) You m ay comply with the following exceptions to the provisions of §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 §60.485a(b) except as provided in §60.5400(c) and in paragraph (b)(4) of this s ection, and §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 §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 Deleted: **VOC**

Deleted: subpart VVa of this part.

Deleted: 5000Page 287 of 566 days as specified in paragraph (b)(1) of this section and §60.482

- 4a(b)(1) of subpart VVa. (ii) N o 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 §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 §§60.482

- 2a(a)(1) and 60.482

- 7a(a), and paragraph (b)(1) of this s ection. (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 requiremen ts of §§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 §60.485 a(e): Deleted: with a

Deleted: (f) Flares used to comply with this subpart must comply with the requirements of §60.18. ¶ (gPage 288 of 566 (1) Equipment is in heavy liquid service if the weight percent evaporated is 10 percent or less at 150 o C (302 o F) as determined by ASTM Method D86

- 78, 82, 90, 95, or 96 (incorporated by reference as specified in §60.17). (2) Equipment is in li ght liquid service if the weight percent evaporated is greater than 10 percent at 150 o C (302 o F) as determined by ASTM Method D86

- 78, 82, 90, 95, or 96 (incorporated by reference as specified in §60.17). (g) An owner or operator may use the following provi sions instead of §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 §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 thePage 289 of 566 leak definition multiplied by (100 minus the percent of negative drift/divided by 100) must be re

- monitored. If any calibration drif t 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. **§60.5402 What are the alternative emission limitations for equipment leaks from onshore natural gas processing plants?**  (a) If, in the Administra tor'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.Page 290 of 566 (c) The Administrator will consider applications under this section from either owners or operators of affected facilit ies, 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 applica nt 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. **§60.5405 What standards apply to sweetening units at onshore**  **natural gas processing plants?** (a) During the initial performance test required by §60.8(b), you must achieve at a minimum, an SO 2 emission reduction efficiency (Z i ) 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. Formatted: No underline, Font color: Auto, Subscript Formatted: No underline, Font color: Auto, SubscriptPage 291 of 566 (b) After demonstrating compliance with the provisions of paragraph (a) of this section, you must achieve at a minimum, an
SO 2 emission reduction efficiency ( Z c ) 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 onsh**  **ore natural gas processing plants?**  (a) In conducting the performance tests required in §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 §60.8(b). (b) During a performance test required by §60.8, you must determine the minimum required reduction efficiencies (Z) of SO 2 emissions as required in §60.5405(a) and (b) as follows: (1) The average sulfur feed rate (X) must be computed as follows:

Where: X = average sulfur feed rate, Mg/D (LT/D). Q a = average volumetric flow rate of acid gas from sweetening unit, dscm/day (dscf/day). Y = average H 2 S 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 × 10 − 3 Mg/dscm, for metric units = (32 lb S/lb

- mole)/((385.36 dscf/lb

- mole)(2240 lb S/long ton)) = 3.707 × 10 − 5 long ton/dscf, for English units. Formatted: No underline, Font color: Auto, Subscript Formatted: No underline, Font color: Auto, Subscript

Formatted: No underline, Font color: Auto, Subscript

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(2) You must use the continuou s readings from the process flowmeter to determine the average volumetric flow rate (Q a ) in dscm/day (dscf/day) of the acid gas from the sweetening unit for each run. (3) You must use the Tutwiler procedure in §60.5408 or a chromatographic procedure follo wing ASTM E

– 260 (incorporated by reference

— see §60.17) to determine the H 2 S 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 mea n 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 × 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 (Z i ) and continuous (Z c ) reduction efficiencies of SO 2 emissions. (c) You must determine compliance with the SO 2 standards in §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: Formatted: No underline, Font color: Auto, Subscript

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Deleted:Page 293 of 566 (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:

Where: E = emission rate of sulfur per run, kg/hr. C e = concentration of sulfur equivalent (SO 2+ reduced sulfur), g/dscm (lb/dscf). Q sd = volumetric flow rate of effluent gas, dscm/hr (dscf/hr). K 1 = conversion factor, 1000 g/kg (7000 gr/lb). (4) The concentration (C e ) of sulfur equivalent must be the

sum of the SO 2 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. Deleted: tanks

Deleted: ¶

Formatted: No underline, Font color: Auto, Subscript Formatted: No underline, Font color: Auto, Superscript Formatted: No underline, Font color: Auto, Subscript Formatted: No underline, Font color: Auto, Subscript Formatted: No underline, Font color: Auto, Subscript Formatted: No underline, Font color: Auto, Subscript

Formatted: No underline, Font color: Auto, Superscript Formatted: No underline, Font color: Auto, Superscript Formatted: No underline, Font color: Auto, SuperscriptPage 294 of 566 (i) You must use Method 6 of appendix A to part 60 of this chapter to determine the SO 2 concentration. You must take eight samples of 20 minutes each at 30

- minute intervals. The

ar ithmetic average must be the concentration for the run. The concentration must be multiplied by 0.5 × 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 sampl es 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 × 10 − 3 to convert the results to sulfur equivalent. (iii) You must us e Method 16A or Method 15 of appendix A to part 60 of this chapter to determine the reduced sulfur concentration from oxidation

- type devices or where the oxygen content of the effluent gas is greater than 1.0 percent by volume. You must take eight samples of 20 minutes each at 30

- minute intervals. The arithmetic average must be the concentration for the run. The concentration in ppm reduced Formatted: No underline, Font color: Auto, Subscript

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Formatted: No underline, Font color: Auto, SuperscriptPage 295 of 566 sulfur as sulfur must be multiplied by 1.333 × 10 − 3 to convert the results to sulfur equivalent. (iv) You must use Me thod 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 (Q sd ) 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. Fo r 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. **60.5 407 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 pl ant and is subject to the provisions of §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: Formatted: No underline, Font color: Auto, Superscript

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(1) The accumulation of sulfur pro duct 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 wi th 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 H 2 S 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 §60.5406(b)(1). The Administrat or may require you to demonstrate that the H 2 S 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 Deleted: tanks

Formatted: No underline, Font color: Auto, SubscriptPage 297 of 566 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 reading s. (4) The sulfur feed rate (X) . For each 24

- hour period, you must compute X using the equation specified in §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 H 2 S concentration in the acid gas for the 24

- hour period, as applicable, to determine the required reduction efficiency in accordance with the provisions of §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 sul fur emission rate (E) of SO 2 in the gases discharged to the atmosphere . The SO 2 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 li mit of §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 Deleted: 3

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Formatted: No underline, Font color: Auto, SubscriptPage 298 of 566 leaving the combustion zo ne of the incinerator, if compliance with §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 manufactur er to be accurate to within ±1 percent of the temperature being measured. (3) When performance tests are conducted under the provision of §60.8 to demonstrate compliance with the standards under §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 SO 2 ) in the gas leaving the incinerator is equal to or less than 0.98, then temperature mon itoring 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 zon e of the incinerator at or above the appropriate level determined during the most recent performance test to ensure the sulfur compound oxidation criteria are met. Operation at lower average temperatures may be considered by the Administrator to be unaccep table operation and maintenance of the affected facility. You may request that the minimum Formatted: No underline, Font color: Auto, SubscriptPage 299 of 566 incinerator temperature be reestablished by conducting new performance tests under §60.8. (4) Upon promulgation of a performance specification of continuous monitor ing 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 a s 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) Wh ere 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 s ulfur compounds as SO 2 equivalent in the gases discharged to the atmosphere. The SO 2 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 t he equivalent emission limit of §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 Formatted: No underline, Font color: Auto, Subscript Formatted: No underline, Font color: Auto, SubscriptPage 300 of 566 monitoring systems for total reduced su lfur compounds at sulfur recovery plants. (d) For those sources required to comply with paragraph (b) or (c) of this section, you must calculate the average sulfur emission reduction efficiency achieved (R) for each 24

- hour clock internal. The 24

- hour int erval 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 §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 H 2 S expressed as sulfur may calcu late thePage 301 of 566 sulfur emission reduction efficiency achieved for each 24

- hour period by:

Where: R = The sulfur dioxide removal efficiency achieved during the 24

- hour period, percent. K 2 = 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 §60.13(b). (g) The continuous emission monitoring systems required in paragraphs (b)(1), (b)(3), and (c) of this section m ust be subject to the emission monitoring requirements of §60.13 of the General Provisions. For conducting the continuous emission monitoring system performance evaluation required by §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. Deleted: ¶

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**§60.5408 What is an o ptional procedure for measuring hydrogen**  **sulfide in acid gas —**  **Tutwiler Procedure? 1**  (a) When an instantaneous sample is desired and H2 S 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

su lfide 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 f or 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

1 Gas Engineers Handbook, Fuel Gas Engineering practices, The Industrial Press, 93 Worth Street, New York, NY, 1966, First Edition, Second Printing, page 6/25 (Docket A

- 80

- 20

- A, Entry II

- I

- 67). Deleted:Page 303 of 566 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 H 2 S per cubic feet of gas. (3) Starch solution. Rub into a thin pa ste 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), op en 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 a fter each addition; continue until a faint permanent blue color is obtained. Record reading; subtract from previous reading, and call difference D. Formatted: No underline, Font color: Auto, SubscriptPage 304 of 566 (e) With every fresh stock of starch solution perform a blank test as follows: Introduce fresh starch solut ion 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 H 2 S per 100 c ubic foot of gas = 100 (D

— C) (f) Greater sensitivity can be attained if a 500 ml capacity Tutwiler burette is used with a more dilute (0.001N) iodine solution. Concentrations less than 1.0 grains per 100 cubic foot can be determined in this way. Usually, the starch

iodine end point is much less distinct, and a blank determination of end point, with H 2 S

- free gas or air, is required. Formatted: Centered Deleted: = Deleted:

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Figure 1 . Tutwiler burette (lettered items mentioned in text).

§ **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** Deleted: Formatted: Font: (Default) Courier New, 12 pt, No underline, Font color: AutoPage 306 of 566 **affected facility, my pneumatic controller affected facility, my storage vessel a**  **ffected 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 **[INSERT DATE OF PUBLICATION IN THE FEDERAL REGISTER]** or upon initial startup, whichever is later, and ends no later tha n one year after the initial startup date for your affected facility or no later than one year after [ **INSERT DATE OF**
**PUBLICATION IN THE FEDERAL REGISTER** ]

. The initial compliance period may be less than one full year. (a) To achieve initi al 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 mu st submit the notification required in §60.5420(a)(2). (2) You must submit the initial annu al report for your well affected facility as required in §60.5420(b). (3) You must maintain a log of records as specified in §60. 5420(c)(1 ) for each well completion operation conducted during the initial compliance period. Deleted: the

Deleted: on the date the first annual report is due as specified in §60.5420(b).

Deleted: You have achieved

Deleted: if Deleted: have complied

Deleted: have notified the Administrator by the first of each month of the anticipated well completion operations during that month, the latitude and longitude coordinates of the well in decimal degrees to an accuracy and precision of five (5) decimals of a degree using the North American Datum (NAD) of 1983. Deleted: (2) You have notified the Administrator by email no later than four days prior to each well completion operation the actual date of the well completion operation. ¶ Deleted: have maintained Deleted: 5375(b) or (fPage 307 of 566
(4) For each gas well affected facility subject to both §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 t he 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 dig ital 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 compress or wet seal fluid degassing system by 95 .0 percent or greater as required by §60.5380 and as demonstrated by the requirements of §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 §60.5411(b) and is connected through a Deleted: You have submitted the initial annual report for your well affected facility as required in §60.5420(b).

Deleted: You have demonstrated

Deleted: if Deleted: have reduced

Deleted: have equippedPage 308 of 566 closed vent system that meets the requirements of §60.5411 (a) to a control device that meets the conditions specified in §60.5412. ( 3 ) You must conduct an initial performance test as required in §60.5413 within 180 days after initial startup or by **[INSERT DATE OF PUBLICATION IN THE FEDERAL REGISTER]** , whichever is later, and you must comply with the continuous compliance require ments in §60.5415( b ). ( 4 ) You must conduct the initial inspections required in §60.5416. (5 ) You must install and operate the continuous parameter monitoring systems in accordance with §60.5417. ( 6 ) You must submit the notifications required in 60.7(a)(1), (a)(3) and (a)(4). (7) You must submit the initial annual report for your centrifugal compressor affected facility as required in §60.5420(b) for each centrifugal compressor affected facility (8) You must maintain the records as specified in §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 (c)( 4 ) of this section. Deleted: have conducted

Deleted: have conducted

Deleted: demonstration Deleted: e Deleted: have conducted

Deleted: have installed Deleted: operated

Deleted: c Deleted: have achieved

Deleted: if Deleted: have complied Deleted: and Deleted: 2Page 309 of 566 (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), (a)(3) and (a)(4). ( 3 ) You must submit the initial annual report for your reciprocating compressor as required in §60.5420(b). (4) You must maintain the records as specified in §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 (d)( 6 ) of this section. (1) If applicable, y ou have demonstrated by maintaining records as specified in §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 §6 0. 5 3 90 (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. Deleted: have

Deleted: monitored Deleted: tracked Deleted:
Deleted: have included Deleted: cumulative number of hours of operation

Deleted: affected facility during the initial compliance period or the number of months since the last rod packing replacement in your initial annual report

Deleted: You have achieved

Deleted: if

Deleted: 5

Deleted: You Deleted: , to the Administra tor’s satisfaction,

Deleted: 5490Page 310 of 566
(3) You own or operat e 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 §60.5390( b )(2). (5) You must include the information in paragraph (d)(1) of this section and a listing of the pn eumatic controller affected facilities specified in paragraphs (d)(2) and (d)(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 §60.5420(b). (6) You must maintain the records as specified in §60.5420(c)(4) for each pneumatic controller affected facility. (e) To achieve initial compliance with the e mission 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

. Deleted: have tagged Deleted: , reconstructed or modified Deleted: c Deleted: have included

Deleted: installed

Deleted: You have demonstrated

Deleted: if Deleted: have complied Deleted: e)(6

Deleted: installation, modification or reconstruc tionPage 311 of 566
(2) You must determine the V OC 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 §60.5411(b) and is connected through a closed vent system that meets the requirements of §60.5411 (a) to a control device that meets the conditions specified in § 60.5412 within 60 days after startup for s torage 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

. ( 5 ) You must conduct an initial performance test as required in §60.5413 within 180 days after initial startup or within 180 days of **[INSERT DATE OF PUBLICATION IN THE FEDERAL** Deleted: have determined

Deleted: upon installation, modification or reconstruction

Deleted: have reduced

Deleted: greaer

Deleted: have equipped

Deleted: §§

Deleted: have conducted

Deleted: byPage 312 of 566
**REGISTER]** , whichever is later, and must conduct the compliance demonstration in §60.5415( b ). ( 6 ) You must conduct the initial inspections required in §60.5416. ( 7 ) You must install and operate continuous parameter monitoring systems in accordance with §60.5417. ( 8 ) You must submit the information in paragraphs (e)(1) through (e)( 7 ) of this section in the initial annual report as required in §60.5420(b). (9) You must maintain the records as specified in §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 require ments is demonstrated if you are in compliance with the requirements of §60.5400. (g) For sweetening unit affected facilities at onshore natural gas processing plants, initial compliance is demonstrated according to paragraphs (g)(1) through (g)(3) of thi s section. (1) To determine compliance with the standards for SO 2 specified in §60.5405(a), during the initial performance test as required by §60.8, the minimum required sulfur dioxide emission reduction efficiency (Z i ) is compared to the emission reduction efficiency (R) achieved by the sulfur recovery technology as Deleted: have conducted

Deleted: e

Deleted: have conducted

Deleted: have installed Deleted: operated

Deleted: have submitted

Deleted: for your storage vessel affected facilities installed, modified or reconstructed during the period covered by the annual report

Formatted: No underline, Font color: Auto, SubscriptPage 313 of 566 specified in paragraphs (g)(1)(i) and (g)(1)(ii) of this section. (i) If R ≥ Z i , your affected facility is in compliance. (ii) If R < Z i , 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 §60.5406(c)(1). (3) You have submitted the results of paragraphs (g)(1) and (g)(2) of this section in the initial annual repo rt submitted for your 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 materials**  **from storage vessels and cen**  **trifugal 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 §60.5412. Deleted: demonstrate initial compliance

Formatted: Font color: Auto

Deleted: tankPage 314 of 566 (2) You must design and operate the closed vent system with no detectable emissions as demonstrated by §60.5416(b)

. (3) You must meet the requirements specified in paragraphs (a)(3)(i) an d (a)(3)(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 thi s section, you must comply with either paragraph (a)(3)(i)(A) or (a)(3)(i)(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 §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 t he 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, anal yzer vents,
open - ended valves or lines, and safety devices are not subject to the requirements of paragraph (a)(3)(i) of this section. Deleted:

.

Deleted: and soundingPage 315 of 566
(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, sea led 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 (t his 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 equip ment 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. **§60.5412 What additional**  **requ irements must I meet for**  **determining initial compliance with control devices used to**  Formatted: Font color: Auto

Deleted: be designed to

Formatted: Font color: AutoPage 316 of 566 **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 d evice to meet the emission reduction standard in §60.5380(a)(1) for your centrifugal compressor or §60.5395(a)(1) or (a)(2) for your storage vessel,

y ou must use one of the control devices specified in paragraphs (a)(1) through (a)(3) of this section . You must demonstrate that the control device achieves the performance requirements u sing the performance test methods and procedures specified in §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 p erformance requirements specified in paragraphs (a)(1)(i) through (a)(1)(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 requireme nts of §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 Deleted: **demonstrate compliance at**

Deleted: demonstrate initial compliance

Deleted: You

Deleted: and comply with the emissions reduction performance requirements for the selected control device to reduce VOC emissions in accordance with the standards of this subpart

Formatted: Font color: AutoPage 317 of 566 less than 20 parts per million by volume on a dry basis corrected to 3 percent oxygen as determined in accordance with
t he requirements of §60.5413. (iii) You must operate at a minimum temperature of 760°C for a control device that can demonstrate a uniform combustion zone temperature during the performance test conducted under §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. (2) You must design and operate a vapor recovery device ( e.g. , carbon adsorption system or condenser) or other non

destructive con trol 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 §60.5413. The vapor recovery device must meet the design analysis requirements of §60. 5413(c). (3) You must design and operate a flare in accordance with the requirements of §60. 5413
. (b) You must operate each control device in accordance with the requirements specified in paragraphs (b)(1) and (b)(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 Formatted: Font color: Auto

Deleted: , as defined in §60.5430,

Deleted: 18(b).Page 318 of 566
vented from the storage vessel affected facility, as required under §60.5395, or wet seal fluid degassing system affecte d facility , as required under §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 m onitored in accordance with the requirements of §60.5417, you must demonstrate compliance according to the requirements of §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 (c)(2) of this section. (1) Following the initial startup of the control device, you must replace all carbon in the control device wit h fresh carbon on a regular, predetermined time interval that is no longer than the carbon service life established according to §60.5413(c)(2) or (c)(3) for the carbon adsorption system. You must maintain records identifying the schedule for replacement

a nd records of each carbon replacement as required in
§ 60.5420(c)(6)
. (2) You must either regenerate, reactivate, or burn the spent carbon removed from the carbon adsorption system in one of Deleted: , as required under §60.5395. Deleted: unit

Deleted: 63.774(b)(7)(ix). You must submit the schedule for replacement with the Notification of Compliance Status report as specified in §63.775(d)(5)(iv). Each carbon replacement must be reported in the Period ic Reports as specified in §63.772(e)(2)(xii).Page 319 of 566 the units specified in paragraphs (c)(2)(i) through (c)(2)(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 impl ements 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 boil er 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.Page 320 of 566 (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. **§60.5413 What are the performance testing procedures for control devices used to demonstrate compliance at my storage vessel**  **or centrifugal compressor**  **affected facility?** Thi s 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 perform ance requirements of §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 §60.18(b). You must conduct the compliance determination using Method 22 at 40 CFR part 60, appendix A

