The EPA Administrator, Lisa P. Jackson, signed the following notice on 4/17/2012, and EPA is submitting it for

publication in the Federal Register (FR). While we have taken steps to ensure the accuracy of this Internet version

of the rule, it is not the official version of the rule for purposes of compliance. Please refer to the official version in

a forthcoming FR publication, which will appear on the Government Printing Office's FDSys website

(http://fdsys.gpo.gov/fdsys/search/home.action) and on Regulations.gov (http://www.regulations.gov) in Docket

No. EPA‐HQ‐OAR‐2010‐0505. Once the official version of this document is published in the FR, this version will be

removed from the Internet and replaced with a link to the official version.

6560-50-P 

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 source 

performance standards for volatile organic compounds from 

leaking components at onshore natural gas processing plants and 

new source performance standards for sulfur dioxide emissions 

from natural gas processing plants. The EPA also established 

standards for certain oil and gas operations not covered by the 

existing standards. In addition to the operations covered by the 

existing standards, the newly established standards will 
                                 

                             

 

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regulate volatile organic compound emissions from gas wells, 

centrifugal compressors, reciprocating compressors, pneumatic 

controllers and storage vessels. This action also finalizes the 

residual risk and technology review for the Oil and Natural Gas 

Production source category and the Natural Gas Transmission and 

Storage source category. This action includes revisions to the 

existing leak detection and repair requirements. In addition, 

the EPA has established in this action emission limits 

reflecting maximum achievable control technology for certain 

currently uncontrolled emission sources in these source 

categories. This action also includes modification and addition 

of testing and monitoring and related notification, 

recordkeeping and reporting requirements, as well as other minor 

technical revisions to the national emission standards for 

hazardous air pollutants. This action finalizes revisions to the 

regulatory provisions related to emissions during periods of 

startup, shutdown and malfunction. 

DATES: This final rule is effective on [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]. 

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ADDRESSES: The EPA has established a docket for this action 

under Docket ID. No. EPA-HQ-OAR-2010-0505. All documents in the 

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

Although listed in the index, some information is not publicly 

available, e.g., confidential business information or other 

information whose disclosure is restricted by statute. Certain 

other material, such as copyrighted material, is not placed on 

the Internet and will be publicly available only in hard copy 

form. Publicly available docket materials are available either 

electronically through http://www.regulations.gov or in hard 

copy at the EPA’s Docket Center, Public Reading Room, EPA West 

Building, Room Number 3334, 1301 Constitution Avenue, NW, 

Washington, 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 

Programs Division (E143-05), Office of Air Quality and 

Standards, Environmental Protection Agency, Research Triangle 

Park, North Carolina 27711, telephone number: (919) 541-5460; 

facsimile number: (919) 685-3200; email address: 

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moore.bruce@epa.gov. For additional contact information, see the 

following SUPPLEMENTARY INFORMATION section. 

SUPPLEMENTARY INFORMATION: For specific information regarding 

risk assessment and exposure modeling methodology, contact Mr. 

Mark Morris, Health and Environmental Impacts Division (C504­

06), Office of Air Quality Planning and Standards, U.S. 

Environmental Protection Agency, Research Triangle Park, NC 

27711; telephone number (919) 541-5416; fax number: (919) 541­

0840; and email address: morris.mark@epa.gov. 

Organization of This Document. The information presented in 

this preamble is organized as follows: 

I. Preamble Acronyms and Abbreviations 

II. General Information 

A. Executive Summary 

B. Does this action apply to me? 

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

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

E. Judicial Review 

III. Background Information on the NSPS and NESHAP 

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

B. What is the litigation history? 

C. What is the sector-based approach? 

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D. What are the health effects of pollutants emitted from the 

oil and 

natural gas sector? 

IV. Summary of the Final NSPS Rule 

A. What are the final actions relative to the NSPS for the Crude 

Oil 

and Natural Gas Production source category? 

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

NSPS? 

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

A. Gas Well Affected Facilities 

B. Centrifugal and Reciprocating Compressor Affected Facilities 

C. Pneumatic Controller Affected Facilities 

D. Storage Vessel Affected Facilities 

E. Equipment Leaks Affected Facilities and Sweetening Unit 

Affected 

Facilities at Onshore Natural Gas Processing Plants 

F. Changes to Notification, Recordkeeping and Reporting 

Requirements 

VI. Summary of the Final NESHAP Rules 

A. What are the final rule actions relative to the Oil and 

Natural 

Gas Production (subpart HH) source category? 

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B. What are the final rule amendments for the Natural Gas 

Transmission and Storage (subpart HHH) source category? 

C. What is the effective date of this final rule and compliance 

dates 

for the standards? 

VII. Summary of the Significant Changes to the NESHAP Since 

Proposal 

A. What are the significant changes since proposal for the Oil 

and 

Natural Gas Production (subpart HH) source category? 

B. What are the significant changes since proposal for the 

Natural 

Gas Transmission and Storage (subpart HHH) source 

category? 

VIII. Compliance Related Issues Common to the NSPS and NESHAP 

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

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

C. What are the requirements for submission of performance test 

data 

to the EPA? 