- 7, to determine visible emissions. Deleted: , as defined in §60.5430,Page 321 of 566 (2) A boiler or process heater with a design h eat 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 whi ch 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 §60.8(b). (7) A control device that can be demonstrated to meet the performance requirements of §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 (b)(5) of this section, as applicable, for each performance test Deleted: (6) A control device for which a performance test was conducted for determining compliance with a regulation promulgated by the EPA and the test was conducted using the same methods specified in this section and either no process changes have been made since the test, or you can d emonstrate that the results of the performance test, with or without adjustments, reliably demonstrate compliance despite process changes. ¶Page 322 of 566

conducted to demonstrate that a control device meets the requirements of §60.5412(a). You must conduct the initial and periodic performance tests according to the schedule specifi ed 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 (b)(1)(ii) of this section. Any references to particulate mentione d 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 s pecified in §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 §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 §60.5412(a)(1)(i) or (a)(2), you must us e Method 25A at 40 CFR part 60, appendix A

- 7. You must use the procedures in paragraphs (b)(3)(i) throughPage 323 of 566 (b)(3)(iv) of this section to calculate percent reduction efficiency. (i) For each run, you must take either an integrated sample or a minimum of fou r 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 equatio ns and procedures specified in paragraphs (b)(3)(ii)(A) and (b)(3)(ii)( B ) of this section. ( A ) You must use the following equations:

Where: E i , E o = Mass rate of TOC (minus methane and ethane) at the inlet and outlet of the control device, respectively, dry basis, kilogram per hour. K 2 = Constant, 2.494 × 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°C. C ij , C oj = 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. M ij , M oj = Molecular weight of sample component j of the gas stream at the inlet and outlet of the control device, respectively, gram/gram

- mole. Deleted: ¶ ¶ ¶ ¶

Field Code Changed Field Code Changed

Deleted: ×Page 324 of 566

Q i , Q o = 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:

Where: R cd = Control efficiency of control device, percent. E i = 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. E o = 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 c ombusted vent streams and primary and secondary fuels with the TOC (minus methane and ethane) exiting the device, respectively. Deleted: Equations [insert numbers here] in

Deleted: ¶Page 325 of 566 (4) You must use Method 25A at 40 CFR part 60, appendix A

- 7 to measure TOC (minus methane and ethane) to determine compliance w ith the enclosed combustion device total VOC concentration limit specified in §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 (b)(4)(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 durin g the run. (ii) You must calculate the TOC concentration for each run as follows:

Where: C TOC = Concentration of total organic compounds minus methane and ethane, dry basis, parts per million by volume. C ji = 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 para graphs (b)(4)(iii)(A) and (b)(4)(iii)(B) of this section. Deleted: ¶Page 326 of 566
( 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 to determine the oxygen concentrati on. 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:

Where: C c = TOC concentration corrected to 3 percent oxygen, dry basis, parts per million by volume. C m = TOC concentration, dry basis, parts per million by volume. %O 2d = Concentration of oxygen, dry basis, percent by volume. (5) You must conduct performance tests according to the

sc hedule specified in paragraphs (b)(5)(i) and (b)(5)(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
§ 60. 5420(b)(7 )
. (ii) You must conduct periodic performance tests for all control devices required to conduct initial performance tests Deleted: ¶

Deleted: the compliance date that is specified Deleted: each Deleted: source in §63.760(f)(7) through (8), except that the initial performance test for existing combustion control devices at existing major sources must be conducted **[INSERT THE DATE NO LATER THAN 3 YEARS AFTER DATE OF**  **PUBLICATION OF THE FINAL RULE IN THE**  **FEDE RAL REGISTER]**  . If you choose to replace an existing combustion control device at an existing major source with a control device whose model is tested under paragraph (d) of this section, then the newly installed device must comply with all provisions of th is subpart no later than **[INSERT THE DATE 3 YEARS AFTER DATE OF PUBLICATION OF THE FINAL**  **RULE IN THE FEDERAL REGISTER**  **]**
. Deleted: in the Notification of Compliance Status Report Deleted: 63.775(d)(1)(iiPage 3 27 of 566 except as specified in paragraphs (b)(5)(ii)(A) and (b)(5)(ii)(B) of this section. You must conduct the first periodic perfo rmance 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 § 60.5420(b)(7 ) . Combustion control devices meeting the criteria in either para graph (b)(5)(ii)(A) or (b)(5)(ii)(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 §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 §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 Deleted: in the next Periodic Report Deleted: 63.775(e)(2)(xi

Deleted: Condenser Deleted: . For a condenser design analysis conducted Formatted: Font color: Auto Deleted: ), you must meet Deleted: requirements specified in paragraphs (c)(1) and (c)(2) of this section. You must submit documentation of the design analysis as a part of the Notification of Compliance Status Report as required in §63.775(d)(1)(i). ¶

(1) The condenserPage 328 of 566 concentration level, design average temperature of the condenser exhaust ve nt stream, and the design 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 c arbon 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 Deleted:

Deleted: (2Page 329 of 566 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 (d)(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 (d)(1)(iii) of this section. (i) The control device model tested must meet the emission levels in paragraphs (d)(1)(i)(A) through (d)(1)(i)(C) of this section.Page 330 of 566 (A) Method 22 at 40 CFR part 60, appendix A

- 7, result s 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 (d)(1)(i)(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 s ettings in paragraphs (d)(2)(i) through (d)(2)(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 independentPage 331 of 566

third

- party laboratory (not affiliated with the control devi ce 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 minut es, 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

m inutes, 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 sampli ng.Page 332 of 566 (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 w ith paragraph (d)(9) of this section. (4) The manufacturer must conduct inlet testing as specified in paragraphs (d)(4)(i) through (d)(4)(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 me ter. (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.Page 333 of 566 (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 (d)(5)(ii) of thi s 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 a s specified in paragraphs (d)(5)(i)(A) through (d)(5)(i)(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)(5)(ii)(D) of this section. You must include the results in the test report in paragraph (d)(9) of this section. (A) Hydrocarbon compounds containing between one and five atoms of carbon plus benzene using ASTM D1945

- 03.Page 334 of 566
(B) Hydrogen (H 2 ), carbon monoxide (CO), carbon dioxide (CO 2 ), nitrog en (N 2 ), oxygen (O 2 ) using ASTM D1945

- 03. (C) Carbonyl sulfide, carbon disulfide plus mercaptans using ASTM D5504. (D) Higher heating value using ASTM D3588

- 98 or ASTM D4891

- 89. (6) The manufacturer must conduct outlet testing in accordance with the cri teria in paragraphs (d)(6)(i) through (d)(6)(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 equival ent 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 Formatted: Font color: AutoPage 335 of 566

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. 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 wei ght as specified in paragraphs (d)(7)(i) and (d)(7)(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 ga s chromatograph

- thermal conductivity detector (GC

- TCD) analysisPage 336 of 566 meeting the criteria in paragraphs (d)(7)(i)(A) through (d)(7)(i)(D) of this section. (A) Collect the integrated sample throughout the entire test, and collect representative volumes from eac h 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 th eir 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 le ast 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 § 60.5420(b)(7 ) . The manufacturer must determine moisture us ing Method 4 at 40 CFR part 60, appendix A

- 3. Traverse both ports with the Method 4 at 40 CFR Deleted: 63.775(d)(iiiPage 337 of 566 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, in tegrated bag sample during the port change. (8) The manufacturer must determine total hydrocarbons as specified by the criteria in paragraphs (d)(8)(i) through (d)(8)(vii) of this section. (i) Conduct THC sampling using Method 25A at 40 CFR part 60, appe ndix 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.Page 338 of 566 (vi) THC results must be corrected to 3 percent CO 2 , 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 (d)(9)(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) Fu el gas delivery pressure and temperature. (B) Fuel gas moisture range. (C) Purge gas usage range. (D) Condensate (liquid fuel) separation range. Formatted: No underline, Font color: Auto, Subscript

Deleted: submit

Deleted: in the test report req uired under §63.775(d)(1)(iii).Page 339 of 566 (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 with test times and calibration values in the test report. **§60.54 15 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 reportsPage 340 of 566 required by §60.5420(b) and maintaining the records for each completion operation specified in §60.5420 (c)(1)
. (b) For each centrifugal compressor affected facility, you must demonstrate continuous compliance according to paragraphs (b)(1) and (b)(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 demo nstrate 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 §60.5420(c)(2). (c) For each reciprocatin g compressor affected facility,
you must demonstrate continuous compliance according to paragraphs (c)(1) through (c) ( 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 **[INSERT DATE OF PUBLICATION IN THE FEDERAL REGISTER]**  , or the date of the
most recent reciprocating compressor rod packing replacement, whichever is later. (2) You m ust submit the annual report as required in §60.5420(b) and maintain records as required in §60.5420(c)(3)

. Deleted: (as defined in §60.5430) Deleted:

. Deleted:
Deleted: have demonstrated

Deleted: C ontinuous compliance is demonstrated if the Deleted: are reduced

Deleted: paragraphs

Deleted: )(i) through (e)(2)(viii

Deleted: have demonstrated

Deleted: and (2

Deleted: have Deleted: monitored

Deleted: tracked

Deleted: previous

Deleted: The cumulative number of hours of operation or number of months since the previous rod packing replacement must be included in the annual report as required in §60.5420(b)(4). Deleted: have replacedPage 341 of 566
( 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 (d)(3) of this section. (1) You must continuously operate the pneumatic controllers as required in §60.5390(a), (b) or (c). ( 2) You must submit the annual report as required in §60.54 20(b). (3) You must maintain records as required in §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 (e)(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 §60.5412(a)(2) using the procedure specified in paragraphs (e)( 2 ) (i) through (e)( 2 ) ( vii ) of this section. If you use a condenser as the control device to achieve the Deleted: previous

Deleted: is demonstrated by maintaining the records demonstrating that you have installed and operated

Deleted: have demonstrated

Deleted: Continuous compliance is demonstrated if the

Deleted: viiiPage 342 of 566 requirements specified in § 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 (e)( 2 ) (vii) of this section and compliance with paragraph (e)( 2 ) (viii) of this section on ly 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 § 60.5420(b) , following the change. ( i ) You must operate below (or above) the site specific maximum ( or minimum ) parameter value establish ed according to the requirements of §60.5417(f)(1). ( ii ) You must calculate the daily average of the applicable monitored parameter in accordance with §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 un der 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 c ontrol device is conducted by the device manufacturer as specified in §60.5413(d), compliance with Deleted: Periodic

Deleted: establish a

Deleted: monitoring Deleted: (as appropriate)Page 343 of 566 the operating parameter limit is achieved when the inlet gas flow rate is equal to or less than the value established under §60.5413(d)(1)(ii). ( iv ) You mus t operate the continuous monitoring system required in §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 qual ity 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 m onitoring 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 acti vities 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. Deleted:Page 344 of 566
( vi ) Failure to colle ct 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 activi ties (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 §60.5412(a), you must demonstrate compliance by installing a device tested under the p rovisions in §60.5413(d) and complying with the criteria in paragraphs (e)(2)(vii)(A) through (e)(2)(vii)(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 §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 §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 mont hly. The observation period must be 2 hours and must follow Method 22.Page 345 of 566
( D ) Compliance with the operating parameter limit is achieved when the criteria in paragraphs (e)(2)(vii)(D)( 1 ) through (e)(2)(vii)(D)( 5 ) are met. ( 1 ) The inlet gas flow rate monito red under paragraph (e)(2)(vii)(A) of this section is equal to or below the maximum established by the manufacturer. ( 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 s ection, 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 (e)(2)(vii)(D)( 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 §60.5413, or replace the device with another control device whose model was tested and meets the requirements in §60.5413(d). ( viii ) If you use a condenser as the control device to achieve the percent reduction performance requirements specified Deleted: 6Page 346 of 566 in §60.5412(a)(2), you must demonstrate compliance using the procedures in paragraphs (e)(2)(viii)(A) through (e)(2)(vi ii)(E) of this section. ( A ) You must establish a site

- specific condenser performance curve according to §60.5417(f)(2). ( B ) You must calculate the daily average condenser outlet temperature in accordance with §60.5417(e). ( C ) You must determine the con denser 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 (e)(2)(viii)(D)( 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 § 60.5370 , if you have l ess 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 r eduction requirement if the 120

- day Deleted: for the preceding 365 operating days Deleted: 63.760(f),Page 347 of 566 average TOC emission reduction is equal to or greater than 9 5 .0 percent. ( 2 ) After 120 days and no more than 364 days of operation after the compliance date specified in § 60.5370 , you must calculate th e 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 9 5 .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 e mission 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 §60.5400. (g) For each sweetening unit affected facility at onshore natural gas processing plants, you must demonstrate continuous compliance with the standards for SO 2 specified in §60.5405(b) according to parag raphs (g)(1) and (g)(2) of this section. Deleted: 90

Deleted: dates Deleted: 63.760(f),

Deleted: 90

Deleted: specified in §60.5412(a)(2)

Formatted: No underline, Font color: Auto, SubscriptPage 348 of 566 (1) The minimum required SO 2 emission reduction efficiency (Z c ) is compared to the emission reduction efficiency (R) achieved by the sulfur recovery technology. (i) If R ≥ Z c , your affected facility is in complian ce. (ii) If R < Z c , 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 §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 §§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 m alfunction, as defined at §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 §60.5420(a), and must prove by a preponderance of evidence that: (i) The violation : Formatted: No underline, Font color: Auto, Subscript

Deleted: exceedance

Deleted: limit

Deleted: notificationPage 349 of 566
(A) Was caused by a s udden, 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; an d (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 dama ge; and (v) All possible steps were taken to minimize the impact of the violation on ambient air quality, the environment and human health; and Deleted: and monitoring

Deleted: Were

Deleted:Page 350 of 566 (vi) All emissions monitoring and control systems were kept in operation if at all possible, consistent with s afety 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 ev ent 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 s ubmit 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 p eriodic 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 Deleted: in a semiannual reportPage 351 of 566 of any applicable averaging period). If such compliance, deviation report or exce ss 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

. **§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 (a)(2) of this section, inspect each cover according to the procedures and schedule specified in paragraph (a)(3) of this sec tion, 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 section s of hard piping or a bolted Formatted: Font color: AutoPage 352 of 566 and gasketed ducting flange), you must meet the requirements specified in paragraphs (a)(1)(i) and (a)(1)(ii) of this section. (i) Conduct an initial inspection according to the test methods and procedures specified in paragra ph (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 § 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 un sealed. You must maintain records of the inspection results as specified in § 60.5420(c)(6 )
. (2) For closed vent system components other than those specified in paragraph (a)(1) of this section, you must meet th e requirements of paragraphs (a)(2)(i) through (a)(2)(iii) of this section. (i) Conduct an initial inspection according to the test methods and procedures specified in paragraph (b) of this Deleted: submit

Deleted: with the Notification of Compliance Status Report Deleted: 63.775(d)(1) or (2

Deleted: submit

Deleted: in the Periodic Report Deleted: 63.775(e)(2)(iiiPage 353 of 566 section to demonstrate that the closed vent system operates with no detectable emissions. You must maintain records of the inspection results as specified in § 60.5420(c)(6 )
. (ii) Conduct annual inspections according to the test methods and proce dures 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 § 60.54 20(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.

Y ou must maintain records of the inspection results as specified in § 60.5420(c)(6 )
. (3) For each cover, you must meet the requirements in paragraphs (a)(3)(i) and (a)(3)(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 Deleted: submit

Deleted: with the Notification of Compliance Status Report Deleted: 63.775(d)(1) or (2

Deleted: submit

Deleted: in the Periodic Report Deleted: 63.775(e)(2)(iii

Deleted: submit Deleted: in the Periodic Report Deleted: 63.775(e)(2)(iiiPage 354 of 566
the cover that extend to or above the ground s urface, 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 sectio n following the installation of the cover. Thereafter, you must perform the inspection at least once every calendar year, except as pro vided in paragraphs (e) and (f) of this section. You must maintain records of the inspection results as specified in
§ 60.5420(c)(7 )
. (4) For each bypass device, except as provided for in
§ 6 0 .5411, you must meet the requirements of paragraphs (a)(4)(i) or (a)(4)(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 th e 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 mo nth to verify that the valve is maintained in the non

- diverting position and the vent stream is not diverted through the bypass Formatted: Font color: Auto

Deleted: You must submit the inspection results with the Notification of Compliance Status Report as specified in §63.775(d)(12). Deleted: submit annual

Deleted: in the Periodic Report

Deleted: 63.775(e)(2)(iii

Deleted: 63Page 355 of 566

device. You must maintain records of the inspections according
to § 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), (a)(2), or (a)(3) of this section, you must meet the requirement s of paragraphs (b)(1) through (b)( 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 Meth od 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 (b)(4)(ii) of this section. (i) Zero air (less th an 10 parts per million by volume hydrocarbon in air). Deleted: 8Page 356 of 566
(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 backg round 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 instrum ent must meet the performance criteria specified in paragraphs (b)(6)(i) and (b)(6)(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 par t 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 process streams that contain nitr ogen, 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 criteri a specified in paragraph (b)(6)(i) of this section, you may adjust the instrument readings by multiplyingPage 357 of 566 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 (b)(7)(ii) of this section. (i) If you choose not to adjust the detection instrument readings for the bac kground 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 backgroun d 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 de tectable organic emissions if the organicPage 358 of 566 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)(A ) and ( b)(9)(B ) of this section, except as provided in paragraph (d) of this section. ( A ) A first attempt at repair must be made no later than 5 calendar days after the leak is detected. ( B ) 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 o r 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 emiss ions 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 requir ements in paragraphs (e)(1) and (e)(2) of this section are met. Unsafe to inspect parts are exempt from the inspection requirements of paragraphs (a)(1) through (a)(3) of this section. Deleted: c

Deleted: c)(1 Deleted: c)(2

Deleted: 1

Deleted: 2

Deleted: d

Deleted: as defined in §60.5430,

Deleted: ePage 359 of 566
( A ) You determine that the equipment is unsafe to inspect because ins pecting personnel would be exposed to an imminent or potential danger as a consequence of complying with paragraphs (a)(1), (a)(2), or (a)(3) of this section. ( B ) You have a written plan that requires inspection of the equipment as frequently as practica ble 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)(A ) and ( b)(12)(B ) of this section are met. Difficult to inspect parts are exempt from the inspection requirements of paragraphs (a)(1) through (a)(3) of this section

. ( A ) You determine that the equipment cannot be inspected without elevating the inspecting personnel mo re than 2 meters above a support surface. ( B ) 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 § 60.5420( c)(9 )
. **§60.5417 What are the continuous control device monitoring requirements for my storage vessel**  **or centrifugal compressor affected facility?**  Deleted: 1

Deleted: 2

Deleted: f

Deleted: f)(1

Deleted: f)(2

Deleted: .:

Deleted: 1

Deleted: 2

Deleted: g

Deleted: §63.774(b)(5) through (8Page 360 of 566 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 cont rol 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 §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 (b)(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 §60.5412. For each continuous parameter monitoring system, you must meet the specifications and Deleted: for each control device used to Deleted: with thePage 361 of 566 requirements in paragraphs (c)(1) throug h (c)(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 (c)(1)(ii) of this section. (i) Each measured data value. (ii) Each block av erage 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 p eriod) 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 (c)(2)(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. Deleted: and in §63.8(d).