IX. Summary of Significant NSPS Comments and Responses 

A. Major Comments Concerning Applicability 

B. Major Comments Concerning Well Completions 

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C. Major Comments Concerning Pneumatic Controllers 

D. Major Comments Concerning Compressors 

E. Major Comments Concerning Storage Vessels 

F. Major Comments Concerning Notification, Recordkeeping and 

Reporting Requirements 

X. Summary of Significant NESHAP Comments and Responses 

A. Major Comments Concerning Previously Unregulated Sources 

B. Major Comments Concerning the Risk Review 

C. Major Comments Concerning the Technology Review 

D. Major Comments Concerning Notification, Recordkeeping and 

Reporting Requirements 

XI. What are the cost, environmental and economic impacts of the 

final NESHAP and NSPS amendments? 

A. What are the air impacts? 

B. What are the energy impacts? 

C. What are the cost impacts? 

D. What are the economic impacts? 

E. What are the benefits of this final rule? 

XII. Statutory and Executive Order Reviews 

A. Executive Order 12866: Regulatory Planning and Review and 

Executive Order 13563: Improving Regulation and Regulatory 

Review 

B. Paperwork Reduction Act 

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C. Regulatory Flexibility Act 

D. Unfunded Mandates Reform Act 

E. Executive Order 13132: Federalism 

F. Executive Order 13175: Consultation and Coordination with 

Indian 

Tribal Governments 

G. Executive Order 13045: Protection of Children from 

Environmental 

Health Risks and Safety Risks 

H. Executive Order 13211: Actions Concerning Regulations That 

Significantly Affect Energy Supply, Distribution, or Use 

I. National Technology Transfer and Advancement Act 

J. Executive Order 12898: Federal Actions to Address 

Environmental 

Justice in Minority Populations and Low-Income Populations 

K. Congressional Review Act 

I. Preamble Acronyms and Abbreviations 

Several acronyms and terms used to describe industrial 

processes, data inventories and risk modeling are included in 

this preamble. While this may not be an exhaustive list, to ease 

the reading of this preamble and for reference purposes, the 

following terms and acronyms are defined here: 

API American Petroleum Institute 

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BACT Best Available Control Technology 

BDT Best Demonstrated Technology 

bpd Barrels Per Day 

BMP Best Management Practice 

BSER Best System of Emission Reduction 

BTEX Benzene, Ethylbenzene, Toluene and Xylene 

CAA Clean Air Act 

CBM Coal Bed Methane 

CDX Central Data Exchange 

CEDRI Compliance and Emissions Data Reporting Interface 

CFR Code of Federal Regulations 

CO Carbon Monoxide 

CO2 Carbon Dioxide 

CO2e Carbon Dioxide Equivalent 

DOE United States Department of Energy 

e-GGRT Electronic Greenhouse Gas Reporting Tool 

EPA Environmental Protection Agency 

ERPG Emergency Response Planning Guidelines 

ERT Electronic Reporting Tool 

GCG Gas Condensate Glycol 

GHG Greenhouse Gas 

GOR Gas to Oil Ratio 

GWP Global Warming Potential 

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HAP Hazardous Air Pollutants 

HEM–3 Human Exposure Model, version 3 

HI Hazard Index 

HP Horsepower 

HQ Hazard Quotient 

H2S Hydrogen Sulfide 

ICR Information Collection Request 

IPCC Intergovernmental Panel on Climate Change 

IRIS Integrated Risk Information System 

km Kilometer 

kW Kilowatts 

LAER Lowest Achievable Emission Rate 

lb Pounds 

LDAR Leak Detection and Repair 

MACT Maximum Achievable Control Technology 

MACT Code NEI code used to identify processes included in a 

 source category 

Mcf Thousand Cubic Feet 

Mg/yr Megagrams per year 

MIR Maximum Individual Risk 

MIRR Monitoring, Inspection, Recordkeeping and Reporting 

MMtCO2e Million Metric Tons of Carbon Dioxide Equivalents 

NAAQS National Ambient Air Quality Standards 

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NAC/AEGL National Advisory Committee for Acute Exposure 

Guideline 

Levels for Hazardous Substances 

NAICS North American Industry Classification System 

NAS National Academy of Sciences 

NATA National Air Toxics Assessment 

NEI National Emissions Inventory 

NEMS National Energy Modeling System 

NESHAP National Emissions Standards for Hazardous Air 

Pollutants 

NGL Natural Gas Liquids 

NIOSH National Institutes for Occupational Safety and Health 

NOX Oxides of Nitrogen 

NRC National Research Council 

NSPS New Source Performance Standards 

NSR New Source Review 

NTTAA National Technology Transfer and Advancement Act 

OAQPS Office of Air Quality Planning and Standards 

OMB Office of Management and Budget 

PB–HAP Hazardous air pollutants known to be persistent and 

bioaccumulative in the environment 

PFE Potential for Flash Emissions 

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PM Particulate Matter 

PM2.5 Particulate Matter (2.5 microns and less) 

POM Polycyclic Organic Matter 

ppm Parts per Million 

ppmv Parts per Million by Volume 

PSIG Pounds per Square Inch Gauge 

PSIA Pounds per Square Inch Absolute 

PTE Potential to Emit 

QA Quality Assurance 

RACT Reasonably Available Control Technology 

RBLC RACT/BACT/LAER Clearinghouse 

REC Reduced Emissions Completions 

REL California EPA Reference Exposure Level 

RFA Regulatory Flexibility Act 

RfC Reference Concentration 

RfD Reference Dose 

RIA Regulatory Impact Analysis 

RICE Reciprocating Internal Combustion Engines 

RTR Residual Risk and Technology Review 

SAB Science Advisory Board 

SBREFA Small Business Regulatory Enforcement Fairness Act 

SCC Source Classification Codes 

scfh Standard Cubic Feet Per Hour 

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scfm Standard Cubic Feet Per Minute 

scm Standard Cubic Meters 

scmd Standard Cubic Meters per Day 

SCOT Shell Claus Offgas Treatment 

SIP State Implementation Plan 

SISNOSE Significant Economic Impact on a Substantial Number of 

 Small Entities 

S/L/T State and Local and Tribal Agencies 

SO2 Sulfur Dioxide 

SSM Startup, Shutdown and Malfunction 

STEL Short-term Exposure Limit 

TLV Threshold Limit Value 

TOSHI Target Organ-Specific Hazard Index 

tpy Tons per Year 

TRIM Total Risk Integrated Modeling System 

TRIM.FaTE A spatially explicit, compartmental mass balance model 

that 

describes the movement and transformation of 

pollutants 

over time, through a user-defined, bounded system that 

includes both biotic and abiotic compartments 

TSD Technical Support Document 

UF Uncertainty Factor 

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UMRA Unfunded Mandates Reform Act 

URE Unit Risk Estimate 

VCS Voluntary Consensus Standards 

VOC Volatile Organic Compounds 

VRU Vapor Recovery Unit 

II. General Information 

A. Executive Summary 

1. Purpose of the Regulatory Action 

Responding to the requirements of a consent decree, this 

action finalizes several rules that apply to the oil and gas 

production industry and significantly reduce emissions of air 

pollutants. More particularly, the action finalizes: 

•	 New source performance standards (NSPS) for the Crude Oil 

and Natural Gas Production and onshore natural gas 

processing plant source category. The EPA reviewed two 

existing NSPS for onshore natural gas processing plant 

source category under section 111(b) of the Clean Air Act 

(CAA). This action improves the existing NSPS and 

finalizes standards for certain crude oil and natural gas 

sources that are not covered by existing NSPS for this 

sector. 

•	 National Emissions Standards for Hazardous Air Pollutants 

(NESHAP) for the Oil and Natural Gas Production source 

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category and the Natural Gas Transmission and Storage 

source category. The EPA conducted risk and technology 

reviews (RTR) for these rules under section 112 of the 

CAA. In addition, the EPA has established emission limits 

for certain currently uncontrolled emission sources in 

these source categories. These limits reflect maximum 

achievable control technology (MACT). 

2. Summary of the Major Provisions of the Regulatory Actions 

New Source Performance Standards (NSPS). The newly 

established NSPS for the Crude Oil and Natural Gas Production 

source category regulate volatile organic compound (VOC) 

emissions from gas wells, centrifugal compressors, reciprocating 

compressors, pneumatic controllers, storage vessels and leaking 

components at onshore natural gas processing plants, as well as 

sulfur dioxide (SO2) emissions from onshore natural gas 

processing plants. This rule sets cost-effective performance 

standards for: 

Gas wells. The rule covers any gas well that is “an onshore 

well drilled principally for production of natural gas.” Oil 

wells (wells drilled principally for the production of crude 

oil) are not subject to this rule. For fractured and refractured 

gas wells, the rule generally requires owners/operators to use 

reduced emissions completions, also known as “RECs” or “green 

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completions,” to reduce VOC emissions from well completions. To 

achieve these VOC reductions, owners and/or operators may use 

RECs or completion combustion devices, such as flaring, until 

January 1, 2015; as of January 1, 2015, owners and/or operators 

must use RECs and a completion combustion device. The rule does 

not require RECs where their use is not feasible, as specified 

in the rule. See sections IX.A and IX.B of this preamble for 

further discussion. 

Storage vessels. Individual storage vessels in the oil and 

natural gas production segment and the natural gas processing, 

transmission and storage segments with emissions equal to or 

greater than 6 tons per year (tpy) must achieve at least 95.0 

percent reduction in VOC emissions. See section IX.E of this 

preamble for further discussion. 

Certain controllers. The rule sets a natural gas bleed rate 

limit of 6 scfh for individual, continuous bleed, natural gasdriven pneumatic controllers located between the wellhead and 

the point at which the gas enters the transmission and storage 

segment. For individual, continuous bleed, natural gas-driven 

pneumatic controllers located at natural gas processing plants, 

the rule sets a natural gas bleed limit of zero scfh. See 

section IX.C of this preamble for further discussion. 

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Certain compressors. The rule requires a 95.0 percent 

reduction of VOC emissions from wet seal centrifugal compressors 

located between the wellhead and the point at which the gas 

enters the transmission and storage segment. The rule also 

requires measures intended to reduce VOC emissions from 

reciprocating compressors located between the wellhead and the 

point where natural gas enters the natural gas transmission and 

storage segment. Owners and/or operators of these compressors 

must replace the rod packing based on specified usage or time. 