Deleted: Using the process describe d in §63.8(f)(4), you may request approval of monitoring system quality assurance and quality control procedures alternative to those specified in paragraphs (c)(2)(i) through (v) of this section in your site

- specific monitoring plan.Page 362 of 566 (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 § 60.13(b )
. (v) Ongo ing reporting and recordkeeping procedures in accordance with provisions in § 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 accordance with the site

- specific monitoring plan. (d) You must insta ll, 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), (d)(2), or (d)(3) of this section. (1) A continuous monitoring system that measures the operating parameters in paragraphs (d)(1)(i) through (d)(1)(viii) of this section, as applicable. Formatted: Font color: Auto

Deleted: 63.8(c)(1) and (c)(3

Deleted: 63.10 Deleted: e)(1 Deleted: e)(2)(iPage 363 of 566 (i) For a thermal vapor incinerator that demonstrates during the performance test conducted under §60.5413 that combusti on 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 °C, or ±2.5 °C, whichev er 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 c apable of monitoring temperature at two locations and have a minimum accuracy of ±1 percent of the temperature being monitored in °C, or ±2.5 °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 in dicates 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 Deleted:

Deleted:Page 364 of 566
percent of the temperature b eing monitored in °C, or ±2.5 °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 °C, or ±2.8 °C, whichever value is greater. You must install the temperature sensor at a location in the exhaust vent stream from t he condenser. (vi) For a regenerative

- type carbon adsorption system, a continuous monitoring system that meets the specifications in paragraphs (d)(1)(vi)(A) and (d)(1)(vi)(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.
Yo u 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 e lectrical connections for oxidation and Deleted:

Deleted:Page 365 of 566 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 perce nt of the temperature being monitored in °C, or ±2.5 °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 speci fied in §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 §60.5413(d), a continuou s monitoring system meeting the requirements of paragraphs (d)(1)(viii)(A) and (d)(1)(viii)(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 accu racy of ±2 percent or better. Deleted:Page 366 of 566 (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 compound s 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, calibra te, 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 (d)(2) of this section, upon approval of the Administrator as specified in § 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 avail able for 75 percent of the Deleted: 63.8(f)(1) through (5Page 367 of 566 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
cont rol device, to define the conditions at which the control device must be operated to continuously achieve the applicable performance requirements of §60.5412(a). You must establish each minimum or maximum operating parameter value as specified in paragraph s (f)(1)(i) through (f)(1)(iii) of this section. (i) If you conduct performance tests in accordance with the requirements of §60.5413(b) to demonstrate that the control device achieves the applicable performance requirements specified in §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 recommenda tions or a combination of both.Page 368 of 566 (ii) If you use a condenser design analysis in accordance with the requirements of §60.5413(c) to demonstrate that the control device achieves the applicable performance requirements specified in §60.5412(a), then you must establish the minimum 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 th e performance test requirement was met under §60.5413(d) to demonstrate that the control device achieves the applicable performance requirements specified in §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 temper ature and condenser control efficiency, according to the requirements of paragraphs (f)(2)(i) and (f)(2)(ii) of this section . (i) If you conduct a performance test in accordance with the requirements of §60.5413(b) to demonstrate that the condenser achie ves the applicable performance requirements in §60.5412(a), then the condenser performance curve must be basedPage 369 of 56 6 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 §60.5413(c)(1) to demonstrate that the condenser achieves the applicable performance requirements specified in §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 operati ng day and more than one of these operating parameters meets a deviation criterion specified in paragraphs (g)(1) through (g)(6) of this section, then a single excursion is determined to have occurred for the control device for that operating d ay. (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 Deleted: An excursion

Deleted: an excursion

Deleted: An excursionPage 370 of 566 operating parameter limit) established in paragraph (f)( 1) of this section. (2) If you meet §60.5412(a)(2), a deviation occurs when the 365

- day average condenser efficiency calculated according to the requirements specified in §60.5415(e)(8)(iv) is less than 95.0 percent. (3) If you meet §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 §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 (g)(5)(ii) of this section are met. (i) For each bypass line subject to §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 §60.5411(a)(3)(i)(B), if the seal or closure mechanism has been broken, the bypass Deleted: an excursion

Deleted: an excursion

Deleted: A n excursion

Deleted: an excursionPage 371 of 566 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 §60.5413(d), a deviation occurs when the conditions of paragraphs (g)(6)(i) o r (g)(6)(ii) are met. (i) The inlet gas flow rate exceeds the maximum established during the test conducted under §60.5413(d). (ii) Failure of the monthly visible emissions test conducted under §60.5415(e)(7)(iii) occurs. **§60.5420 What are my notification, reporting, and**  **recordkeeping requirements?**  (a) You must submit the notifications required in §60.7(a)(1 ) and (a)(4), and according to paragraphs (a)(1) and (a)(2) of this section, if you own or operate one or more of the affected facilities specified in §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 §6 0.7(a)(1), (a)(3) and (a)(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 Deleted: an excursion Deleted: (h) For each excursion, you are deemed to have failed to have applied control in a manner that achieves the required operating parameter limits, except as provided for in paragraph (i) of this section. Failure to achieve the required operating parameter limits is a violation of this standard. ¶

(i) An excursion is not a violation of the operating parameter limit as specified in paragraphs (i)(1) and (i)(2) of this section. ¶

(1) An excursion does not count toward the number of excused excursions allowed under paragraph (i)(2) of this se ction when the excursion occurs during any one of the periods identified in paragraphs (i)(1)(i) and (i)(1)(ii) of this section. ¶

(i) During a malfunction when the affected facility is operated during such period in accordance with §63.6(e)(1); or ¶

(ii) Du ring periods of non

operation of the unit or the process that is vented to the control device (resulting in cessation of VOC emissions to which the monitoring applies). ¶

(2) For each control device, or combinations of control devices installed on the same emissions unit, one excused excursion is allowed per semiannual period for any reason. The initial semiannual period is the 6

- month reporting period addressed by the first Periodic Report submitted in accordance with §63.775(e) of this subpart. ¶

(j) Nothin g in paragraphs (a) through (i) of this section is construed to allow or excuse a monitoring parameter excursion caused by any activity that violates other applicable provisions of this subpart. ¶ Deleted: ), (a)(3 Deleted: installed Deleted: replaced Deleted: the notifications specified in paragraphs (a)(2)(i) and (a)(2)(ii) of this section to the Administrator. ¶

(i) By the first of each month in which you anticipate the commencement of one or more well completion operations, you must submit Deleted: eachPage 372 of 566 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 sta te 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 requir ements. You must submit annual reports containing the information specified in paragraphs (b)(1) through (b)(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 §60.5410 . Subsequent an nual reports are due on the same date each year as the initial annual report. If you own or operate more than one affected facility, you may submit one report for multiple affected facilities provided the report contains all of the information required as specified in paragraphs (b)(1) through (b)(6) of this section. Annual reports may coincide with Deleted: during that month.

Deleted: of the

Deleted:

.

Deleted: (ii) No earlier than 3 days or later than 2 days prior to the commencement of each well completion operation, you must send an email notification to the Administrator of the actual commencement date of the well completion operation. ¶

Deleted: up to 1 year

Deleted: startup date for your affected facility or up to 1 year after **[INSERT DATE OF PUBLICATION IN THE FEDERAL REGISTER]**  , whichever is laterPage 373 of 566 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 report s 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 (b)(1)( 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. (2) For each gas well affected facil ity, the information in paragraphs (b)(2)(i) through (b)(2)( ii ) of this section. (i) Records of each well completion operation as specified in paragraph (c)(1)(i) through (c)(1)(iv) of this section for each gas well a ffected facility conducted during the reporting period . In lieu of submitting the records specified in paragraph (c)(1)(i) through (c)(1)(iv), the owner or operator may submit a list of the well completions with hydraulic fracturing completed Deleted: iii

Deleted: An identification Deleted: , Deleted: defined Deleted: §60.5430,

Deleted: ;Page 374 of 566 during the r eporting period and the records required by paragraph (c)(1)(v) of this section for each well completion. (ii) R ecord s 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 (b)(3)(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 §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 (b)(4)( ii ) of this section. (i) The cumulative number of hours or operation or the number of months since initial startup, **[INSERT DATE OF PUBLICATION IN THE FEDERAL REGISTER]**  , or since the previous reciprocating compressor rod packing replacement, whichever is later. Deleted: (iii) Records specified in §60.5375(b) for each well completion operation that occurred during the reporting period. ¶

Deleted: installed

Deleted: iiiPage 375 of 566
(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 (b)(5)( 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 §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 sto rage vessel affected facility, the information in paragraphs (b)(6)(i) through (b)(6)( 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. Deleted: (ii) Documentation that the reciprocating compressor rod packing was replaced before the cumulative number of hours of operation reached 2 6 ,000 hours or 36 months from the previous rod packing repla cement . ¶ (iii

Deleted: installed

Deleted: ¶

¶

Deleted: iv

Deleted: installedPage 376 of 566
( ii ) Documentation that the VOC em ission rate is less than 6 tpy for meeting the requirements in §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 §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

co llected using test methods on the ERT website 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 inform ation (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 a nd mailed to U.S. EPA/OAPQS/CORE Deleted: If required to reduce emissions by complying with §60.5395(a)(1), the records specified in §63.774(b)(2) through (b)(8) of this chapter. ¶ ( iii ) Deleted: iv

Formatted: No underline, Font color: AutoPage 377 of 566
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 discreti on 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 paragraphs (1)(i) of this section must be sent to the Administrator at the appropriate address listed in §6 3.13 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 (1)(i) and (ii) of this section in paper format. (c) Recordkeeping requirements

. You must maintain the records identified as specified in §60.7(f) and in paragraphs (c)(1) through (c)( 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 (c)(1)( v ) of this section

. Formatted: Font color: Auto

Deleted: 5

Deleted: iiiPage 378 of 566 (i) Records identifying each well completion operation for each gas well affected facility ; (ii) Record s of deviations i n cases where well completion operations with hydraulic fracturing were not performed in compliance with the requirements specified in §60.5375. (iii) Records required in §60.5375(b) or (f) for each well completion operation conducted for each gas well af fected facility that occurred during the reporting period. You must maintain the records specified in paragraphs (c)(1)(iii)(A) and (c)(1)(iii)(B) of this section. (A) For each gas well affected facility required to comply with the requirements of §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; a nd 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 §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 §60.5375(a)(3), you must record: the location of Deleted: conducted during the reporting period;

Deleted: well s

Deleted: sales

Deleted: sales line. In addition, y ou must record the distance, in miles, of the nearest gathering line.Page 379 of 566

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 §60.5375(a)(1) and (a)(3) , records of the digital photograph as specified in §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 §60.5380

. (3) For each reciprocating compressors affected facility, you must maintain the records in paragraphs (c)(3)(i) through (c )(3)( iii ) of this section. (i) Records of the cumulative number of hours of operation or number of months since initial startup or **[INSERT DATE OF PUBLICATION IN THE FEDERAL REGISTER]**  , or the previous replacement of the reciprocating compressor rod packin g, 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 §6 0.5385.Page 380 of 566 (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 control ler 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

rea sons 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 cubi c 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 co mpliance with the requirements specified in §60.5390. (5) For each storage vessel affected facility, you must maintain the records identified in paragraphs (c)(5)(i) through (c)(5)( iv ) of this section. Deleted: c)(4)(

Deleted: installed

Deleted: determination

Deleted: iiiPage 381 of 566 (i) If required to reduce emissions by complying with
§ 60.5395 , the records specified in § 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 §60.5395(a ) , including identifica tion 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 §§60.5395, 60.5411, 6 0.5412 and 60.5413. (iv) F or vessels that are skid

- mounted or permanently attached to something that is mobile ( such as trucks, railcars, barges or ships ), r ecords indicating the number of consecutive days that the vessel is located at a site in the oil and natural gas prod uction segment, natural gas processing segment or natural gas transmission and storage segment . I f 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, t hen 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
§ 60.5416(a)(1) and (2), records of each inspection. Deleted: 63.774(b)(2) through (8) Deleted: chapter

Deleted: ).

Deleted: ,Page 382 of 566 (7) For each storage vessel or centrifugal compressor subject to the cover requirements of § 60.5416(a)(3), a record of each inspection. (8) For each storage vessel or centrifugal compressor subject to the bypass requirements of § 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 syste m used to comply with this subpart that must operate with no detectable emissions, a record of the monitoring conducted in accordance with § 60.5416(b)(13). (10) Records of the schedule for carbon replacement (as determined by the design analysis requirements of §60.5413(c)(2) or (c)(3)) and records of each carbon replacement as specified in §60.5412(c)(1). (11) For each storage vessel or centrifugal compressor subject to the control device requirements of §6 0.5412, 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. **§60. 5421 What are my additional recordkeeping requirements for**  **my affected facility subject to VOC requirements for onshore natural gas processing plants?** Page 383 of 566 (a) You must comply with the requirements of paragraph (b) of this section in addition to the requiremen ts of §60.486a. (b) The following recordkeeping requirements apply to pressure relief devices subject to the requirements of §60.5401(b)(1) of this subpart. (1) When each leak is detected as specified in §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 devi ce may be removed after it has been repaired. (2) When each leak is detected as specified in §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.Page 384 of 566 (v) ”Repair delayed” and the reason for the delay if a leak is not repaired within 15 calendar days a fter 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 rep aired 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 §60.482

- 4a(a). The designation of equipment subject to the provisions of §60.482

- 4a(a) must be signed by the owner or operator. **§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 §60.487a(a), (b), (c)(2)(i) through (iv), and (c)(2)(vii) through (viii).Page 385 of 566
(b) An owner or operator must include the following information in the initial semiannual report in addition to the information required in §60.487a(b)(1) through (4): Number of pressure relief devices subject to the requirements of §60.5401(b) except for thos e pressure relief devices designated for no detectable emissions under the provisions of §60.482

– 4a(a) and those pressure relief devices complying with §60.482

– 4a(c). (c) An owner or operator must include the following information in all semiannual report s in addition to the information required in §60.487a(c)(2)(i) through (vi): (1) Number of pressure relief devices for which leaks were detected as required in §60.5401(b)(2); and (2) Number of pressure relief devices for which leaks were not repaired as required in §60.5401(b)(3). **§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 requi red in §60.5405(a) and (b) and §60.5407(a) through (g) for at least 2 years following the date of the measurements. This requirement is included under §60.7(d) of the General Provisions.Page 386 of 566 (b) You must submit a report of excess emissions to the Administrato r 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 reduc tion efficiency (R) is less than the minimum required efficiency (Z). (2) For any affected facility electing to comply with the provisions of §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 §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 H 2 S 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 H 2 S expressed as sulfur. (d) If you elect to comply with §60.5407(e) you must keep, for the life of the facility, a record demonstrating that the Deleted: semiannuallyPage 387 of 566 facility's de sign capacity is less than 150 LT/D of H 2 S 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 report ing 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 requ irements established by the state. **§60.5425 What part of the General Provisions apply to me?** Table 3 to this subpart shows which parts of the General Provisions in §§60.1 through 60.19 apply to you. **§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 ( H 2 S) and carbon dioxide (CO 2 ) 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 t he burden of proof, and thePage 388 of 566 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
pressu re 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. Deleted: Centrifugal compressor means a piece of equipment that compresses a process gas b y means of mechanical rotating vanes or impellers.Page 389 of 566 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 opera tions, 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: (i) Fails to meet any requirement or obligation estab lished by this subpart including, but not limited to, any emission limit, operating limit, or work practice standard; Deleted: Compressor means a piece of equipment that compresses process gas and is usually a centrifugal compressor or a reciprocating compressor. ¶

Deleted: Condensate Deleted: hydrocarbon liquid separated from Deleted: that condenses due Deleted: changes in the Deleted: , or both, and remains liquid at standard conditions, as specified in §60.2. For Deleted: purposes of this subpart, a hydrocarbon liquid with an API gravity equal to or greater than 40 degrees is considered condensate. ¶ Crude oil means crude petroleum oil any other hydrocarbon liquid, which are produced at the well in liquid form by ordinary production met hods, and which are not the result of condensation of Deleted: before or after it leaves Deleted: reservoir. For Deleted: purposes of this subpart, a hydrocarbon liquid with an API gravity less than 40 degrees is considered crude oilPage 390 of 566 (ii) Fails to meet any term or condition that is adopted to implement an applicable requirement in this subpart and that is included in t he operating permit for any affected source required to obtain such a permit; or (iii) Fails to meet any emission limit, operating limit, or work practice standard in this subpart during startup, shutdown, or malfunction, regardless o f 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 fro m 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. Flowback means the process of allowing fluids to flow from a natural gas well following a treatment, either in preparation for a subsequent phase of treatment or in preparation for Deleted: compressor,

Deleted: thePage 391 of 566 cleanup and returning the well to production. The flowback period begins when material introduced into the well durin g 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, whicheve r occurs first. 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

. 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 independe ntly 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 Deleted: surface pipe through which Deleted: natural Deleted: travels

Deleted: liquids,

Deleted: ,
Deleted: sand, Deleted: , Deleted: involvePage 392 of 566 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 servic e means that the piece of equipment contains a liquid that meets the conditions specified in §60.485a(e) or §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 c ondensed 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 g as - driven pneumatic controller means a pneumatic controller powered by pressurized natural gas. Deleted: back flow

Deleted: sand

Deleted: h

Deleted: 443

Deleted: 092

Deleted: plus 497 Deleted: sales Deleted: Modification means any physical change in, or change in the method of operation of, an affected facility which increases the am ount of VOC or natural gas emitted into the atmosphere by that facility or which results in the emission of VOC or natural gas into the atmosphere not previously emitted. ¶Page 393 of 566 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 si te 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, booster s, 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.Page 394 of 566

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 uni t 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 indepe ndently 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 move ment 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 limitingPage 395 of 566
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 purch ased fuel or raw material would serve, with no direct release to the atmosphere

. Reduced sulfur compounds means H 2 S, carbonyl sulfide (COS), and carbon disulfide (CS 2 ). 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 sa les or expenditures exceeding $25 million (in second quarter 1980 dollars); or Deleted: sales

Deleted:

. ¶ Reduced emissions recompletion means a Deleted: completion following refracturing of a gas Deleted: where gas flowback Deleted: is otherwise vented is captured, cleaned, and routed Deleted: sales linePage 396 of 566 (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, standard s, 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 6 0. 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 Formatted: Font color: AutoPage 397 of 566

c hemical 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 , reg ardless 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 §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 ori ginal vessel was first located at the site. ( 2) Process vessels such as surge control vessels, bottoms receive rs or knockout vessels. (3) Pressure vessels designed to operate in excess of 204.9 kilopascals and without emissions to the atmosphere. Deleted: Sales line means pipeline, generally small in diameter, used to transport oil or gas from the well to a processing facility or a mainline pipeline. ¶

Deleted: a motor vehicle,

Deleted: ,

Deleted: ,Page 398 of 566 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 SO 2 equivalents means the sum of volumetric or mass concentrations of the sulfur compounds obtained by adding the quantity existing as SO 2 to the quantity of SO 2 that would be obtained if all reduced sulfur compounds were converted to SO 2 (ppmv or kg/dscm (lb/dscf)). Underground storage vessel means a storage vessel stored below ground. Deleted: tank Deleted: tankPage 399 of 566

Well means an oil or gas well, a hole drilled for the purpose of producing oil or gas, or a well into which fluids are injected. Well completion means the process that allows for the flow back 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

a ffected 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, tu bing 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. Deleted: flow

Deleted: steps Deleted: gas Deleted: Well completion also involve s connecting the well bore to the reservoir, which may include treating the formation or installing tubing, packer(s), or lifting equipment. Well completion begins with the flowback immediately following hydraulic fracturing or refracturing and ends when e ither (1) the well is shut in, or (2) the well is continuously producing to the sales line. Deleted: well recompletion with hydraulic fracturing Deleted: thePage 400 of 566

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 SO 2 Emission Reduction Efficiency (Z i )

H 2 S content of acid gas (Y), % Sulfur feed rate (X), LT/D 2.0 < X < 5.0 5.0<X < 15.0 15.0<X < 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, whichever is smaller 97.9 10 < Y<20 79.0 88.5X 0.0101 Y 0.0125 or 97.9, whichever is smaller 93.5 93.5

Y<10 79.0 79.0 79.0 79.0

Table 2 to Subpart OOOO of part 60

– Required Minimum SO 2 Emission Reduction Efficiency (Z c )

H 2 S content of acid gas (Y), % Sulfur feed rate (X), LT/D 2.0 < X < 5.0 5.0<X < 15.0 15.0<X < 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, whichever is smaller 97.5 10 < Y<20 74.0 85.35X 0.0144 Y 0.0128 or 90.8, whichever is smaller 90.8 90.8

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. Formatted: No underline, Font color: Auto, SubscriptPage 401 of 566 S = The sulfur production rate, kilograms per hour (kg/hr) [pounds per hour (lb/hr)], rounded to one decimal place. X = The sulfur feed rate from the sweetening unit ( i.e. , the H 2 S in the acid gas), expressed as su lfur, 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 H 2 S (dry basis) rounded to one decimal place. Z = The minimum required sulfur dioxide (SO2) emission reduction effici ency, expressed as percent carried to one decimal place. Z i refers to the reduction efficiency required at the initial performance test. Z c refers to the reduction efficiency required on a continuous basis after compliance with Z i has been demonstrated.