See section IX.D of this preamble for further discussion. 

For onshore natural gas processing plants, this final 

action revises the existing NSPS requirements for leak detection 

and repair (LDAR) to reflect the procedures and leak thresholds 

established in the NSPS for Equipment Leaks of VOCs in the 

Synthetic Organic Chemicals Manufacturing Industry. This final 

action also revises the existing NSPS requirements for SO2 

emission reductions 99.8 percent to 99.9 percent based on 

reanalysis of the original data. 

National Emissions Standards for Hazardous Air Pollutants 

(NESHAP). This action also revises the NESHAP for glycol 

dehydration unit process vents and leak detection and repair 

(LDAR) requirements. In the final rule for major sources at oil 

and natural gas production facilities, we have lowered the leak 

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definition for valves at natural gas processing plants to 500 

parts per million (ppm) and thus require the application of LDAR 

procedures at this level. In this final rule, we also have 

established MACT standards for “small” glycol dehydration units, 

which were unregulated under the initial NESHAP. Covered glycol 

dehydrators are those with an actual annual average natural gas 

flow rate less than 85,000 standard cubic meters per day (scmd) 

or actual average benzene emissions less than 1 ton per year 

(tpy), and they must meet unit-specific limits for benzene, 

ethylbenzene, toluene and xylene (BTEX). 

In the final rule for major sources at natural gas 

transmission and storage facilities, we have established MACT 

standards for “small” glycol dehydrators also not regulated 

under the initial NESHAP. Covered glycol dehydrators are those 

with an actual annual average natural gas flow rate less than 

283,000 scmd or actual average benzene emissions less than 0.90 

Mg/yr, and they must meet unit-specific BTEX emission limits. v. 

See sections VII and X of this preamble for further discussion 

of both standards. 

3. Costs and Benefits 

Table 1 summarizes the costs and benefits of this action. 

See section XI of this preamble for further discussion. 

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TABLE 1. SUMMARY OF THE MONETIZED BENEFITS, SOCIAL COSTS AND NET

BENEFITS FOR THE FINAL OIL AND NATURAL GAS NSPS AND NESHAP 

AMENDMENTS IN 2015 (MILLIONS OF 2008$)1 

Final NSPS Final NESHAP 

Amendments 

Final NSPS and 

NESHAP 

Amendments 

Combined 

Total 

Monetized 

Benefits2 

N/A N/A N/A 

Total Costs3 -$15 million $3.5 million -$11 million 

Net Benefits N/A N/A N/A 

Nonmonetized 

Benefits4 

11,000 tons of

HAP 670 tons of HAP 12,000 tons ofHAP 

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

imply that there are no benefits or co-benefits of the rules; rather, it is a

reflection of the difficulties in modeling the direct and indirect impacts of

the reductions in emissions for this industrial sector with the data 

currently available.

3 The engineering compliance costs are annualized using a 7-percent discount

rate. The negative cost for the final NSPS reflects the inclusion of revenues

from additional natural gas and hydrocarbon condensate recovery that are

estimated as a result of the NSPS. Possible explanations for why there appear

to be negative cost control technologies are discussed in the engineering

costs analysis section in the Regulatory Impact Analysis (RIA).

4

 For the NSPS, reduced exposure to HAP and climate effects are co-benefits.

For the NESHAP, reduced VOC emissions, PM2.5 and ozone exposure, visibility and

vegetation effects and climate effects are co-benefits. The specific control

technologies for the final NSPS are anticipated to have minor secondary

disbenefits, including an increase of 1.1 million tons of carbon dioxide

(CO2), 550 tons of nitrogen oxides (NOx), 19 tons of PM, 3,000 tons of carbon

monoxide (CO) and 1,100 tons of total hydrocarbons (THC), as well as emission

reductions associated with the energy system impacts. The specific control 

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technologies for the NESHAP are anticipated to have minor secondary

disbenefits, but the EPA was unable to estimate the secondary disbenefits.

The net CO2-equivalent emission reductions are 18 million metric tons. 

B. Does this action apply to me? 

The regulated categories and entities potentially affected 

by the final standards are shown in Table 2 of this preamble. 

TABLE 2. INDUSTRIAL SOURCE CATEGORIES AFFECTED BY THIS ACTION 

Category

Industry . . . . 

NAICS code1 

211111 

Examples of regulated entities 

Crude Petroleum and Natural Gas 

Extraction 

211112 

221210 

Natural Gas Liquid Extraction 

Natural Gas Distribution 

486110 Pipeline Distribution of Crude

Oil 

486210 Pipeline Transportation of

Natural Gas 

Federal government . . . . Not affected. 

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

government

1

 North American Industry Classification System. 

This table is not intended to be exhaustive, but rather is 

meant to provide a guide for readers regarding entities likely 

to be affected by this action. If you have any questions 

regarding the applicability of this action to a particular 

entity, consult either the air permitting authority for the 

entity or your EPA regional representative as listed in 40 CFR 

60.4 or 40 CFR 63.13 (General Provisions). 

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

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1. What are the emission sources affected by the NSPS? 

The emission sources affected by the NSPS include well 

completions, pneumatic controllers, equipment leaks from natural 

gas processing plants, sweetening units at natural gas 

processing plants, reciprocating compressors, centrifugal 

compressors and storage vessels which are constructed, modified 

or reconstructed after August 23, 2011. Well completions subject 

to the NSPS are limited to the flowback period following 

hydraulic fracturing operations at a gas well affected facility. 

These completions include those conducted at newly drilled and 

fractured wells, as well as completions conducted following 

refracturing operations that may occur at various times over the 

life of the well. Pneumatic controllers affected by the NSPS 

include continuous bleed, natural gas-driven pneumatic 

controllers with a natural gas bleed rate greater than 6 scfh 

and which commenced construction after August 23, 2011, in the 

oil and natural gas production segment (except for gas 

processing plants) and continuous bleed natural gas-driven 

pneumatic controllers which commenced construction after August 

23, 2011, at natural gas processing plants. The NSPS applies to 

centrifugal compressors with wet seals and reciprocating 

compressors located in the natural gas production and processing 

segments. The NSPS also applies to equipment leaks from onshore 

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natural gas processing plants and to storage vessels located in 

the oil and natural gas production segment, the natural gas 

processing segment and the natural gas transmission and storage 

segment. The NSPS also affects sweetening units located onshore 

that process natural gas from onshore or offshore wells. 

2. What are the emission sources affected by the NESHAP? 

The emission sources that are affected by the Oil and 

Natural Gas Production NESHAP (40 CFR part 63, subpart HH) or 

the Natural Gas Transmission and Storage NESHAP (40 CFR part 63, 

subpart HHH) include glycol dehydrators and equipment leaks. 

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

In addition to being available in the docket, an electronic 

copy of this action will also be available on the World Wide Web 

(WWW). Following signature by the Administrator, a copy of the 

action will be posted on the EPA’s website at the following 

address: http://www.epa.gov/airquality/oilandgas. 

Additional information is available on the EPA’s RTR web 

site at http://www.epa.gov/ttn/atw/rrisk/oarpg.html. This 

information includes the most recent version of the rule, source 

category descriptions, detailed emissions and other data were 

used as inputs to the risk assessments. 

E. Judicial Review 

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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 section 307(d)(7)(B), only an objection to 

this final rule that was raised with reasonable specificity 

during the period for public comment (including any public 

hearing) can be raised during judicial review. This section also 

provides a mechanism for the EPA to convene a proceeding for 

reconsideration “[i]f the person raising an objection can 

demonstrate to the Administrator that it was impracticable to 

raise such objection within [the period for public comment] or 

if the grounds for such objection arose after the period for 

public comment (but within the time specified for judicial 

review) and if such objection is of central relevance to the 

outcome of the rule[.]” Any person seeking to make such a 

demonstration to us should submit a Petition for Reconsideration 

to the Office of the Administrator, Environmental Protection 

Agency, Room 3000, Ariel Rios Building, 1200 Pennsylvania Ave., 

NW, Washington, D.C. 20004, with a copy to the person listed in 

the preceding FOR FURTHER INFORMATION CONTACT section, and the 

Associate General Counsel for the Air and Radiation Law Office, 

Office of General Counsel (Mail Code 2344A), Environmental 

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Protection Agency, 1200 Pennsylvania Ave., NW, Washington, D.C. 

20004. Note, under CAA section 307(b)(2), the requirements 

established by this final rule may not be challenged separately 

in any civil or criminal proceedings brought by the EPA to 

enforce these requirements. 

III. Background Information on the NSPS and NESHAP 

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

1. What is the statutory authority for the NSPS? 

Section 111 of the CAA requires the EPA Administrator to 

list categories of stationary sources, if such sources cause or 

contribute significantly to air pollution, which may reasonably 

be anticipated to endanger public health or welfare. The EPA 

must then issue performance standards for such source 

categories. Whereas CAA section 112 standards are issued for new 

and existing stationary sources, standards of performance are 

issued for new and modified stationary sources. These standards 

are referred to as NSPS. The EPA has the authority to define the 

source categories, determine the pollutants for which standards 

should be developed, identify the facilities within each source 

category to be covered and set the emission level of the 

standards. 

CAA section 111(b)(1)(B) requires the EPA to “at least 

every 8 years review and, if appropriate, revise” performance 

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standards. However, the Administrator need not review any such 

standard if the “Administrator determines that such review is 

not appropriate in light of readily available information on the 

efficacy” of the standard. When conducting a review of an 

existing performance standard, the EPA has authority to revise 

that standard to add emission limits for pollutants or emission 

sources not currently regulated for that source category. 