T able 3 to Subpart OOOO of part 60

– Applicability of General Provisions to Subpart OOOO As stated in §60.5425, you must comply with the following applicable General Provisions:

General Provisions Citation Subject of Citation Applies to subpart? Explanati on
§60.1 General applicability of the General Provisions Yes
§60.2 Definitions Yes Additional terms defined in §60.5430 §60.3 Units and abbreviations Yes §60.4 Address Yes §60.5 Determination of construction or modification Yes

§60.6 Review of plans Yes §60.7 Notification and record keeping Yes Except that §60.7 only applies as specified in §60.5420(a).Page 402 of 566

§60.8 Performance tests Yes Performance testing is required for control devices used on storage vessels and centrifugal compressors §60.9 Availability of information Yes §60.10 State authority Yes §60.11 Compliance with standards and maintenance requirements No Requirements are specified in subpart OOOO. §60.12 Circumvention Yes §60.13 Monitoring requirements Yes Continuous monitors are required for storage vessels §60.14 Modification Yes §60.15 Reconstruction Yes §60.16 Priority list Yes §60.17 Incorporations by reference Yes §60.18 General control device requirements Yes Except that §60.18 does not apply to flares. §60.19 General notification and reporting requirement Yes Deleted: No

Deleted: as specified in 40 CFR part 63, sub part HH.Page 403 of 566

**Subpart HH -**  **– [**  **Amended]** 10. Section 63.760 is amended by: a. Revising paragraph (a)(1) introductory text; b. Revising paragraph (a)(1)( i );

c . Revising paragraph (a)( 1)(iii ); d . Revising paragraph ( a)(2);

e . Revising paragraph (b)(1)( i ); f. Adding paragraph ( c);
g . Revising paragraph (f ) introductory text; h . Revising paragraph (f)( 1); i . Revising paragraph (f)( 2); j . Adding paragraphs (f)(7), (f)(8), and (f)(9 ) ; and k. Removing and reserving paragraph (g)(1 ) to read as follows: **§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 §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 owne r or operator of a Deleted: **PART 63 --**  **[Amended] ¶**  8. The authority citation for part 63 continues to read as follows: ¶ Authority: 42 U.S.C. 7401, et seq . ¶

9. Section 63.14 is amended by: ¶ a. Adding paragraphs (b)(69), (b)(70), (b)(71) and (b)(72); and ¶ b. Revising paragraph (i)(1) to read as follows: ¶ §63.14 Incorporations by reference. ¶ * * * * * ¶

(b) * * * ¶ * * * * * ¶

(69) ASTM D1945

– 03(2010) Standard Test Method for Analysis of Natural Gas by Gas Chromatography, IBR approved for §§63.772 and 63.1282. ¶

(70) ASTM D5504

- 08 Standard Test Method for Determination of Sulfur Compounds in Natural Gas and Gaseous Fuels by Gas Chromatography and Chemiluminescence , IBR approved for § §63.772 and 63.1282. ¶

(71) ASTM D3588

- 98(2003) Standard Practice for Calculating Heat Value, Compressibility Factor, and Relative Density of Gaseous Fuels, IBR approved for §§63.772 and 63.1282. ¶

(72) ASTM D4891

- 89(2006) Standard Test Method for Heatin g Value of Gases in Natural Gas Range by Stoichiometric Combustion, IBR approved for §§63.772 and 63.1282. ¶ * * * * * ¶

(i) * * * ¶ (1) ANSI/ASME PTC 19.10

– 1981, Flue and Exhaust Gas Analyses [Part 10, Instruments and Apparatus], issued August 31, 1981 IBR ap proved for §§63.309(k)(1)(iii), 63.771(e), 63.865(b), 63.1281(d), 63.3166(a)(3), 63.3360(e)(1)(iii), 63.3545(a)(3), 63.3555(a)(3), 63.4166(a)(3), 63.4362(a)(3), 63.4766(a)(3), 63.4965(a)(3), 63.5160(d)(1)(iii), 63.9307(c)(2), 63.9323(a)(3), 63.11148(e)(3) (iii), 63.11155(e)(3), 63.11162(f)(3)(iii) and (f)(4), 63.11163(g)(1)(iii) and (g)(2), 63.11410(j)(1)(iii), 63.11551(a)(2)(i)(C), 63.11646(a)(1)(iii), table 5 to subpart DDDDD of this part, and

... Deleted: iii Deleted: 2 Deleted: b)(1)(i); Deleted: ii Deleted: Revising Deleted: f) introductory text; Deleted: )(1); Deleted: and Deleted: iPage 404 of 566 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 §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 hydroca rbon liquid throughput, as appropriate, each year for the 5 years prior to **[INSERT DATE OF PUBLICATION IN THE FEDERAL REGISTER]**  , 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 thePage 405 of 566 maximum throughput used to determine whether a facility is a major source in accord ance 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 **[INSERT**
**DATE OF PUBLICATION IN THE FEDERAL REGISTER]**  , 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 **[INSERT DATE OF**
**PUBLICATON IN T HE FEDERAL REGISTER]**  , 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’sPage 406 of 566 maximum rate under its physical and operational design consistent with the definition of potential to emit in §63.2. (2) Facilities that process, upgra de, 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 wh ich 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 **[INSERT DATE OF PUBLICATION IN THE FEDERAL REGISTER]** , whichever Deleted: on or

Deleted: (ii) E ach storage vessel; ¶Page 407 of 566
is later, and each year thereafter , using gas composition data measured during the precedin g 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), (f)(2), and (f)(7) through (f)(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 (f)(6) of this section. (1) Except as specified in paragraphs (f)(7) through (9) of this section, the owner or ope rator 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 §63.6(i). The o wner 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 sh all 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 orPage 408 of 566

af ter 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 sect ion, 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 §63.761, located at a major source, that commenced construction before August 23, 2011, must achieve compliance no later than **[INSERT DATE 3**  **YEARS AND 60 DAYS**  **AFTER DATE OF PUBLICATION IN THE FEDERAL REGISTER]**  , except as provided in §63.6(i). (8) Each affected new small glycol dehydration unit , as defined in §63.761, located at a major source, that commenced construction on or after August 23, 2011, must achieve compliance immediately upon initial startup or **[INSERT DATE 60 DAYS AFTER DATE OF PUBLICATION IN THE FEDERAL REGISTER],**  whichever is later. (9) A production field facility, as defined in §63.761, constructed on or before August 23, 2011, that was previously determined to be an area source but becomes a major source (as Deleted: and each storage vessel that is not a storage vessel with the potential for flash emissions, both

Deleted: **THREE**

Deleted: and each storage vessel that is not a stora ge vessel with the potential for flash emissions, bothPage 409 of 566 defined in paragraph 3 of the major source definition in §63.761) on the **[INSERT DATE OF PUBLICATION IN THE FEDERAL REGISTER]**  must achieve compliance no later than **[INSERT DATE 3**
**YEARS AND 60 DAYS**  **AFTER DATE OF PUBLICATION IN THE FEDERAL REGISTER]**  , except as provided in §63.6(i). (g) * * * (1) [Reserved]
* * * * * 11. Section 63.761 is amended by: a. Adding, in alphabetical order, new definitions for the terms “affirmative defense,” “BTEX,” “flare,” “large glycol dehydration units,” “responsible official” and “small glycol dehydration units”; b. Revising the definitions for “associated equipment,” “glycol dehydration unit baseline operations,” and “storage vessel ”; and c. Revising paragraph (3) o f the definition for “major source” to read as follows: **§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 Deleted:

Deleted: ,” and “temperature monitoring devicePage 410 of 566 merits of which are independently and objectively evaluated in a judicial or administrativ e 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).Page 411 of 566 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, determin ed according to §63.772(b). A glycol dehydration unit complying with the 0.9 Mg/yr control option under § 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 similarPage 412 of 566 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 sub ject 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 adv ance 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 off icial. 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
EP A); 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 Formatted: Font color: AutoPage 413 of 566 (ii) The designated representative f or 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 annu al average benzene emissions less than 0.90 Mg/yr, determined according to §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.
* * * * * 12. Section 63.762 is revised to read as follows: **§63.762 Affirmative defense for violations of emission standard**  **s during malfunction**  **.** (a) The provisions set forth in this subpart shall apply at all times. (b) [Reserved] (c) [Reserved] Formatted: Font color: Auto

Deleted: * * * * * ¶ Temperature monitoring device means an instrument used to monitor temperature and having a minimum accuracy of ±1 percent of the temperature being monitored expressed in degrees C, or ±2.8 degrees C, whichever is greater. The temperature monitorin g device may measure temperature in degrees Fahrenheit or degrees Celsius, or both. ¶ Deleted: **Malfunctions**Page 414 of 566 (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 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 , t he affirmati ve 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, an d 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 fo r; and Deleted: excee dances

Deleted: ,

Deleted: . The

Deleted: limit Deleted: notification

Deleted: excess emissions

Deleted: Were

Deleted: and monitoring

Moved (insertion) [23]

Moved down [24]: ¶

(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 ¶Page 415 of 566
(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 overt ime 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 t he 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 p ractices; 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 Deleted: Were

Deleted: the applicable emission limitations were being exceeded.

Deleted: excess emissions

Deleted: during periods of such emissions Deleted: excess emissions

Deleted: excess emissions

Deleted: excess emissionsPage 416 of 566 (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 violat i on 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 init ial occurrence of the violation of the relevant standard (which may be the end of any applicable averaging period ). If s uch 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 e mission report due after the initial occurrence of the violation of the relevant standard

. 13. Section 63.764 is amended by:

a . Revising paragraph ( e)(1) introductory text; Deleted: excess emissions

Deleted: excess

Deleted: Notification . The owner or operator of the affected source experiencing exceedance of its emission limit(s) during a malfunction shall notify the Administrator by telephone or facsimile transmission as soon as possible, but no later than two business days after the initial occurrence of the malfunction, if it wishes to avail i tself of an affirmative defense to civil penalties for that malfunction Formatted: Font color: Auto Deleted: also Deleted: within 45 days of the initial occurrence of the exceedance of the standard in this subpart to demonstrate, Deleted: The owner or operator may seek an extension of this deadline for up to 30 addition al days by submitting a written request to the Administrator before the expiration of the 45 day Deleted: . Until a request for an extension has been approved by the Administrator, the owner or operator is subject to the requirement to submit Deleted: report within 45 days of

Deleted: exceedance

Deleted: c)(2) introductory text; ¶ b. Revising paragraph (Page 417 of 566

b . Revising paragraph (i); and

c . Adding paragraph (j) to read as follows: **§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 §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 det ected, 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 violati on 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 maint ain any affected source, including associated air pollution control equipment and monitoring equipment, in a manner consistent with safety and good air pollution control practices Deleted: c

Deleted: d

Deleted: (c) * * * ¶

(2) For each storage vessel subject to this subpart, the owner or operator shall comply with the requirements specified in paragraphs (c)(2)( i) through (iii) of this section. ¶ * * * * * ¶Page 418 of 566 for minimizing emissions. Determination of whether such operation and mainte nance 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 inspe ction of the source. 14. Section 63.765 is amended by: a. Revising paragraph (a); b. Revising paragraph (b)(1); c. Revising paragraph (c)(2); and d. Revising paragraph (c)(3) to read as follows: **§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 §63.764. (b) * * * (1) For each glycol dehydration unit proc ess 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 §63.761, shall connect the process vent to a control dev ice or a combination of control devices through a closed

- vent system. The closed

- vent system shall be designed and Deleted: ¶Page 419 of 566 operated in accordance with the requirements of §63.771(c). The control device(s) shall be designed and operated in accordance with the requi rements of §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 §63.771(c). The control device(s) shall be designed and operated in accordance with the requirem ents of §63.771(d), except that the performance levels specified in §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 §63.761, to the limit determined i n Equation 1 of this section. You must limit BTEX emissions from each new small glycol dehydration unit process vent, as defined in §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 with one of the alternatives specified in paragraphs (b)(1)(iii)(A) through (D) of this section.Page 420 of 566

Equation 1 Where:
EL BTEX = Unit

- specific BTEX emission limit, megagrams per year;

3.28x10 - 4 = BTEX emission limit, grams BTEX/standard cubic meter

- ppmv; Throughput = Annual average daily natural gas throughput, standard cubic meters per day
C i,BTEX = average annual BTEX concentration of the natural gas at the inlet to the glycol dehydration unit, ppmv.

Equation 2 Where:
EL BTEX = Unit

- specific BTEX emission limit, megagrams per year; 4.66x10 - 6 = BTEX emission limit, grams BTEX/standard cubic meter

- ppmv; Throughput = Annual average daily natural gas throughput, standard cubic meters per day

C i,BTEX = average annual BTEX concentration of the natural gas at the inlet to the glycol dehydration unit, ppmv. Deleted: Equation 1 ¶

Moved (insertion) [25]

Formatted: Line spacing: Double
Moved down [26]: Where: ¶ EL BTEX = Unit

- specific BTEX emission limit, megagrams per year; ¶

Moved (insertion) [27]

Moved (insertion) [26] Formatted: Line spacing: Double

Moved down [28]: C i,BTEX = average annual BTEX concentration of the natural gas at the inlet to the glycol dehydration unit, ppmv. Deleted: ¶ ¶ Equation 2 ¶ Where: ¶ EL BTEX = Unit

- specific BTEX emission limit, megagrams per year; ¶ Moved up [27]: C i,BTEX = average annual BTEX concentration of the natural gas at the inlet to the glycol dehydration unit, ppmv. ¶ Deleted: ¶ Moved (insertion) [28]Page 421 of 566
(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 §63.771(c). The control device(s) shall be designed and opera ted in accordance with the requirements of §63.771(f). (B) Meet the emissions limit through process modifications in accordance with the requirements specified in §63.771(e). (C) Meet the emissions limit for each small glycol dehydration unit using a com bination 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 g lycol dehydration unit. Document operational parameters in accordance with the requirements specified in §63.771(e) and emissions in accordance with the requirements specified in §63.772(b)(2).
* * * * * (c) * * * (2) The owner or operator shall demonst rate, 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 mo re Deleted: ¶Page 422 of 566 control devices, in accordance with the requirements specified in §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 emi ssions 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 th is 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 sma ll 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 l imit calculated by Equation 2 of paragraph (b)(1)(iii) of this section. 15. Section 63.766 is amended by:

a . Adding paragraph (b)(3); and b

. Revising paragraph (d) to read as follows: Deleted: Revising paragraph (a); ¶ b. Revising paragraph (b) introductory text; ¶ c. Revising paragraph (b)(1); ¶ d. Deleted: ePage 423 of 566

**§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 §63.771(c), to a process natural gas line.
* * * * * (d) This section does not apply to storage vessels for wh ich the owner or operator is subject to and controlled under the requirements specified in 40 CFR part 60, subpart s 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 §63.775(e). 16. Section 63.769 is amended by: a. Revising paragraph (b); b. Revising paragraph (c) introductory text; and

c . Revising paragraph (c)(8) to read as follows: **§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 subpa rt H of this Deleted: (a) This section applies to each storage vessel (as defined in §63.761) subject to this subpart. ¶

(b) The owner or operator of a storage vessel (as defined in §63.761) shall comp ly with one of the control requirements specified in paragraphs (b)(1) through (3) of this section. ¶

(1) The owner or operator shall equip the affected storage vessel with a cover that is connected, through a closed

- vent system that meets the conditions sp ecified in §63.771(c), to a control device or a combination of control devices that meets any of the conditions specified in §63.771(d). The cover shall be designed and operated in accordance with the requirements of §63.771(b). ¶ * *

Deleted: subpart Deleted: subpart

Deleted:

Deleted: ¶

Deleted: bPage 424 of 566

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 §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, §§61.241 through 61.247, except as specified in paragraphs (c)(1) through (8) of this section, except that for valves subject to §61.242

- 7(b) **or §61.243**  **- 1**  , a leak is detected if an instrument reading of 500 ppm or greater is measured. A leak dete cted from a valve at a source constructed on or before August 23, 2011 shall be repaired in accordance with the schedule in §61.242

- 7(d), or by **[INSERT DATE 1 YEAR**  **AND 60 DAYS AFTER THE DATE OF PUBLICATION IN THE FEDERAL REGISTER]**  , 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 §61.242

- 7(d), or by **[INSERT DATE 60 DAYS**  **AFTER THE DATE OF PUBLICATION IN THE FEDERAL REGISTER]** , whichever is later.
* * * * * (8) Flares, as defined in §63.761, used to comply with this subpart shall comply with the requirements of §63.11(b). Deleted: KKK or subpart OOOO.