In setting or revising a performance standard, CAA section 

111(a)(1) provides that performance standards are to “reflect 

the degree of emission limitation achievable through the 

application of the BSER which (taking into account the cost of 

achieving such reduction and any nonair quality health and 

environmental impact and energy requirements) the Administrator 

determines has been adequately demonstrated.” In this notice, we 

refer to this level of control as the BSER. In determining BSER, 

we typically conduct a technology review that identifies what 

emission reduction systems exist and how much they reduce air 

pollution, in practice. Next, for each control system 

identified, we evaluate its costs, secondary air benefits (or 

disbenefits) resulting from energy requirements and nonair 

quality impacts such as solid waste generation. Based on our 

evaluation, we would determine BSER. The resultant standard is 

usually a numerical emissions limit, expressed as a performance 

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level (i.e., a rate-based standard or percent control), that 

reflects the BSER. Although such standards are based on the 

BSER, the EPA may not prescribe a particular technology that 

must be used to comply with a performance standard, except in 

instances where the Administrator determines it is not feasible 

to prescribe or enforce a standard of performance. Typically, 

sources remain free to select any control measures that will 

meet the emission limits. Upon promulgation, an NSPS becomes a 

national standard to which all new sources must comply. 

2. What is the statutory authority for the NESHAP? 

Section 112 of the CAA establishes a two-stage regulatory 

process to address emissions of HAP from stationary sources. In 

the first stage, after the EPA has identified categories of 

sources emitting one or more of the HAP listed in section 112(b) 

of the CAA, section 112(d) of the CAA calls for us to promulgate 

NESHAP for those sources. “Major sources” are those that emit or 

have the potential to emit (PTE) 10 tpy or more of a single HAP 

or 25 tpy or more of any combination of HAP. For major sources, 

the technology-based emission standards must reflect the maximum 

degree of emission reductions of HAP achievable (after 

considering cost, energy requirements and nonair quality health 

and environmental impacts) and are commonly referred to as MACT 

standards. 

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MACT standards are set to reflect application of measures, 

processes, methods, systems or techniques, including, but not 

limited to, measures which, (1) reduce the volume of or 

eliminate pollutants through process changes, substitution of 

materials or other modifications, (2) enclose systems or 

processes to eliminate emissions, (3) capture or treat 

pollutants when released from a process, stack, storage or 

fugitive emissions point, (4) are design, equipment, work 

practice or operational standards (including requirements for 

operator training or certification) or (5) are a combination of 

the above. CAA sections 112(d)(2)(A)–(E). A MACT standard may 

take the form of a design, equipment, work practice or 

operational standard where the EPA first determines either that, 

(1) a pollutant cannot be emitted through a conveyance designed 

and constructed to emit or capture the pollutant or that any 

requirement for or use of such a conveyance would be 

inconsistent with law or (2) the application of measurement 

methodology to a particular class of sources is not practicable 

due to technological and economic limitations. CAA sections 

112(h)(1),(2). 

The MACT “floor” is the minimum control level allowed for 

MACT standards promulgated under CAA section 112(d)(3) and may 

not be based on cost considerations. For new sources, the MACT 

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floor cannot be less stringent than the emission control that is 

achieved in practice by the best-controlled similar source. The 

MACT floors for existing sources can be less stringent than 

floors for new sources, but cannot be less stringent than the 

average emission limitation achieved by the best-performing 12 

percent of existing sources in the category or subcategory (or 

the best-performing five sources for categories or subcategories 

with fewer than 30 sources). In developing MACT standards, we 

must also consider control options that are more stringent than 

the floor. We may establish standards more stringent than the 

floor based on the consideration of the cost of achieving the 

emissions reductions, any nonair quality health and 

environmental impacts and energy requirements. 

The EPA is then required to review these technology-based 

standards and to revise them “as necessary (taking into account 

developments in practices, processes, and control technologies)” 

no less frequently than every 8 years, under CAA section 

112(d)(6). In conducting this review, the EPA is not obliged to 

completely recalculate the prior MACT determination. NRDC v. 

EPA, 529 F.3d 1077, 1084 (D.C. Cir. 2008). 

The second stage in standard-setting focuses on reducing 

any remaining “residual” risk according to CAA section 112(f). 

This provision requires, first, that the EPA prepare a Report to 

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Congress discussing (among other things) methods of calculating 

risk posed (or potentially posed) by sources after 

implementation of the MACT standards, the public health 

significance of those risks and the EPA’s recommendations as to 

legislation regarding such remaining risk. The EPA prepared and 

submitted this report (Residual Risk Report to Congress, EPA– 

453/R–99–001) in March 1999. Congress did not act in response to 

the report, thereby triggering the EPA’s obligation under CAA 

section 112(f)(2) to analyze and address residual risk. 

CAA section 112(f)(2) requires us to determine for source 

categories subject to MACT standards, whether the emissions 

standards provide an ample margin of safety to protect public 

health. CAA section 112(f)(2) expressly preserves our use of a 

two-step process for developing standards to address any 

residual risk and our interpretation of “ample margin of safety” 

developed in the National Emission Standards for Hazardous Air 

Pollutants: Benzene Emissions from Maleic Anhydride Plants, 

Ethylbenzene/Styrene Plants, Benzene Storage Vessels, Benzene 

Equipment Leaks, and Coke By-Product Recovery Plants (Benzene 

NESHAP) (54 FR 38044, September 14, 1989). The first step in 

this process is the determination of acceptable risk. The second 

step provides for an ample margin of safety to protect public 

health, which is the level at which the standards must be set 

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(unless a more stringent standard is required to prevent an 

adverse environmental effect, taking into consideration costs, 

energy, safety and other relevant factors). 