Formatted: Font: 11 pt, Bold, No underline, Font color: Auto

Deleted: When a Deleted: is Deleted: it
Formatted: Font: Bold, No underline, Font color: Auto

Formatted: Font: Bold, No underline, Font color: AutoPage 425 of 566 17. Section 63.771 is amended by: a. Revising paragraph (c)(1) introductory text; b. Revising the heading of parag raph (d); c. Adding paragraph (d) introductory text; d. Revising paragraph (d)(1)(i)(C); e. Revising paragraph (d)(1)(ii); f. Revising paragraph (d)(1)(iii); g. Revising paragraph (d)(4)(i); h. Revising paragraph (d)(5)(i); i. Revising paragraph (e)(2); j. Revising paragraph (e)(3) introductory text; k. Revising paragraph (e)(3)(ii); and l. Adding paragraph (f) to read as follows: **§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 d ehydration units

. Owners and operators of small glycol dehydration units, shall comply with the control device requirements in paragraph (f) of this section.Page 426 of 566
(1) * * * (i) * * * (C) Operates at a minimum temperature of 760 degrees C, provided the cont rol device has demonstrated, under §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 §63.772(e). (iii) A flare, as defined in §63.76 1, that is designed and operated in accordance with the requirements of §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 emission s unit or units through the closed

- vent system to the control device, as required under §63.765, §63.766, and §63.769. An owner or operator may vent more than one unit to a control device used to comply with this subpart. Deleted: controlPage 427 of 566

* * * * * (5) * * * (i) Followin g 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 §63.774(b)(7)(ix). The schedule for replacement shall be submitted with the Notification of Compliance Status Report as specified in §63.775 (d)(5)(iv). Each carbon replacement must be reported in the Periodic Reports as specified in §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 §63.765(b)(1)(iii), as applicable, either through process modifications or through a combination of process modif ications 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 thePage 428 of 566 emission reduction to be achieved by the control device to achieve an overall HAP e mission reduction of 95.0 percent for the glycol dehydration unit process vent or, if applicable, the BTEX limit determined in §63.765(b)(1)(iii) for the small glycol dehydration unit process vent. Only modifications in glycol dehydration unit operations d irectly 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 t he 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 §63.765(b)(1)(iii), as applicable, using process modifications alone shall comp ly 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 §63.765(b)(1)(iii), as applicable, using a combination of process modifications and one or more con trol 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 em ission reduction orPage 429 of 566

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 B TEX the emission limit calculated in §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, b oiler, 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 zon e 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 §63.772(e). (B) The concentration of either TOC or total HAP in the exhaust gases at the out let 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 §63.772(e).Page 430 of 566 (ii) A vapor recovery device ( e.g. , carbon adsorpti on 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 §63.772(e). (iii) A flare, as defined i n §63.761, that is designed and operated in accordance with the requirements of §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) Eac h 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 require ments of §63.773(d), the owner or operator shall demonstrate compliance according to the requirements of either §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
sect ion, the owner or operator shall manage the carbon as required under (d)(5)(i) and (ii) of this section. 18. Section 63.772 is amended by: a. Revising paragraph (b) introductory text;Page 431 of 566 b. Revising paragraph (b)(1)(ii); c. Revising paragraph (b)(2); d. Revising paragraph (c)(6)(i); e. Adding paragraph (d); f. Revising paragraph (e) introductory text; g. Revising paragraphs (e)(1)(i) through (v); h. Revising paragraph (e)(2); i. Revising paragraph (e)(3) introductory text; j. Revising paragraph (e)( 3)(i)(B); k. Revising paragraph (e)(3)(iv)(C)( 1 ); l. Adding paragraphs (e)(3)(v) and (vi); m. Revising paragraph (e)(4) introductory text; n. Revising paragraph (e)(4)(i); o. Revising paragraph (e)(5); p. Revising paragraph (f) introductory text;

q. Revising paragraph (f)(2) and paragraph (f)(3); r. Adding paragraphs (f)(4) through (f)(6); s. Revising paragraph (g) introductory text; t. Revising paragraph (g)(1) and paragraph (g)(2) introductory text; u. Revising paragraph (g)(2)(iii); v. Revis ing paragraph (g)(3); w. Adding paragraph (h); and x. Adding paragraph (i) to read as follows:Page 432 of 566 **§63.772 Test methods, compliance procedures, and compliance demonstrations.** 
* * * * * (b) Determination of glycol dehydration unit flowrate, benzene emissio ns, 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

A dministrator'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 parag raph (b)(2)(i) or (b)(2)(ii) of this section. Emissions shall be determined either uncontrolled, or with federally enforceable controls in place. (i) The owner or operator shall determine actual average benzene or BTEX emissions using the model GRI

- GLYCal c 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) reportPage 433 of 566 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 emi ssions in kilograms per hour through direct measurement using the methods in §63.772(a)(1)(i) or (ii), or an alternative method according to §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 Meth od 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.
* * * * *Page 434 of 566
(d) Test procedures and compliance dem onstrations 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 §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 §63.765(b)(1)(iii), the owner or operator must determine t he 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 ca lculated using the equation in §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.Page 435 of 566 (iii) The BTEX emissions from the outlet of the glycol dehydratio n unit process vent shall be determined using the procedures specified in paragraph (e)(3)(v) of this section. As an alternative, the mass rate of BTEX at the outlet of the glycol dehydration unit process vent may be calculated using the model GRI

- GLYCalc T M , Version 3.0 or higher, and the procedures presented in the associated GRI

- GLYCalc TM Technical Reference Manual. Inputs to the model shall be representative of actual operating conditions of the glycol dehydration unit and shall be determined using the procedures documented in the Gas Research Institute (GRI) report entitled “Atmospheric Rich/Lean Method for Determining Glycol Dehydrator Emissions” (GRI

– 95/0368.1). When the BTEX mass rate is calculated for glycol dehydration units using the model GRI

- GLYCalc TM , all BTEX measured by Method 18, 40 CFR part 60, appendix A, shall be summed. (e) Control device performance test procedures . This paragraph applies to the performance testing of control devices. The owners or operators shall demonstrate that a control device achieves the performance requirements of §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 altern ative procedures in paragraph (e)(5) ofPage 436 of 566 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 co nducting a performance test under this section for combustion control devices, a control device that can be demonstrated to meet the performance requirements of §63.771(d)(1), (e)(3)(ii) or (f)(1) through a performance test conducted by the manufacturer, a s 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 §63.761, that is designed and operated in accordance with §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 str eam 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 fi nal permit under 40 CFR part 270 and complies with thePage 437 of 566 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 dehydra tion 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 requirement s of 40 CFR part 265, subpart O.
* * * * * (2) An owner or operator shall design and operate each flare, as defined in §63.761, in accordance with the requirements specified in §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 §63.771(d)(1), (e)(3)(ii) or (f)(1), the owner or operator shall use the test methods and p rocedures 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) * * *Page 438 of 566 (B) To determine compliance with the enclosed combustion device total HAP concentration limit specified in §63.771(d)(1)(i)(B), or the BTEX emission limit specified in §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, 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 §63.765(b)(1)(iii) the owner or operator shall use one of the following methods: Meth od 18, 40 CFR part 60, appendix A; ASTM D6420

– 99 (2004), as specified in §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 sha ll be used to calculate BTEX emissions:Page 439 of 566 (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 approxim ately equal intervals in time, such as 15

- minute intervals during the run. (B) The mass rate of BTEX (E o ) 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 sh all be used:

Where:
E o = Mass rate of BTEX at the outlet of the control device, dry basis, kilogram per hour.
C oj = Concentration of sample component j of the gas stream at the outlet of the control device, dry basis, parts per million by volume.
M oj = Molecular weight of sample component j of the gas stream at the outlet of the control device, gram/gram

- mole. Q o = Flowrate of gas stream at the outlet of the control device, dry standard cubic meter per minute.

K 2 = Constant, 2.494×10 − 6 (parts per million) (gram

- mole per standard cubic meter) (kilogram/gram) (minute/hour), where Deleted: ¶ Formatted: Font: (Default) Courier New, 12 pt, No underline, Font color: Auto Formatted: Line spacing: DoublePage 440 of 566
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 measure d by Method 18, 40 CFR part 60, appendix A, or ASTM D6420

– 99 (2004) as specified in §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 t o 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 §63.760(f)(7) through (8), except tha t 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 **[INSERT DATE 3**
**YEARS AFTER DATE OF PUBLICATION IN THE FEDERAL REGISTER]**  . 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 §63.772(h), then the newly installed device shall comply with all pr ovisions of this subpart no later than **[INSERT DATE 3 YEARS AFTER DATE OF PUBLICATION IN THE FEDERAL REGISTER]**  . The performance test Deleted: at existing

Deleted: an existingPage 441 of 566 results shall be submitted in the Notification of Compliance Status Report as required in §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 m onths 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 sour ce desires to establish a new operating limit. The periodic performance test results must be submitted in the next Periodic Report as specified in §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, §63.772(h), or ( 2 ) A combustion control device demonstrating during the performance test under §63.772( e) that combustion zone temperature is an indicator of destruction efficiency and operates at a minimum temperature of 760 degrees C.Page 442 of 566 (4) For a condenser design analysis conducted to meet the requirements of §63.771(d)(1), (e)(3)(ii), or (f)(1), the owner or operator shall meet the requirements specified in paragraphs (e)(4)(i) and (e)(4)(ii) of this section. Documentation of the design analysis shall be submitted as a part of the Notification of Compliance Status Report as required in §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 D etermining 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. Deleted:Page 443 of 566
(f) Compliance demonstration for control device performance requirements

. This paragraph applies to the demonstration of compliance with the control device performance requirements specified in §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 al ternative, an owner or operator that installs a condenser as the control device to achieve the requirements specified in §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 swi tch 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 re ported in the next Periodic Report, as required in §63.775(e), following the change.
* * * * * (2) The owner or operator shall calculate the daily average of the applicable monitored parameter in accordance with §63.773(d)(4) except that the inlet gas flo wrate 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 isPage 444 of 566 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 establ ished under §63.772(h ) or under the performance test conducted under §63.772(3), as applicable. (4) Except for periods of monitoring system malfunctions, repairs associated with monitoring system malfunctions, and required monitoring system quality assu rance or quality control activities (including, as applicable, system accuracy audits and required zero and span adjustments), the CMS required in §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 req uired 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 malfun ctions, or required monitoring system quality assurance or control Deleted: ).Page 445 of 566 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
t he 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
contr ol 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 §63.771(d)(1)(ii),(e)(3) or (f)(1) for condensers. Compliance shall be demonstrated using the procedures in paragr aphs (g)(1) through (3) of this section. (1) The owner or operator shall establish a site

- specific condenser performance curve according to §63.773(d)(5)(ii). For sources required to meet the BTEX limit in accordance with §63.771(e) or (f)(1) the owner or operator shall identify the minimum percent reduction necessary to meet the BTEX limit.Page 446 of 566 (2) Compliance with the requirements in §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 secti on. * * * * * (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 §63.771(e), the 365

- day ave rage 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 §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 thePage 447 of 566 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 §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 p ercent 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 §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 §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 identif ied under paragraph (g)(1) of this section ( i.e. , at least 76.0 percent if the 365

- day design value is 80.0 percent).Page 448 of 566
(3) If the owner or operator has data for 365 days or more of operation, compliance is achieved based on the applicable criteria in par agraphs (g)(3)(i) or (ii) of this section. (i) For sources meeting the HAP emission reduction specified in §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 §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 redu ction identified in paragraph (g)(1) of this section.
* * * * * (h) Performance testing for combustion control devices

- manufacturers’ performance test. (1) This paragraph applies to the performance testing of a combustion control device conducted by the device manufacturer. The manufacturer shall demonstrate that a specific model of control device achieves the performance requirements in (h)(7) of this section by conducting a performance test as specified in paragraphs (h)(2) through (6) of this section. (2) Performance testing shall consist of three one

- hour (or longer) test runs for each of the four following firing rate settings making a total of 12 test runs per test. PropenePage 449 of 566 (propylene) gas shall be used for the testing fuel. All fuel analyses shal l 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 7 0 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 ra te 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

- 3 0

- 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 0Page 450 of 566 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. Resu lts 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 el ectronic 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 se ction. (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. Deleted: fuel

Deleted: fuel

Deleted: fu el

Deleted: fuelPage 451 of 566
(iii) Inlet gas fuel sampling shall be conducted in accordance with the criteria in paragraphs (h)(4)(iii)(A) and (B) of t his 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. ( 2 ) Hydrogen (H 2 ), carbon monoxide (CO), carbon dioxide (CO 2 ), nitrogen (N 2 ), oxygen (O 2 ) using ASTM D1945

- 03. Deleted: fuel

Deleted: 1

Deleted: fuelPage 452 of 566
( 3 ) Higher heating value using ASTM D3588

- 98 or ASTM D4891

- 89. (5) Outlet testing shall be conducted in accordance with the criteria in paragraphs (h)(5)(i) through (v) of this section. (i) Sampling and flowrate measured in accordance with the following: (A) The outlet sampling location shall be a minimum of 4 equivalent stack diameters downstream from the highest peak flame or any other flow disturbance, and a minimum of one equivalent stack diameter upstream of the exit or any other flow disturbance. A minimum of two sample ports shall be used. (B) 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 meas ure 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 accurat e flow profile. (ii) Molecular weight shall be determined as specified in paragraphs (h)(4)(iii)(B), (h)(5)(ii)(A), and (h)(5)(ii)(B) of this section.Page 453 of 566 (A) An integrated bag sample shall be collected during the Method 4, 40 CFR part 60, Appendix A, moistu re 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 l ocation. ( 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
concentrat ion 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 o f: O 2 , CO 2 , methane (CH4), and N 2 and include in the test report submitted under §63.775(d)(iii). Moisture shall be determined using Method 4, 40 CFR part 60, Appendix A. Traverse both ports with the Method 4,Page 454 of 566 40 CFR part 60, Appendix A, sampling train du ring each test run. Ambient air shall not be introduced into the Method 3C, 40 CFR part 60, Appendix A, integrated bag sample during the port change. (iii) Carbon monoxide shall be determined using Method 10, 40 CFR part 60, Appendix A. The test shall be run at the same time and with the sample points used for the EPA Method 25A, 40 CFR part 60, Appendix A, testing. An instrument range of 0

- 10 per million by volume

- dry (ppmvd) shall be used. (iv) Visible emissions shall be determined using Method 22, 40 C FR 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 p hotos 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. (6) Total hydrocarbons (THC) shall be determined as specified by the fol lowing 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 THCPage 4 55 of 566
probe must be traversed to 16.7 percent, 50 percent, and 8 3.3 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) measur ement 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 C alibration 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 CO 2 , 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:Page 456 of 566 (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 CO 2 , 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 CO 2 . (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 secti on. (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 §63.775(d)(1)(iii).Page 457 of 566
(i) Full schematic of the control device and dimensions of the d evice 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) Pilo t flame design fuel and fuel usage. (K) Tip velocity range. (L) Momentum flux ratio. (M) Exit temperature range. (N) Exit flowrate.Page 458 of 566 (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 demo nstration 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 §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 §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 §63.773(d)(3)(i)(H)( 2 ). (3) Devices shall be operated with no visible emissions, except for periods not to exceed a total of 2 minutes during any hour. A visible emissions test using Method 22, 40 CFR part 60, Appendix A, shall be performed each calendar quarter. ThePage 459 of 566 observation period shall be 1 hour and shall be conducted according to EPA Method 22, 40 CFR part 60, Appendix A. (4) Com pliance 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 v isible 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 acti vities 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 descr ibed in paragraph (i)(3) of this section. 19. Section 63.773 is amended by: a. Adding paragraph (b); b. Revising paragraph (d)(1) introductory text; Deleted: 1 minutePage 460 of 566 c. Revising paragraph (d)(1)(ii) and adding paragraphs (d)(1)(iii) and (iv); d. Revising paragraph ( d)(2); e. Revising paragraph (d)(3)(i)(A ); f. Revising paragraph (d)(3)(i)(D ); g. Revising paragraph (d)(3)(i)(G); h . Adding paragraph (d)(3)(i)(H); i. Revising paragraph (d)(4); j. Revising paragraph (d)( 5)(i ); k. Revising paragraphs (d)(5)(ii)(A) through (C); l . Revising paragraph (d)(6) introductory text;

m . Revising paragraphs (d)(6)(ii) and (iii);

n . Adding paragraph (d)(6)(vi);

o . Revising paragraph (d)(7); and

p . Removing paragraphs (d)(8) and (d)(9) to read as follows: **§63.773 Inspection and monitoring requirements.** 
* * * * * (b) The owner or operator of a control device whose model was tested under §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 ea ch control device with Deleted: paragraphs Deleted: ) and (B Deleted: paragraphs Deleted: ) and (E Deleted: paragraphs (d)(3)(i)(F)( 1 ) and ( 2 ); ¶ h. Revising Deleted: i

Deleted: 4

Deleted: paragraph (d)(5)(i); ¶ l. Revising Deleted: m

Deleted: n

Deleted: o

Deleted: p

Deleted: qPage 461 of 566 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 §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 §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 t he monitoring system design, data collection, and the quality assurance and quality control elements outlined in paragraph (d) of this section and in §63.8(d). Each CPMS must be installed, calibrated, operated, and maintained in accordance with the procedu res in your approved site

- specific monitoringPage 462 of 566 plan. Using the process described in §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) throug h (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 proced ures in accordance with provisions in §63.8(c)(1) and (c)(3); and (E) Ongoing reporting and recordkeeping procedures in accordance with provisions in §63.10(c), (e)(1), and (e)(2)(i). (iii) The owner or operator must conduct the CPMS equipment performan ce 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

m onitoring plan.Page 463 of 566 (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 §63.772(e) that the combustion zone temperature is an accurate indicator of performance, a tempe rature monitoring device equipped with a continuous recorder. The monitoring device shall have a minimum accuracy of ± 2 percent of the temperature being monitored in ° C, or ±2. 5 ° 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 Deleted: 1 Deleted: degrees Deleted: 8 degrees Deleted: (B) For a catalytic vapor incinerator, a temperature monitoring device equipped with a continuous recorder. The device shall be capable of monitoring temperature at two locatio ns and have a minimum accuracy of ±1 percent of the temperature being monitored in degrees C, or ±2.8 degrees C, whichever value is greater. One temperature sensor shall be installed in the vent stream at the nearest feasible point to the catalyst bed inle t and a second temperature sensor shall be installed in the vent stream at the nearest feasible point to the catalyst bed outlet. ¶Page 464 of 566

temper ature monitoring device shall have a minimum accuracy of

± 2 percent of the temperature being monitored in ° C, or ±2. 5 ° C, whichever value is greater. The temperature sensor shall be installed at a location representative of the combustion zone temperature. * * * * * (G) For a n onregenerative

- type carbon adsorption system, the owner or operator shall monitor the design carbon replacement interval established using a performance test performed in accordance with §63.772(e)(3) shall be based on the total carbon working capacity of the control device and source operating schedule. (H) For a control device model whose model is tested under §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 high er, 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 §63.772(i)(3); ( 2 ) A heat sensing monitoring device equipped with a continuous recorder that indicates the continuous ignition of the pilot flame.
* * * * * Deleted: 1 Deleted: degrees Deleted: 8 degrees

Deleted: (E) For a condenser, a temperature monitoring device equipped with a continuous recorder. The temperature monitoring device shall have a minimum accuracy of ±1 percent of the temperature being monitored in degrees C, or ±2.8 degrees C, whichever value is greater. The temperature sensor shall be installed at a location in the exhaust vent stream from the condenser. ¶

(F) * * * ¶ ( 1 ) A continuous parameter monitoring system to measure and record the average total regeneration stream mass flow or volumetric flow during each carbon bed regeneration cycle. The flow sensor must have a measurement sensitivity of 5 percent of the flowrate or 10 cubic feet per minute, whichever is greater. The mechanical connections for leakage must be checked at least every month, and a visual inspection must be performed at least every 3 months of all components of the flow CPMS for physical and operational integrity and all electrical connections for oxidation and galvanic corrosion if your flow CPMS is not equ ipped with a redundant flow sensor; and ¶

( 2 ) A continuous parameter monitoring system to measure and record the average carbon bed temperature for the duration of the carbon bed steaming cycle and to measure the actual carbon bed temperature after regenera tion and within 15 minutes of completing the cooling cycle. The temperature monitoring device shall have a minimum accuracy of ±1 percent of the temperature being monitored in degrees C, or ±2.8 degrees C, whichever value is greater. ¶Page 465 of 566 (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 h ours 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 para meter 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 §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 §63.772(e)(3) to demonstrate that the control device achieves the ap plicable performance requirements specified in §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 Deleted: ¶Page 466 of 566 measured during the performance test and supplement ed, 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 §63.772(e)(4) to demonstrate tha t the control device achieves the applicable performance requirements specified in §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 a nalysis 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 §63.772(h) to demonstrate that the control device achieves the app licable performance requirements specified in §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 §63.772(e)(3) to demonstrate that the condenser achieves the applicable performance requirements in §63.771(d)(1), (e)(3)(ii) or (f)(1), then the condenser performa nce curve shall be based on values measuredPage 467 of 566 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 contro l device design analysis in accordance with the requirements of §63.772(e)(4)(i) to demonstrate that the condenser achieves the applicable performance requirements specified in §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 (d)(6)(vi) of this section being met. When multiple operating parameters ar e monitored for the same control device and during the same operating day and more than one of these operating parameters meets an excursion criterionPage 468 of 566 specified in paragraphs (d)(6)(i) through (d)(6)(vi) of this section, then a single excursion is determin ed to have occurred for the control device for that operating day.
* * * * * (ii) For sources meeting §63.771(d)(1)(ii), an excursion occurs when the 365

- day average condenser efficiency calculated according to the requirements specified in §63.772(g)(2)( iii) is less than 95.0 percent. For sources meeting §63.771(f)(1), an excursion occurs when the 365

- day average condenser efficiency calculated according to the requirements specified in §63.772(g)(2)(iii) is less than 95.0 percent of the identified 365

- da y required percent reduction. (iii) For sources meeting §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 §63.772(g)(2)( iii)(A) or (B) is less than 90.0 percent. For sources meeting §63.771(f)(1), an excursion occurs when the 365

- day average condenser efficiency calculated according to the requirements specified in §63.772(g)(2)(iii) is less than the identified 365

- day requ ired percent reduction.
* * * * * (vi) For control device whose model is tested under §63.772(h) an excursion occurs when:Page 469 of 566 (A) The inlet gas flowrate exceeds the maximum established during the test conducted under §63.772(h). (B) Failure of the quarterl y visible emissions test conducted under §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.
* * * * * 20. Section 63.774 is amended by: a. Revising paragraph (b)(3) introductory text; b. Removing and reserving paragraph (b)(3)(ii); c. Revising paragraph (b)(4)(ii) introductory text; d. Adding paragraph (b)(4)(ii)(C); e. Revising paragraph (b)(4)(iii); f. Adding paragraph (b)(7)(ix); and g. Adding paragraphs (g) through (i) to read as follows: **§63.774 Recordkeeping requirements.** 
* * * * * (b) * * * (3) Records specified in §63.10(c) for each monitoring system operated by the owner or operator in accordance with the requirements of §63.773(d). Notwithstanding the requirements ofPage 470 of 566 §63.10(c), monitoring data recorded during periods identified in paragraphs (b)(3)(i) through (b)(3)(iv) of this section shall not be included in any average or percent leak rate computed under this subpart. Records shall be kept of the times and durations of all such periods and any other periods during process or control device operation when monitors are not operating or failed to collect required data.
* * * * * (ii) [Reserved]
* * * * * (4) * * * (ii) Records of the daily average value of each continuously monitored parameter for each operating day determined according to the proced ures specified in §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 §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.
* * * * *Page 471 of 566
(7) * * * (ix) Records identifying the carbon replacement schedule under §63.771(d)(5) an d 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 c ontrol equipment and monitoring equipment. The owner or operator shall maintain records of actions taken during periods of malfunction to minimize emissions in accordance with §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 §63.772(h) to comply with §63.771(d), (e)(3)(ii) and (f)(1): (1) All visible emiss ion readings and flowrate calculations made during the compliance determination required by §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 und er §63.773(b) is performed. Include a list of any Deleted: aPage 472 of 566 modifications or repairs made to the control device during the inspection and other maintenance performed such as cleaning of the fuel nozzles. 21. Section 63.775 is amended by: a. Revising paragraph (b)( 1); b. Revising paragraph (b)(6); c. Removing and reserving paragraph (b)(7); d. Revising paragraph (c)(1); e. Revising paragraph (c)(6); f. Revising paragraph (c)(7)(i); g. Revising paragraph (d)(1)(i); h. Revising paragraph (d)(1)(ii) introductory text; i. Revising paragraph (d)(5)(ii); j. Adding paragraph (d)(5)(iv); k. Revising paragraph (d)(11); l. Adding paragraphs (d)(13) and (d)(14); m. Revising paragraphs (e)(2) introductory text, (e)(2)(ii)(B) and (C); n. Adding paragraphs (e)(2)(ii) (E) and (F);

o . Adding paragraphs (e)(2)(xi) through (xiii); and p. Adding paragraph (g) to read as follows: **§63.775 Reporting requirements.** 
* * * * * (b) * * *Page 473 of 566 (1) The initial notifications required for existing affected sources under §63.9(b)(2) shal l be submitted as provided in paragraphs (b)(1)(i) and (ii) of this section. (i) Except as otherwise provided in paragraph (ii), the initial notifications shall be submitted by 1 year after an affected source becomes subject to the provisions of this subp art 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 §63.760(f)(7) or (9) shall submit an initial notification required for existing affected sources under §63.9(b)(2) within 1 year after the affected source becomes subject to the provisions of this subpart or by **[INSERT DATE 1**  **YEAR AFTER DATE OF PUBLICATION IN THE FEDERAL REGISTER]**  **,** whichever is later. An affected source identified under §63.760(f)(7) or (9) that plans to be an area source by **[INSERT DATE 3**  **YEARS AFTER DATE OF PUBLICATION IN THE FEDERAL REGISTER]**  **,** shall include in this notification a brief, nonbinding description of a schedule for the action(s) that are planned to achieve area source status.
* * * * * Deleted: **ONE**

Deleted: **THREE**Page 474 of 566 (6) If there was a malfunction during t he 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 §63.764(j), including actions taken to co rrect a malfunction. (7) [Reserved]
* * * * * (c) * * * (1) The initial notifications required under §63.9(b)(2) not later than January 3, 2008. In addition to submitting your initial notification to the addressees specified under §63.9(a), you must als o submit a copy of the initial notification to the EPA's Office of Air Quality Planning and Standards. Send your notification via e

- mail to Oil and Gas Sector@epa.gov or via U.S. mail or other mail delivery service to U.S. EPA, Sector Policies and Programs Division/Fuels and Incineration Group (E143

– 01), Attn: Oil and Gas Project Leader, Research Triangle Park, NC 27711.
* * * * *Page 475 of 566 (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 descri ption of actions taken by an owner or operator during a malfunction of an affected source to minimize emissions in accordance with §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) * * *Page 476 of 566 (i) The condenser design analysis documentation specified in §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 specifi ed 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 §63.772(e)(3) and that the test con ditions are representative of current operating conditions. If the owner or operator operates a combustion control device model tested under §63.772(h), an electronic copy of the performance test results shall be submitted via email to Oil

_ and

_ Gas

_ PT@EP A.GOV unless the test results for that model of combustion control device are posted at the following website: 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 §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 Formatted: No underline, Font color: Auto Deleted:

Formatted: No underline, Font color: Auto Deleted:

Formatted: No underline, Font color: Auto Deleted:

Formatted: No underline, Font color: Auto Formatted: No underline, Font color: AutoPage 477 of 566 device is operating in accordance with the appl icable requirements of §63.771(d)(1), (e)(3)(ii) or (f)(1).
* * * * * (iv) For each carbon adsorber, the predetermined carbon replacement schedule as required in §63.771(d)(5)(i).
* * * * * (11) The owner or operator shall submit the analysis prepared un der §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 §63.765(b)(1)(iii), through process modifications or a combination of process modifications a nd one or more control devices.
* * * * * (13) If the owner or operator installs a combustion control device model tested under the procedures in §63.772(h), the data listed under §63.772(h)(8). (14) For each combustion control device model tested under
§ 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.Page 478 of 566
(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 speci fied 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 §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 §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.
* * * * *Page 479 of 566 (E) For each excursion caused when the maximum inlet gas flowrate identified under § 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 §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 §63.772(e) (3) conducted during the reporting period. (xii) For each carbon adsorber used to meet the control device requirements of §63.771(d)(1), records of each carbon replacement that occurred during the reporting period. (xiii) For combustion control device i nspections conducted in accordance with §63.773(b) the records specified in §63.774(i). (ix) Certification by a responsible official of truth, accuracy, and completeness. This certification shall state that, based on information and belief formed after re asonable inquiry, the statements and information in the document are true, accurate, and complete.
* * * * *Page 480 of 566
(g) Electronic reporting . (1) Within 60 days after the date of completing each performance test(defined in §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). Performa nce 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 me thods on the ERT website 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 subm it 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 confidentialPage 481 of 566 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 par agraph (g)(1) of this section must be sent to the Administrator at the appropriate address listed in §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 med ia 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. 22. Appendix to subpart HH of part 63 is amended by revising Table 2 to rea d as follows: **Appendix to Subpart HH of Part 63 —**  **Tables**
* * * * * **Table 2 to Subpart HH of Part 63 —**  **Applicability of 40 CFR Part 63 General Provisions to Subpart HH**  **General provisions reference**  **Applicable to**  **subpart HH**  **Explanation**

§63.1(a)(1) Yes. §63.1(a)(2) Yes. §63.1(a)(3) Yes. §63.1(a)(4) Yes. §63.1(a)(5) No Section reserved. §63.1(a)(6) Yes. §63.1(a)(7) through (a)(9) No Section reserved. §63.1(a)(10) Yes. §63.1(a)(11) Yes. §63.1(a)(12) Yes. Formatted: Font color: Auto

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§63.1(b)(1) No Subpart HH specifies applicability. §63.1(b)(2) No Section reserved. §63.1(b)(3) Yes. §63.1(c)(1) No Subpart HH specifies applicability. §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 §63.760(h). §63.1(c)(3) and (c)(4) No Section reserved. §63.1(c)(5) Yes. §63.1(d) No Section reserved. §63.1(e) Yes. §63.2 Yes Except definition of major source is unique for this source category and there are additional definitions in subpart HH. §63.3(a) through (c) Yes. §63.4(a)(1) through (a)(2) Yes. §63.4(a)(3) through (a)(5) No Section reserved. §63.4(b) Yes. §63.4(c) Yes. §63.5(a)(1) Yes. §63.5(a)(2) Yes. §63.5(b)(1) Yes. §63.5(b)(2) No Section reserved. §63.5(b)(3) Yes. §63.5(b)(4) Yes. §63.5(b)(5) No Section Reserved. §63.5(b)(6) Yes. §63.5(c) No Section reserved. §63.5(d)(1) Yes. §63.5(d)(2) Yes. §63.5(d)(3) Yes. §63.5(d)(4) Yes. §63.5(e) Yes. §63.5(f)(1) Yes. §63.5(f)(2) Yes. §63.6(a) Yes. §63.6(b)(1) Yes.Page 483 of 566

§63.6(b)(2) Yes. §63.6(b)(3) Yes. §63.6(b)(4) Yes. §63.6(b)(5) Yes. §63.6(b)(6) No Section reserved. §63.6(b)(7) Yes. §63.6(c)(1) Yes. §63.6(c)(2) Yes. §63.6(c)(3) through (c)(4) No Section reserved. §63.6(c)(5) Yes. §63.6(d) No Section reserved. §63.6(e) Yes. §63.6(e)(1)(i) No See §63.764(j) for general duty requirement. §63.6(e)(1)(ii) No. §63.6(e)(1)(iii) Yes. §63.6(e)(2) No Section reserved. §63.6(e)(3) No. §63.6(f)(1) No. §63.6(f)(2) Yes. §63.6(f)(3) Yes. §63.6(g) Yes. §63.6(h)(1) No. §63.6(h )(2) through (h)(9 ) Yes. §63.6(i)(1) through (i)(14) Yes. §63.6(i)(15) No Section reserved. §63.6(i)(16) Yes. §63.6(j) Yes. §63.7(a)(1) Yes. §63.7(a)(2) Yes But the performance test results must be submitted within 180 days after the compliance date. §63.7(a)(3) Yes. §63.7(b) Yes. §63.7(c) Yes. §63.7(d) Yes. §63.7(e)(1) No. §63.7(e)(2) Yes. §63.7(e)(3) Yes. §63.7(e)(4) Yes. §63.7(f) Yes. §63.7(g) Yes. §63.7(h) Yes.Page 484 of 566

§63.8(a)(1) Yes. §63.8(a)(2) Yes. §63.8(a)(3) No Section reserved. §63.8(a)(4) Yes. §63.8(b)(1) Yes. §63.8(b)(2) Yes. §63.8(b)(3) Yes. §63.8(c)(1) No. §63.8(c)(1)(i) §63.8(c)(1)(ii) §63.8(c)(1)(iii) No. Yes. No . §63.8(c)(2) Yes. §63.8(c)(3) Yes. §63.8(c)(4) Yes. §63.8(c)(4)(i) No Subpart HH does not require continuous opacity monitors. §63.8(c)(4)(ii) Yes. §63.8(c)(5) through (c)(8) Yes. §63.8(d) Yes. §63.8(d)(3) Yes. Except for last sentence, which refers to an SSM plan. SSM plans are not required. §63.8(e) Yes Subpart HH does not specifically require continuous emissions monitor performance evaluation, however, the Administrator can request that one be conducted. §63.8(f)(1) through (f)(5) Yes. §63.8(f)(6) Yes. §63.8(g) No Subpart HH specifies continuous monitoring system data reduction requirements. §63.9(a) Ye s. §63.9(b)(1) Yes. §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 §63.764(e) do not have to submit initial notifications. §63.9(b)(3) No Section reserved. §63.9(b)(4) Yes. §63.9(b)(5) Yes. §63.9(c) Yes. Deleted: PendingPage 485 of 566

§63.9(d) Yes. §63.9(e) Yes. §63.9(f) Yes. §63.9(g) Yes. §63.9(h)(1) through (h)(3) Yes Area sources located outside UA plus offset and UC boundaries are not required to submit notifications of compliance status. §63.9(h)(4) No Section reserved. §63.9(h)(5) through (h)(6) Yes. §63.9(i) Yes. §63.9(j) Yes. §63.10(a) Yes. §63.10(b)(1) Yes §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. §63.10(b)(2) Yes. §63.10(b)(2)(i) No. §63.10(b)(2)(ii) No See §63.774(g) for recordkeeping of (1) occurrence and duration and (2) actions taken during malfunctions. §63.10(b) (2)(iii) Yes. §63.10(b)(2)(iv) through (b)(2)(v) No. §63.10(b)(2)(vi) through (b)(2)(xiv) Yes. §63.10(b)(3) Yes §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. §63.10(c)(1) Yes. §63.10(c)(2) through (c)(4) No Sections reserved. §63.10(c)(5) through (8) (c)(8) Yes. §63.10(c)(9) No Section reserved. §63.10(c)(10) through (11) No See §63.774(g) for recordkeeping of malfunctions. §63.10(c)(12) through (14) Yes. Deleted: , Deleted: ,Page 486 of 566

§63.10(c)(15) No. §63.10(d)(1) Yes. §63.10(d)(2) Yes Area sources located outside UA plus offset and UC boundaries do not have to submit performance test reports. §63.10(d)(3) Yes. §63.10(d)(4) Yes. §63.10(d)(5) No See §63.775(b)(6) or (c)(6) for reporting of malfunctions. §63.10(e)(1) Yes Area sources located outside UA plus offset and UC boundaries are not required to submit reports. §63.10(e)(2) Yes Area sources located outside UA plus offset and UC boundaries are not required to submit reports. §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 p lus offset and UC boundaries are not required to submit reports. §63.10(e)(3)(i)(A) Yes. §63.10(e)(3)(i)(B) Yes. §63.10(e)(3)(i)(C) No Section reserved. §63.10(e)(3)(ii) through (viii) Yes. §63.10(f) Yes. §63.11(a) and (b) Yes. §63.11(c), (d), and (e) Yes. §63.12(a) through (c) Yes. §63.13(a) through (c) Yes. §63.14(a) and (b) Yes. §63.15(a) and (b) Yes. §63.16 Yes.Page 487 of 566

**Subpart HHH –**  **- [Amended]**  23. Section 63.1270 is amended by: a. Revising paragraph (a) introductory text; b. Revising paragraph (a)(4); c. Revising paragraph (b); d. Revising paragraphs (d)(1) and (d)(2); and e. Adding paragraphs (d)(3) and (4) to read as follows: **§63.1270 Applicability and designation of affected source.** (a) This subp art 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), an d that are major sources of hazardous air pollutants (HAP) emissions as defined in §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 se ction 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 p otential emissions. Other means to determine the facility's major source status are allowed, provided the information is documented andPage 488 of 566

recorded to the Administrator's satisfaction in accordance with §63.10(b)(3). A compressor station that transports natur al 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 incre ases 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 ap plicable 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 t hat 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 de termined 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 dehydrationPage 489 of 566 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 §63.2. (b) The affected source is each new and existing glycol dehydration unit specified in pa ragraphs (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 operat or 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 §63.6(i). The owner or operator of a n area source, the construction or reconstruction of which commenced before February 6, 1998, that increases its emissions of (or its Deleted: on orPage 490 of 566 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 §63.1271, located at a major source, that commenced construction before August 23, 2011, must achieve compliance no later than **[INSERT DATE 3 YEARS AND 60 DAYS**  **AFTER DATE OF PUBLICATION IN THE FEDERAL REGISTER]**  , except as provided in §63.6(i). (4) Each affected small glycol dehydration unit, as defined in §63.1271, located at a major source, that commenced construction on or after August 23, 2011, must achieve compliance immediately upon initial startup or **[INSERT DATE 60 DAYS AFTER DATE OF PUBLICATION IN THE FEDERAL REGISTER]**  , whichever is later.Page 491 of 566

* * * * * 24. Section 63.1271 is amended by: a. Adding, in alphabetical order, new definitions for the terms “affirmative defense,” “BTEX,” “flare,” “large glycol dehydration units,” “responsible official” and “small glycol dehydration units”; and b. Revising the definition for “glycol dehydration unit baseline operations ” to read as follows: **§63.1271 Definitions.**
* * * * * Affirmative defense means, in the context of an enforcement proceeding, a response or defense put forward by a defendant, regardi ng 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 dehydra tion Deleted: definitions

Deleted: ” and “temperature monitoring devicePage 492 of 566 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 (in cluding, 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 c ubic meters per day and actual annual average benzene emissions equal to or greater than 0.90 Mg/yr, determined according to §63.1282(a). A glycol dehydration unit complying with the 0.9 Mg/yr control option under 63. 12 75(b)(1)(ii) is considered to be a la rge 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 simila r policy or decision

- making functions for the corporation, or aPage 493 of 566 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 s ubject 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 a dvance 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 representativ e for any other purposes under part 70. Formatted: Font color: AutoPage 494 of 566

* * * * * 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 §63.1282(a).
* * * * * 25. Section 63.1272 is revised to read as follows: **§63.1272 Affirmative defense for violations of emission**  **standard s**  **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 §63.2. Appropr iate penalties may be assessed ; however, if you fail to meet your burden of proving all of the requirements in the affirmative defense , t he 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 Deleted: Temperature monitoring device means an instrument used to monitor temperature and having a minimum accuracy of ±1 percent of the temperature being monitored expressed in degrees C, or ±2.8 degrees C, whichever is greater. The temperature monitoring device may measure temperature in degrees Fahrenheit or degrees Celsius, or both. ¶ Deleted: **Malfunctio ns** 

Deleted: exceedances

Deleted: in

Deleted: ,

Deleted: . The

Deleted: limit, the owner or operator Deleted: notificationPage 495 of 566 requirements in paragraph (d)(2) of this section, and must prove by a preponderance of evidence that: (i) The vio lation : (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 Deleted: excess emissions

Deleted: Were

Deleted: and monitoring

Moved (insertion) [24]

Moved up [23]: ¶

(B) Could not have been prevented through careful planning, proper de sign 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 ¶ Deleted: Were

Moved (insertion) [29]

Deleted: the applicable emission limitations were being exceeded. Moved up [29]: Off

- sh ift and overtime labor were used, to the extent practicable to make these repairs; and ¶ Deleted: excess emissions Deleted: during periods of suc h emissions Deleted: excess emissionsPage 496 of 566 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, consiste nt 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 wri tten root cause analysis has been prepared , the purpose of which is to determine, correct, and eliminate the primary causes of the malfunction and the violat i on 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. Deleted: excess emissions

Moved (insertion) [30]

Moved up [30]: ¶

(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 ¶ Deleted: excess emissions

Deleted: excess emissions

Deleted: excessPage 497 of 56 6
(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 seco nd compliance, deviation report or excess emission report due after the initial occurrence of the violation of the relevant standard

. 26. Section 63.1274 is amended by: a. Revising paragraph (c) introductory text; b. Removing and reserving p aragraph (d); c. Revising paragraph (g); and d. Adding paragraph (h) to read as follows: **§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 Deleted: (2) Notification . The owner or operator of the affected source experiencing an exceedance of its emission limit(s) during a malfunction shall notify the Administrator by telephone or facsimile transmission as soon as possible, but no later than two business days after the initial occurrence of the malfunction, if it wishes to avail itself of an affirmative defense to civil penalties for that malfunction Formatted: Font color: Auto Deleted: also Deleted: within 45 days of the initial occurrence of the exceedance of the standard in this subpart to demonstrate, Deleted: The owner or operator may seek an extensi on of this deadline for up to 30 additional days by submitting a written request to the Administrator before the expiration of the 45 day Deleted: . Until a request for an extension has been approved by the Administrator, the owner or operator Deleted: subject to the requirement to submit such report within 45 days of

Deleted: exceedance

Deleted: ¶Page 498 of 566

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 detec ted, 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 maintenan ce procedures are being used will be based on information available to the Administrator which may include, but is not limited to, monitoring results, review ofPage 499 of 566 operation and maintenance procedures, review of operation and maintenance records, and inspecti on of the source. 27. Section 63.1275 is amended by: a. Revising paragraph (a); b. Revising paragraph (b)(1); c. Revising paragraph (c)(2); and d. Revising paragraph (c)(3) to read as follows: **§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 §63.1274. (b) * * * (1) For each glycol dehydration unit process vent, the owner or operator sh all control air emissions by either paragraph (b)(1)(i) or (b)(1)(iii) of this section. (i) The owner or operator of a large glycol dehydration unit, as defined in §63.1271, shall connect the process vent to a control device or a combination of control de vices through a closed

- vent system. The closed

- vent system shall be designed and operated in accordance with the requirements of §63.1281(c). The control device(s) shall be designed and operated in accordance with the requirements of §63.1281(d). (ii) The owner or operator of a large glycol dehydration unit shall connect the process vent to a control device or aPage 500 of 566 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 me gagrams per year. The closed

- vent system shall be designed and operated in accordance with the requirements of §63.1281(c). The control device(s) shall be designed and operated in accordance with the requirements of §63.1281(d), except that the performance requirements specified in §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 §63.1271, to the limit determined in Equation 1 of this section. You must limit
BTEX em issions from each new small glycol dehydration unit process vent, as defined in §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 th e alternatives specified in paragraphs (b)(1)(iii)(A) through (D) of this section.