If the MACT standards for HAP that are “classified as a 

known, probable, or possible human carcinogen do not reduce 

lifetime excess cancer risks to the individual most exposed to 

emissions from a source in the category or subcategory to less 

than 1-in-1 million,” the EPA must promulgate residual risk 

standards for the source category (or subcategory), as 

necessary, to provide an ample margin of safety to protect 

public health. In doing so, the EPA may adopt standards equal to 

existing MACT standards if the EPA determines that the existing 

standards are sufficiently protective. NRDC v. EPA, 529 F.3d 

1077, 1083 (D.C. Cir. 2008) (“If EPA determines that the 

existing technology-based standards provide an ‘ample margin of 

safety,’ then the Agency is free to readopt those standards 

during the residual risk rulemaking.”). As mentioned, the EPA 

must also adopt more stringent standards, if necessary, to 

prevent an adverse environmental effect,1

 but must consider cost, 

energy, safety and other relevant factors in doing so. 

1

 “Adverse environmental effect” is defined in CAA section 112(a)(7) as any

significant and widespread adverse effect, which may be reasonably

anticipated to wildlife, aquatic life or natural resources, including adverse

impacts on populations of endangered or threatened species or significant

degradation of environmental qualities over broad areas. 

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The terms “individual most exposed,” “acceptable level,” 

and “ample margin of safety” are not specifically defined in the 

CAA. However, CAA section 112(f)(2)(B) preserves the 

interpretation set out in the Benzene NESHAP, and the United 

States Court of Appeals for the District of Columbia Circuit has 

concluded that the EPA’s interpretation of CAA section 112(f)(2) 

is a reasonable one. See NRDC v. EPA, 529 F.3d at 1083 

(“[S]ubsection 112(f)(2)(B) expressly incorporates the EPA’s 

interpretation of the Clean Air Act from the Benzene standard, 

complete with a citation to the Federal Register”). See, also, A 

Legislative History of the Clean Air Act Amendments of 1990, 

volume 1, p. 877 (Senate debate on Conference Report). We 

notified Congress in the Residual Risk Report to Congress that 

we 

intended to use the Benzene NESHAP approach in making CAA 

section 

112(f) residual risk determinations (EPA–453/R–99–001, p. ES– 

11). 

In the Benzene NESHAP, we stated as an overall objective: 

* * * in protecting public health with an ample margin of 

safety, we strive to provide maximum feasible protection 

against risks to health from hazardous air pollutants by, 

(1) protecting the greatest number of persons possible to 

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an individual lifetime risk level no higher than 

approximately 1-in-1 million; and (2) limiting to no higher 

than approximately 1-in-10 thousand [i.e., 100-in-1 

million] the estimated risk that a person living near a 

facility would have if he or she were exposed to the 

maximum pollutant concentrations for 70 years. 

The agency also stated in the Residual Risk Report to Congress 

that “The EPA also considers incidence (the number of persons 

estimated to suffer cancer or other serious health effects as a 

result of exposure to a pollutant) to be an important measure of 

the health risk to the exposed population. Incidence measures 

the extent of health risk to the exposed population as a whole, 

by providing an estimate of the occurrence of cancer or other 

serious health effects in the exposed population.” The agency 

went on to conclude that “estimated incidence would be weighed 

along with other health risk information in judging 

acceptability.” As explained more fully in our Residual Risk 

Report to Congress, the EPA does not define “rigid line[s] of 

acceptability,” but considers rather broad objectives to be 

weighed with a series of other health measures and factors (EPA– 

453/R–99–001, p. ES–11). The determination of what represents an 

“acceptable” risk is based on a judgment of “what risks are 

acceptable in the world in which we live” (Residual Risk Report 

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to Congress, p. 178, quoting the Vinyl Chloride decision at 824 

F.2d 1165) recognizing that our world is not risk-free. 

In the Benzene NESHAP, we stated that “EPA will generally 

presume that if the risk to [the maximum exposed] individual is 

no higher than approximately 1-in-10 thousand, that risk level 

is considered acceptable.” 54 FR 38045. We discussed the maximum 

individual lifetime cancer risk (or maximum individual risk 

(MIR)) as being “the estimated risk that a person living near a 

plant would have if he or she were exposed to the maximum 

pollutant concentrations for 70 years.” Id. We explained that 

this measure of risk “is an estimate of the upper bound of risk 

based on conservative assumptions, such as continuous exposure 

for 24 hours per day for 70 years.” Id. We acknowledge that 

maximum individual lifetime cancer risk “does not necessarily 

reflect the true risk, but displays a conservative risk level 

which is an upper-bound that is unlikely to be exceeded.” Id. 

Understanding that there are both benefits and limitations to 

using maximum individual lifetime cancer risk as a metric for 

determining acceptability, we acknowledged in the 1989 Benzene 

NESHAP that “consideration of maximum individual risk * * * must 

take into account the strengths and weaknesses of this measure 

of risk.” Id. Consequently, the presumptive risk level of 100­

in-1 million (1-in-10 thousand) provides a benchmark for judging 

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the acceptability of maximum individual lifetime cancer risk, 

but does not constitute a rigid line for making that 

determination. 