Equation
1 Where:
EL BTEX = Unit

- specific BTEX emission limit, megagrams per year; 3. 10 x10 - 4 = BTEX emission limit, grams BTEX/standard cubic meter

- ppmv; Deleted: Equation 1 ¶Page 501 of 566 Throughput = Annual average daily natural gas throughput, standard cubic meters per day
C i,BTEX = Annual average BTEX concentration of the natural gas at the inlet to the glycol dehydration unit, ppmv.

Equation
2 Where:
EL BTEX = Unit

- specific BTEX emission limit, megagrams per year; 5.44 x10 - 5 = BTEX emission limit, grams BTEX/standard cubic meter

- ppmv; Throughput = Annual average daily natural gas throughput, standard cubic meters per day
C i,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 o f control devices through a closed

- vent system. The closed vent system shall be designed and operated in accordance with the requirements of §63.1281(c). The control device(s) shall be designed and operated in accordance with the requirements of §63.1281(f ). Moved (insertion) [31]

Moved (insertion) [32]

Formatted: Line spacing: Double

Deleted: 3.72x10 - 4

Deleted: ¶ Equation 2 ¶ Moved up [25]: Where: ¶ EL BTEX = Unit

- specific BTEX emission limit, megagrams per year; ¶ Formatted: Line spacing: Double Deleted: 1.10x10 - 5 = BTEX emission limit, grams BTEX/standard cubic meter

- ppmv; ¶ Moved up [31]: Throughput = Annual average daily natural gas throughput, standard cubic meters per day Deleted: ¶ Moved up [32]: C i,BTEX = Annual average BTEX concentration of the natural gas at the inlet to the glycol dehydration unit, ppmv. Deleted: ¶ ¶Page 502 of 566 (B) Meet the emissions limit through process modifications in accordance with the requirements specified in §63.1281(e). (C) Meet the emission limit for each small glycol dehydration unit using a combination of process modifications and one or more co ntrol 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 paramet ers in accordance with the requirements specified in §63.1281(e) and emissions in accordance with the requirements specified in §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 requireme nts specified in §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 dehydratio n unitPage 503 of 566 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 emission s 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 le ss 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 secti on. 28. Section 63.1281 is amended by: a. Revising paragraph (c)(1); b. Revising the heading of paragraph (d). c. Adding paragraph (d) introductory text; d. Revising paragraph (d)(1)(i)(C); e. Revising paragraphs (d)(1)(ii) and (iii); f. Revising pa ragraph (d)(4)(i); g. Revising paragraph (d)(5)(i); h. Revising paragraph (e)(2);Page 504 of 566 i. Revising paragraph (e)(3) introductory text; j. Revising paragraph (e)(3)(ii); and k. Adding paragraph (f) to read as follows: **§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 mi nimum temperature of 760 degrees C, provided the control device has demonstrated, under §63.1282(d), that combustion zone temperature is an indicator of destruction efficiency

. * * * * * (ii) A vapor recovery device ( e.g. , carbon adsorption syste m or condenser) or other non

- destructive control device Deleted: control

Deleted:

..Page 505 of 566 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 requirem ents of §63.1282(d). (iii) A flare, as defined in §63.1271, that is designed and operated in accordance with the requirements of §63.11(b).
* * * * * (4) * * * (i) Each control device used to comply with this subpart shall be operating at all times whe n gases, vapors, and fumes are vented from the emissions unit or units through the closed vent system to the control device as required under §63.1275. An owner or operator may vent more than one unit to a control device used to comply with this subpart.

* * * * * (5) * * * (i) Following the initial startup of the control device, all carbon in the control device shall be replaced with fresh carbon on a regular, predetermined time interval that is no longer than the carbon service life established for the carbon adsorption system. Records identifying the schedule for replacement and records of each carbon replacement shall be maintained as required in §63.1284(b)(7)(ix). The schedule for replacement shall be submitted with the Notification ofPage 506 of 566 Compliance Sta tus Report as specified in §63.1285(d)(4)(iv). Each carbon replacement must be reported in the Periodic Reports as specified in §63.1285(e)(2)(xi).
* * * * * (e) * * * (2) The owner or operator shall document, to the Administrator's satisfaction, the con ditions 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 §63.1275(b)(1)(iii), as applicable, either through process modifications or through a co mbination 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 t o 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 §63.1275(b)(1)(iii) for the small glycol dehydration unit process vent. Only modifications in glycol de hydration 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 gasPage 507 of 566
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 §63.1275(b)(1)(iii), as applicable, using process mo difications 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 §63.1275(b)(1)(iii), as applicable, using a combination of process modi fications 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 a pplicable, 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 §63.1275(b)(1)(iii) shall be one of the control devices specified in paragraphs (f)(1)(i) through (iii) of this section.Page 508 of 566
(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 §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 §63.1282(e). (ii) A vapor recover y 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 §63.1282( d). (iii) A flare, as defined in §63.1271, that is designed and operated in accordance with the requirements of §63.11(b).Page 509 of 566
(2) The o wner 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 operat or 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 §63.1283(d), the owner or operator shall demonstrate compliance according to the requirement s of either §63.1282(e) or (h). (3) For each carbon adsorption system used as a control device to meet the requirements of paragraph (f)(1) of this section, the owner or operator shall manage the carbon as required under (d)(5)(i) and (ii) of this section

. 29. Section 63.1282 is amended by: a. Revising paragraph (a) introductory text; b. Revising paragraph (a)(1)(ii); c. Revising paragraph (a)(2); d. Revising paragraph (b)(6)(i); e. Adding paragraph (c); f. Revising paragraph (d) introductory text; g. Revising paragraphs (d)(1)(i) through (v); h. Revising paragraph (d)(2);Page 510 of 566 i. Revising paragraph (d)(3) introductory text; j. Revising paragraph (d)(3)(i)(B); k. Revising paragraph (d)(3)( iii) introductory text; l. Revising paragraph (d) (3)(iv) introductory text; m. Revising paragraph (d)(3)(iv)(C)( 1 );

n . Adding paragraphs (d)(3)(v) and (vi); o. Revising paragraph (d)( 4) introductory text;

p. Revising paragraph ( d)(4)(i); q. Revising paragraph (d)(5); r. Revising paragraph ( e) introductory text;

s . Revising paragraphs (e)(2) and (e)(3);
t . Adding paragraphs (e)(4) through (e)(6); u. Revising paragraph (f ) introductory text; v. Revising paragraph (f)( 1 ); w. Revising paragraph (f)( 2) introductory text; x. Revising paragraph (f)(2)(iii); y. Revising paragraph (f)( 3); and

z . Adding paragraphs (g) and (h) to read as follows: **§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 Deleted: iv)(C)( 1 );

Deleted: l

Deleted: m. Revising paragraph (d)(4) introductory text; ¶ n. Revising paragraph (d)(4)(i); ¶
Deleted: 5);

Deleted: q

Deleted: r

Deleted: s. Revising paragraph (f) introductory text; ¶ t. Revising paragraph (f)(1); ¶
Deleted: )(2 Deleted: 2)(iii

Deleted: xPage 511 of 566 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 gly col dehydration unit. (2) The determination of actual average benzene or BTEX emissions from a glycol dehydration unit shall be made using the procedures of either paragraph (a)(2)(i) or (a)(2)(ii) of this section. Emissions shall be determined either unc ontrolled or with federally enforceable controls in place. (i) The owner or operator shall determine actual average benzene or BTEX emissions using the model GRI

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

- GLYCalc T M 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 R ich/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 Meth od 18 in 40 CFR part 60, appendix A ; or ASTM D6420

- 99(2004), as specified in Deleted: (Page 512 of 566
§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 rat e 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 performa nce 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 gly col 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 §63.1275(b)(1)(iii), the requirements of paragraph (d) of this s ection apply. Compliance Deleted: ),Page 513 of 566 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 §63.1275(b)(1)(iii), the owner or operator must determine the glycol dehydration u nit 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 equa tion in §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 proceduresPage 514 of 566 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 p rocedures 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

- GLYC alc 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 cont rol device achieves the performance requirements of §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 performancePage 515 of 566 requirements of §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 §63.1271, th at is designed and operated in accordance with §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 u sed 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 CFRPage 516 of 566 part 270 and complies with the requirements of 4 0 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 §63.1271, in accordance with the requirements specified in §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 § 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 spec ified in paragraph (d)(3)(vi) of this section. (i) * * * (B) To determine compliance with the enclosed combustion device total HAP concentration limit specified in §63.1281(d)(1)(i)(B), or the BTEX emission limit specified in §63.1275(b)(1)(iii), the sam pling site shall be located at the outlet of the combustion device.
* * * * *Page 517 of 566 (iii) To determine compliance with the control device percent reduction performance requirement in §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(2004), as specified in §63.772(a)(1)(ii); alternatively, any other method or data that have been validated

a ccording 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 H AP concentration limit specified in §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(2004), as specified in §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 c oncentration, corrected to 3 percent oxygen:
* * * * * (C) * * * Deleted: (iv) * * * ¶ (C) * * * ¶Page 518 of 566
( 1 ) The emission rate correction factor for excess air, integrated sampling and analysis procedures of Method 3A or 3B, 40 CFR part 60, appendix A, shall be used to determine the
oxygen con centration (%O 2d ). 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 §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 (2004), as specified in §63.772(a)(1)(ii); or any other method or data that have been validated according to the applicable procedures in M ethod 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 (E o ) 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:Page 519 of 566

Where:
E o = Mass rate of BTEX at the outlet of the control device, dry basis, kilogram per hour.
C oj = Concentration of sample component j of the gas stream at the outlet of the control device, dry basis, parts per million by volume.
M oj = Molecular weight of sample component j of the gas stream at the outlet of the control device, gram/gram

- mole. Q o = Flowrate of gas stream at the outlet of the control device, dry standard cubi c meter per minute.

K 2 = Constant, 2.494×10 − 6 (parts per million) (gram

- mole per standard cubic meter) (kilogram/gram) (minute/hour), where standard temperature (gram

- mole per standard cubic meter) is 20 degrees C. n = Number of components in sample. ( 2 ) When the BTEX mass rate is calculated, only BTEX compounds measured by Method 18, 40 CFR part 60, appendix A, or ASTM D6420

– 99 (2004) as specified in §63.772(a)(1)(ii), shall be summed using the equations in paragraph (d)(3)(v)(B)( 1 ) of this section. Deleted: ¶ Formatted: Font: (Default) Courier New, 12 pt, No underline, Font color: Auto Formatted: Line spacing: DoublePage 520 of 566
(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 §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 **[INSERT DATE 3 YEARS AFTER DATE OF PUBLICATION IN THE FEDERAL REGISTER]**  . 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 §63.128 2(g), then the newly installed device shall comply with all provisions of this subpart no later than **[INSERT DATE 3 YEARS AFTER DATE OF PUBLICATION IN THE FEDERAL REGISTER]**  . The performance test results shall be submitted in the Notification of Compliance Status Report as required in §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. Deleted: at existing

Deleted: an existingPage 521 of 566 Subsequent periodic performance tests shall be conducted at intervals no longer than 60 months foll owing 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 §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, §63.1282(g), or ( 2 ) A combustion control device demonstrating during the performance test under §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 §63.1281(d)(1), (e)(3)(ii), or (f)(1), the owner or operator shall meet the requirements specified in paragraphs (d)(4)(i) and (d)(4)(ii) of this section. Documentation of the design analysis shall be submitted as a part of the Notification of Compliance Status Report as required in §63.1285(d)(1)(i). (i) The condenser design analysis shall include an analysis of the vent stream composition, constituent concentrations,Page 522 of 566 flowrate, relative humidity, and temperature, and shall
esta blish 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 de sign analysis, an owner or operator may elect to use the procedures specified in paragraph (d)(5) of this section.
* * * * * (5) As an alternative to the procedures in paragraph (d)(4)(i) of this section, an owner or operator may elect to use the procedur es 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 d emonstration for control devices performance requirements

. This paragraph applies to the demonstration of compliance with the control device performance requirements specified in §63.1281(d)(1), (e)(3)(ii), and (f)(1). Compliance shall be demonstrated usin g 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 §63.1281(d)(1)(ii), (e)(3)(ii), or (f)(1) may demonstratePage 523 of 566 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

se lected approach. Notification of such a change in the compliance method shall be reported in the next Periodic Report, as required in §63.1285(e), following the change.
* * * * * (2) The owner or operator shall calculate the daily average of the applicabl e monitored parameter in accordance with §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) o f 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
t he value is equal to or less than the value established under §63.1282(g ) or under the performance test conducted under §63.1282(d), as applicable. (4) Except for periods of monitoring system malfunctions, repairs associated with monitoring system malfu nctions, and required monitoring system quality assurance or quality control Deleted: ).Page 524 of 566 activities (including, as applicable, system accuracy audits and required zero and span adjustments), the CMS required in §63.1283(d) must be operated at all times the affected so urce 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 ar e 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 lev els. 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 toPage 525 of 566 collect required data is a deviati on 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 §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 §63.1283(d)(5)(ii). For sources required to meet the BTEX limit in accordance with §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 §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 sec tion, 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 condenserPage 526 of 566 efficiencies as determined in paragraph (f)(2)(ii) of this section for the preceding 30 ope rating days. If the owner or operator uses a combination of process modifications and a condenser in accordance with the requirements of §63.1281(e), the 30

- day average HAP emission, or BTEX, emission reduction, shall be calculated using the emission reduc tion 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 §63.1270(d), an owner or operator of a fac ility 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 condens er 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 §63.1270(d), for an owner or operator that has less than 30 days of data for determining the average HAP, or BTE X, emission reduction, asPage 527 of 566 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 th e 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 source s meeting the HAP emission reduction specified in §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 l imit under §63.1281(e)(3) or (f)(1), compliance is achieved if the average BTEX emission reduction calculated in paragraph (f)(2)(iii) of this section is equal to or greater than the minimum percent reduction identified in paragraph (f)(1) of this section.
* * * * * (g) Performance testing for combustion control devices

- manufacturers’ performance test. (1) This paragraph applies to the performance testing of a combustion control device conducted by the device manufacturer. The manufacturer shall demonstra te that a specific model of control device achieves the performancePage 528 of 566 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 laborator y (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 7 0 percent for 5 minutes. In the 10

- 15 minute time range, incrementally ramp back down to 30Page 529 of 566 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 th e 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 individua lly 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 b e 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 Deleted: fuel

Deleted: fuelPage 530 of 566 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 para graphs (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 s hall 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 eac h 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. Deleted: fuel

Moved (insertion) [33] Moved up [33]: Record the start and stop reading for each 60

- minute THC test.

Deleted: fuel

Deleted: fuel

Deleted: 1Page 531 of 566
(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. ( 2 ) Hydrogen (H 2 ), carbon monoxide (CO), carbon dioxide (CO 2 ), nitrogen (N 2 ), oxygen (O 2 ) using ASTM D1945

- 03. ( 3 ) Higher heating value using ASTM D3588

- 98 or ASTM D4891

- 89. (5) Outlet testing shall be conducted in accordance with the criteria in paragraphs (g)(5)(i) through (v) of this section. (i) Sampling and flowrate measured in accordance with the following: (A) The outlet sampling location shall be a minimum of 4 equivalent stack diameters downstream from the highest peak flame or any other flow disturbance, and a minimum of one

e quivalent 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 Deleted: fuelPage 532 of 566 0.05 inches of water) during the performance test, a more sensitive manometer or othe r 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 collecte d 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 ) T he 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 vali d. 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 thisPage 533 of 566 criterion is not met, the initial calibration using at least three concentration le vels shall be repeated. (B) Report the molecular weight of: O 2 , CO 2 , methane (CH4), and N 2 and include in the test report submitted under §63.775(d)(iii). Moisture shall be determined using Method 4, 40 CFR part 60, Appendix A. Traverse both ports with t he Method 4, 40 CFR part 60, Appendix A, sampling train during each test run. Ambient air shall not be introduced into the Method 3C, 40 CFR part 60, Appendix A, integrated bag sample during the port change. (iii) Carbon monoxide shall be determined using Method 10, 40 CFR part 60, Appendix A. The test shall be run at the same time and with the sample points used for the EPA Method 25A, 40 CFR part 60, Appendix A, testing. An instrument range of 0

- 10 per million by volume

- dry (ppmvd) shall be used. (iv) V isible 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 dat e 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.Page 534 of 566
(6) Total hydr ocarbons (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

- 1 0 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 T raceability 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 CO 2 , 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.Page 535 of 566
(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 Meth od 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 CO 2 , and (C) Average CO emissions determined under paragraph (g)(5)(iv) of this section equal to o r less than 10 parts ppmvd, corrected to 3.0 percent CO 2 . (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 mod el 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 th is subpart. (8) The owner or operator of a combustion control device model tested under this section shall submit the informationPage 536 of 566 listed in paragraphs (g)(8)(i) through (iii) in the test report required under §63.775(d)(1)(iii). (i) Full schematic of th e 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 pre ssure. (I) Pilot flame sensor. (J) Pilot flame design fuel and fuel usage. (K) Tip velocity range.Page 537 of 566
(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 §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 b y the manufacturer. Flowrate shall be calculated as specified in §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 §63.1283(d)(3)(i)(H)( 2 ).Page 538 of 566 (3) Devices shall be op erated 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 doe s 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 mainte nance 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. Deleted: used

Deleted: 5Page 539 of 566 (iv) Following return to operation from mainte nance or repair activity, each device must pass a Method 22 visual observation as described in paragraph (h)(3) of this section. 30. Section 63.1283 is amended by: a. Adding paragraph (b); b. Revising paragraph (d)(1) introductory text; c. Revising pa ragraph (d)(1)(ii) and adding paragraphs (d)(1)(iii) and (iv); d. Revising paragraph (d)(2); e. Revising paragraph (d)(3)(i)(A ); f. Revising paragraph (d)(3)(i)(D ); g. Revising paragraph (d)(3)(i)(G); h . Adding paragraph (d)(3)(i)(H); i. Revising paragraph (d)(4); j. Revising paragraph (d)( 5)(i ); k. Revising paragraphs (d)(5)(ii)(A) through (C); l . Revising paragraph (d)(6) introductory text;

m . Revising paragraphs (d)(6)(ii);

n . Adding paragraph (d)(6)(v);

o . Revising paragraph (d)(7)); and

p . Removing paragraph (d)(8) to read as follows: **§63.1283 Inspection and monitoring requirements.**
* * * * * Deleted: paragraphs Deleted: ) and (B Deleted: paragraphs Deleted: ) and (E Deleted: paragraphs (d)(3)(i)(F)( 1 ) and ( 2 ); ¶ h. Revising Deleted: i

Deleted: 4

Deleted: paragraph (d)(5)(i); ¶ l. Revising Deleted: m

Deleted: n

Deleted: o

Deleted: p

Deleted: qPage 540 of 566
(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 operat ion 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 §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 de termination can be made on whether the control device is achieving the applicable performance requirements of §63.1281(d), (e)(3), or (f)(1). Each continuous parameter monitoring system shall meet the following specifications and requirements:
* * * * *Page 541 of 566
( 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 §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 §63.8(f)(4), you may request approval of monitoring system quality assurance and quality control procedu res 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 §63.8(c)(1) and (c)(3); and (E) Ongoing reporting and recordkeeping procedures in accordance with provisions in §63.10(c), (e)(1), and (e)(2)(i).Page 542 of 566 (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 perf ormance 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 devic es: (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 §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 minimumPage 543 of 566
accuracy of ± 2 percent of the temperature being monitored in ° C, or ±2. 5 ° 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 temperatu re 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 ° C, or ±2. 5 ° C, whichever value is greater. The temperature sens or 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 §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 §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 Deleted: 1 Deleted: degrees Deleted: 8 deg rees Deleted: (B) For a catalytic vapor incinerator, a temperature monitoring device equipped with a continuous recorder. Th e device shall be capable of monitoring temperatures at two locations and have a minimum accuracy of ±1 percent of the temperatures being monitored in degrees C, or ±2.8 degrees C, whichever value is greater. One temperature sensor shall be installed in th e vent stream at the nearest feasible point to the catalyst bed inlet and a second temperature sensor shall be installed in the vent stream at the nearest feasible point to the catalyst bed outlet. ¶ Deleted: 1 Deleted: degrees Deleted: 8 degrees Deleted: (E) For a condenser, a temperature monitoring device equipped with a continuous recorder. The temperature monitoring device shall have a minimum accuracy of ±1 percent of the temperature being monitored in degrees C, or ±2.8 degrees C, whichever value is greater. The temperature sensor shall be installed at a location in the exhaust vent stream from the condenser. ¶

(F) * * * ¶ ( 1 ) A continuous parameter monitoring system to measure and record the average total regeneration stream mass flow or volumetric flow during each carbon bed regeneration cycle. The flow sensor must have a measurement sensitivity of 5 percent of the flowrate or 10 cubic feet per minute, whichever is g reater. The mechanical connections for leakage must be checked at least every month, and a visual inspection must be performed at least every 3 months of all components of the flow CPMS for physical and operational integrity and all electrical connections for oxidation and galvanic corrosion if your flow CPMS is not equipped with a redundant flow sensor; and ¶

( 2 ) A continuous parameter monitoring system to measure and record the average carbon bed temperature for the duration of the carbon bed steaming cycl e and to measure the actual carbon bed temperature after regeneration and

...Page 544 of 566 shall be representative of actual operating conditions of the controlled unit. The determination shall be performed to coincide with the v isible emissions test under §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 i nlet 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 opera tion 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 ap plicable performance requirements ofPage 545 of 566
§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 § 63.1282(d)(3) to demonstrate that the control device achieves the applicable performance requirements specified in §63.1281(d)(1), (e)(3)(ii), or (f)(1), then the minimum operating parameter value or the maximum operating parameter value shall be establish ed 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 §63.1282(d)(4) to demonstrate that the control device achieves the applicable performance requirements specified in §63.1281(d)(1), (e)(3)(ii), or (f)(1), then the minimum operating parameter value or the maximum ope rating 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 m et under §63.1282(g) to demonstrate that the control device achieves the applicable performance requirements specified in §63.1281(d)(1), (e)(3)(ii)Page 546 of 566 or (f)(1), then the maximum inlet gas flowrate shall be established based on the performance test and suppl emented, as necessary, by the manufacturer recommendations. (ii) * * * (A) If the owner or operator conducts a performance test in accordance with the requirements of §63.1282(d)(3) to demonstrate that the condenser achieves the applicable performance re quirements in §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 recomm endations, or a combination or both. (B) If the owner or operator uses a control device design analysis in accordance with the requirements of §63.1282(d)(4)(i) to demonstrate that the condenser achieves the applicable performance requirements specified i n §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

–Page 547 of 566 95/0368.1) as inputs for the model GRI

- GLYCalc TM , Version 3.0 or hig her, 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 §63.1281(d)(1)(ii), an excursion occurs when average condenser efficiency calculat ed according to the requirements specified in §63.1282(f)(2)(iii) is less than 95.0 percent, as specified in §63.1282(f)(3). For sources meeting §63.1281(f)(1), an excursion occurs when the 30

- day average condenser efficiency calculated according to the

re quirements of §63.1282(f)(2)(iii) is less than the identified 30

- day required percent reduction.
* * * * * (v) For control device whose model is tested under §63.1282(g) an excursion occurs when:Page 548 of 566 (A) The inlet gas flowrate exceeds the maximum established during the test conducted under §63.1282(g). (B) Failure of the quarterly visible emissions test conducted under §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.
* * * * * 31. Section 63.1284 is amended by: a. Revising paragraph (b)(3) introductory text; b. Removing and reserving paragraph (b)(3)(ii); c. Revising paragraph (b)(4)(ii); d. Revising paragraph (b)(4)(iii); e. Adding paragraph (b)(7)(ix); and f. Adding paragraph (f), (g) and (h) to read as follows: **§63.1284 Recordkeeping requirements.**
* * * * * (b) * * * (3) Records specified in §63.10(c) for each monitoring system operated by the owner or operator in accordance with the requirements of §63.1283(d). Notwithstanding the previous sentence, monitoring data recorded during periods identified inPage 549 of 566
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 proced ures specified in §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 §63.1275, records of the annual 30

- day rolling average condenser efficiency determined under §63.1282(f) shall be kept in addition to the daily averages. (C) For a control device whose model is tested under §63.1282(g), the records required in paragraph (g) of this section. Deleted: )_Page 550 of 566 (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 §63.1281 (d)(5) and records of each carbon replacement.
* * * * * (f) The owner or operator of an affected source subject to this subpart shall maintain records of the occurrence and duration of each malfunction of operation ( i.e. , process equipment) or the air po llution 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 §63.1274( h ), including corrective actions to restore malfunctioning pr ocess 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 §63.1282(g) to comply with §63.1281(d), (e)(3)(ii) and (f)(1): (1) All v isible emission readings and flowrate calculations made during the compliance determination required by §63.1282(h); and Deleted: aPage 551 of 566 (2) All hourly records and other recorded periods when the pilot flame is absent. (h) The date the semi

- annual maintenance inspection required under §63.1283(b) is performed. Include a list of any modifications or repairs made to the control device during the inspection and other maintenance performed such as cleaning of the fuel nozzles. 32. Section 63.1285 is amended by: a. Revising paragraph (b)(1); b. Revising paragraph (b)(6); c. Removing paragraph (b)(7); d. Revising paragraph (d) introductory text; e. Revising paragraph (d)(1) introductory text; f. Revising paragraph (d)(1)(i); g. Revising paragraph (d)(1)(ii) introductory text; h. Revising paragraph (d)(2) introductory text; i. Revising paragraph (d)(4) introductory text; j. Revising paragraph (d)(4)(ii); k. Adding paragraph (d)(4)(iv); l. Revising paragraph (d)(10); m. Adding paragraphs (d)(11) and (d)(12);
n. Rev ising paragraph (e)(2) introductory text; o. Revising paragraphs (e)(2)(ii)(B); p. Adding paragraphs (e)(2)(ii)(D) and (E);Page 552 of 566 q. Adding paragraphs (e)(2)(x),(xi) and (xii); and r. Adding paragraph (g) to read as follows: **§63.1285 Reporting requirements.**
* * * * * (b) * * * (1) The initial notifications required for existing affected sources under §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 §63.1270(d)(3) shall submit an initial notification required for existing affected sources under §63.9(b)(2) within 1 year after the affected source becomes subject to the provisions of this subpart or by **[INSERT DATE 1**  **YEAR AFTER DATE OF PUBLICATION IN THE FEDERAL REGISTER]**  **,** whichever is later. An affected source identified under §63.1270(d)(3) that plans to be an area source Deleted: **ONE**Page 553 of 566
by **[INSERT DATE 3**  **YEARS AFTER DATE OF PUBLICATION IN THE FEDERAL REGISTER]**  **,** shall include in this notification a brief, nonbinding description of a schedule for the action(s) that are planned to achieve area source status.
* * * * * (6) If there was a malfunction during the reporting period, the Periodic Report specified in paragraph (e) of this section shall include the number, duration, and a brief description for each type of malfunction which occurred during the reporting period and which caused or may have caused any applicable emission limitation to be exceeded. The report must also include a description of actions taken by an owner or operator during a malfunction of an affected source to minimize emissions in accordance with §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 Com pliance Status Report as required under §63.9(h) within 180 days after the compliance date specified in §63.1270(d). In addition to the information required under §63.9(h), the Notification of Compliance Status Report shall include the information specifie d in paragraphs (d)(1) through (12) of this section. This information may be submitted in an operating permit application, in an amendment to Deleted: **THREE**Page 554 of 566 an operating permit application, in a separate submittal, or in any combination of the three. If all of the inform ation required under this paragraph have been submitted at any time prior to 180 days after the applicable compliance dates specified in §63.1270(d), a separate Notification of Compliance Status Report is not required. If an owner or operator submits the i nformation 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 §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 thi s section. (i) The condenser design analysis documentation specified in §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 performan ce 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 thatPage 555 of 566 the test was conducted using the methods specified in §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 §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 website: epa.gov/airquality/oilandgas/

. * * * * * (2) If a closed

- vent system and a flare are used to co mply with §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 §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 b e monitored in accordance with the requirements of §63.1283(d).* *
* * * (ii) An explanation of the rationale for why the owner or operator selected each of the operating parameter values established in §63.1283(d)(5) of this subpart. This explanation Formatted: Font: Not Italic, No underline, Font color: Auto

Formatted: No underline, Font color: AutoPage 556 of 566

sha ll 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 §63.1281(d)(1), (e)(3)(ii), or (f)(1).
* * * * * (iv ) For each carbon adsorber, the predetermined carbon replacement schedule as required in §63.1281(d)(5)(i).
* * * * * (10) The owner or operator shall submit the analysis prepared under §63.1281(e)(2) to demonstrate that the conditions by which the facili ty will be operated to achieve the HAP emission reduction of 95.0 percent, or the BTEX limit in §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 ins talls a combustion control device model tested under the procedures in §63.1282(g), the data listed under §63.1282(g)(8). (12) For each combustion control device model tested under §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.Page 557 of 566
(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 d estruction 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, a s applicable.
* * * * * (ii) * * * (B) For each excursion caused when the 30

- day average condenser control efficiency is less than the value, as specified in §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 §63.1282(g) is exceeded, the report must include the values of the inlet gas iden tified and the date and duration of the period that the excursion occurred.Page 558 of 566
(E) For each excursion caused when visible emissions determined under §63.1282(h) exceed the maximum allowable duration, the report must include the date and duration of the perio d 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 §63.1282(d)(3) conducted during the reporting period. (xi) For each carbon adsorber use d to meet the control device requirements of §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 §63.1283(b) the records specified in §6 3.1284(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 §63.2) as required by this subpart you must submit the results of the performance tests required by this subpart to EPA’s WebFIREPage 559 of 566 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 o f 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 website are subject to this requirement for submitting reports electronically to WebFIRE. Owners or operators who c laim 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 (in cluding, 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 fo rmat 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 toPage 560 of 566 the Administrator at the appropriate address listed in §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 par agraph (g)(1) of this section in paper format. 33. Section 63.1287 is amended by revising paragraph (a) to read as follows: **§63.1287 Alternative means of emission limitation.** (a) If, in the judgment of the Administrator, an alternative means of emissio n 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 §§63.1274 through 63.1281, the Administrator will publish a notice in the **Federal Re gister**  permitting the use of the alternative means for purposes of compliance with that requirement. The notice may condition the permission on requirements related to the operation and maintenance of the alternative means.
* * * * * 34. Appendix to Subpar t HHH of Part 63

– Table is amended by revising Table 2 to read as follows: **Appendix to Subpart HHH of Part 63 —**  **Tables** Formatted: Font color: AutoPage 561 of 566

* * * * * **Table 2 to Subpart HHH of Part 63 —**  **Applicability of 40 CFR Part 63 General Provisions to Subpart HHH**  **General provisions reference**  **Applicable to**  **subpart HHH Explanation** 

§63.1(a)(1) Yes. §63.1(a)(2) Yes. §63.1(a)(3) Yes. §63.1(a)(4) Yes. §63.1(a)(5) No Section reserved. §63.1(a)(6) through (a)(8) Yes. §63.1(a)(9) No Section reserved. §63.1(a)(10) Yes. §63.1(a)(11) Yes. §63.1(a)(12) through (a)(14) Yes. §63.1(b)(1) No Subpart HHH specifies applicability. §63.1(b)(2) Yes. §63.1(b)(3) No. §63.1(c)(1) No Subpart HHH specifies applicability. §63.1(c)(2) No. §63.1(c)(3) No Section reserved. §63.1(c)(4) Yes. §63.1(c)(5) Yes. §63.1(d) No Section reserved. §63.1(e) Yes. §63.2 Yes Except definition of major source is unique for this source category and there are additional definitions in subpart HHH. §63.3(a) through (c) Yes. §63.4(a)(1) through (a)(3) Yes. §63.4(a)(4) No Section reserved. §63.4(a)(5) Yes. §63.4(b) Yes. §63.4(c) Yes. §63.5(a)(1) Yes. §63.5(a)(2) No Preconstruction review required only for major sources that Formatted: LeftPage 562 of 566

commence construction after promulgation of the standard. §63.5(b)(1) Yes. §63.5(b)(2) No Section reserved. §63.5(b)(3) Yes. §63.5(b)(4) Yes. §63.5(b)(5) Yes. §63.5(b)(6) Yes. §63.5(c) No Section reserved. §63.5(d)(1) Yes. §63.5(d)(2) Yes. §63.5(d)(3) Yes. §63.5(d)(4) Yes. §63.5(e) Yes. §63.5(f)(1) Yes. §63.5(f)(2) Yes. §63.6(a) Yes. §63.6(b)(1) Yes. §63.6(b)(2) Yes. §63.6(b)(3) Yes. §63.6(b)(4) Yes. §63.6(b)(5) Yes. §63.6(b)(6) No Section reserved. §63.6(b)(7) Yes. §63.6(c)(1) Yes. §63.6(c)(2) Yes. §63.6(c)(3) and (c)(4) No Section reserved. §63.6(c)(5) Yes. §63.6(d) No Section reserved. §63.6(e) Yes. §63.6(e) Yes Except as otherwise specified. §63.6(e)(1)(i) No See §63.1274(h) for general duty requirement. §63.6(e)(1)(ii) No. §63.6(e)(1)(iii) Yes. §63.6(e)(2) Yes. §63.6(e)(3) No. §63.6(f)(1) No. §63.6(f)(2) Yes. §63.6(f)(3) Yes. §63.6(g) Yes. §63.6(h)(1) No. §63.6(h )(2) through (h)(9 ) Yes. §63.6(i)(1) Yes.Page 563 of 566
through (i)(14) §63.6(i)(15) No Section reserved. §63.6(i)(16) Yes. §63.6(j) Yes. §63.7(a)(1) Yes. §63.7(a)(2) Yes But the performance test results must be submitted within 180 days after the compliance date. §63.7(a)(3) Yes. §63.7(b) Yes. §63.7(c) Yes. §63.7(d) Yes. §63.7(e)(1) No. §63.7(e)(2) Yes. §63.7(e)(3) Yes. §63.7(e)(4) Yes. §63.7(f) Yes. §63.7(g) Yes. §63.7(h) Yes. §63.8(a)(1) Yes. §63.8(a)(2) Yes. §63.8(a)(3) No Section reserved. §63.8(a)(4) Yes. §63.8(b)(1) Yes. §63.8(b)(2) Yes. §63.8(b)(3) Yes. §63.8(c)(1) Yes. § 63.8(c)(1)(i). §63.8(c)(1)(ii). §63.8(c)(1)(iii) No. Yes. No . §63.8(c)(2) Yes. §63.8(c)(3) Yes. §63.8(c)(4) No. §63.8(c)(5) through (c)(8) Yes. §63.8(d) Yes. §63.8(d)(3) Yes Except for last sentence, which refers to an SSM plan. SSM plans are not required. §63.8(e) Yes Subpart HHH does not specifically require continuous emissions monitor performance evaluations, however, the Administrator can request that one be conducted. §63.8(f)(1) through (f)(5) Yes Deleted: PendingPage 564 of 566

§63.8(f)(6) No Subpart HHH does not require continuous emissions monitoring. §63.8(g) No Subpart HHH specifies continuous monitoring system data reduction requirements. §63.9(a) Yes. §63.9(b)(1) Yes. §63.9(b)(2) Yes Existing sources are given 1 year (rather than 120 days) to submit this notification. §63.9(b)(3) Yes. §63.9(b)(4) Yes. §63.9(b)(5) Yes. §63.9(c) Yes. §63.9(d) Yes. §63.9(e) Yes. §63.9(f) Yes. §63.9(g) Yes. §63.9(h)(1) through (h)(3) Yes. §63.9(h)(4) No Section reserved. §63.9(h)(5) and (h)(6) Yes. §63.9(i) Yes. §63.9(j) Yes. §63.10(a) Yes. §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. §63.10(b)(2) Yes. §63.10(b)(2)(i) No. §63.10(b)(2)(ii) No See §63.1284(f) for recordkeeping of (1) occurrence and duration and (2) actions taken during malfunction

. §63.10(b)(2)(iii) Yes. §63.10(b)(2)(iv) through (b)(2)(v) No.

§63.10(b)(2)(vi) through (b)(2)(xiv) Yes.

§63.10(b)(3) No. Deleted: , Deleted: ,Page 565 of 566

§63.10(c)(1) Yes. §63.10(c)(2) through (c)(4) No Sections reserved. §63.10(c)(5) through (c)(8) Yes. §63.10(c)(9) No Section reserved. §63.10(c)(10) through (c)(11) No See §63.1284(f) for recordkeeping of malfunctions

. §63.10(c)(12) through (c)(14) Yes. §63.10(c)(15) No. §63.10(d)(1) Yes. §63.10(d)(2) Yes. §63.10(d)(3) Yes. §63.10(d)(4) Yes. §63.10(d)(5) No See §63.1285(b)(6) for reporting of malfunctions. §63.10(e)(1) Yes. §63.10(e)(2) Yes. §63.10(e)(3)(i) Yes Subpart HHH requires major sources to submit Periodic Reports semi

- annually. §63.10(e)(3)(i)(A) Yes. §63.10(e)(3)(i)(B) Yes. §63.10(e)(3)(i)(C) No Subpart HHH does not require quarterly reporting for excess emissions. §63.10(e)(3)(ii) through (e)(3)(viii) Yes.

§63.10(f) Yes. §63.11(a) and (b) Yes. §63.11(c), (d), and (e) Yes. §63.12(a) through (c) Yes. §63.13(a) through (c) Yes. §63.14(a) and (b) Yes. §63.15(a) and (b) Yes.Page 566 of 566