The agency also explained in the 1989 Benzene NESHAP the 

following: “In establishing a presumption for MIR, rather than a 

rigid line for acceptability, the Agency intends to weigh it 

with a series of other health measures and factors. These 

include the overall incidence of cancer or other serious health 

effects within the exposed population, the numbers of persons 

exposed within each individual lifetime risk range and 

associated incidence within, typically, a 50-kilometer (km) 

exposure radius around facilities, the science policy 

assumptions and estimation uncertainties associated with the 

risk measures, weight of the scientific evidence for human 

health effects, other quantified or unquantified health effects, 

effects due to co-location of facilities and co-emission of 

pollutants.” Id. 

In some cases, these health measures and factors taken 

together may provide a more realistic description of the 

magnitude of risk in the exposed population than that provided 

by maximum individual lifetime cancer risk alone. As explained 

in the Benzene NESHAP, “[e]ven though the risks judged 

‘acceptable’ by the EPA in the first step of the Vinyl Chloride 

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inquiry are already low, the second step of the inquiry, 

determining an ‘ample margin of safety,’ again includes 

consideration of all of the health factors, and whether to 

reduce the risks even further.” In the ample margin of safety 

decision process, the agency again considers all of the health 

risks and other health information considered in the first step. 

Beyond that information, additional factors relating to the 

appropriate level are considered, including costs and economic 

impacts of controls, technological feasibility, uncertainties 

and any other relevant factors. Considering all of these 

factors, the agency will establish the standard at a level that 

provides an ample margin of safety to protect the public health, 

as required by CAA section 112(f). See 54 FR 38046. 

B. What is the litigation history? 

On January 14, 2009, pursuant to section 304(a)(2) of the 

CAA, WildEarth Guardians and the San Juan Citizens Alliance 

filed a complaint in the United States District Court for the 

District of Columbia and alleged that the EPA failed to meet its 

obligations under CAA sections 111(b)(1)(B), 112(d)(6) and 

112(f)(2) to take actions relative to the review/revision of the 

NSPS and the NESHAP with respect to the Oil and Natural Gas 

Production source category. On February 5, 2010, the Court 

entered a consent decree that, as successively modified, 

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required the EPA to sign by July 28, 2011,2 proposed standards 

and/or determinations not to issue standards pursuant to CAA 

sections 111(b)(1)(B), 112(d)(6) and 112(f)(2) and to take final 

action by April 3, 2012. On April 2, 2012, the consent decree 

was modified to change the date for final action to no later 

than April 17, 2012. 

C. What is the sector-based approach? 

Sector-based approaches are based on integrated assessments 

of industrial operations that consider multiple pollutants in a 

comprehensive and coordinated manner to manage emissions and CAA 

requirements. One of the many ways we can address sector-based 

approaches is by reviewing multiple regulatory programs together 

whenever possible, for example the NSPS and NESHAP, consistent 

with all applicable legal requirements. This approach 

essentially expands the technical analyses on costs and benefits 

of particular technologies, to consider the interactions of 

rules that regulate sources. The benefit of multi-pollutant and 

sector-based analyses and approaches includes the ability to 

identify optimum strategies, considering feasibility, cost 

impacts and benefits across the different pollutant types while 

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. 

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streamlining administrative and compliance complexities and 

reducing conflicting and redundant requirements, resulting in 

added certainty and easier implementation of control strategies 

for the sector under consideration. In order to benefit from a 

sector-based approach for the oil and gas industry, the EPA 

analyzed how the NSPS and NESHAP under consideration relate to 

each other and other regulatory requirements currently under 

review for oil and gas facilities. In this analysis, we looked 

at how the different control requirements that result from these 

requirements interact, including the different regulatory 

deadlines and control equipment requirements that result, the 

different reporting and recordkeeping requirements and 

opportunities for states to account for reductions resulting 

from this rulemaking in their State Implementation Plans (SIP). 

The requirements analyzed affect criteria pollutants, HAP and 

methane emissions from oil and natural gas processes and cover 

the NSPS and NESHAP reviews. 

As a result of the sector-based approach, this rulemaking 

will reduce conflicting and redundant requirements. Also, the 

sector-based approach streamlines the monitoring, recordkeeping 

and reporting requirements, thus, reducing administrative and 

compliance complexities associated with complying with multiple 

regulations. In addition, the sector-based approach in this rule 

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promotes a comprehensive control strategy that maximizes the cocontrol of multiple regulated pollutants while obtaining 

emission reductions as co-benefits. 

D. What are the health effects of pollutants emitted from the 

oil and natural gas sector? 

The final oil and natural gas sector NSPS and NESHAP 

amendments are expected to result in significant reductions in 

existing emissions and prevent new emissions from expansions of 

this industry. These emissions include HAP, VOC (a precursor to 

both PM2.5 and ozone formation) and methane (a GHG and a 

precursor to global ozone formation). These emissions are 

associated with substantial health effects, welfare effects and 

climate effects. One HAP of particular concern from the oil and 

natural gas sector is benzene, which is a known human 

carcinogen. PM2.5 is associated with health effects, including 

premature mortality for adults and infants, cardiovascular 

morbidity, such as heart attacks, hospital admissions and 

respiratory morbidity such as asthma attacks, acute and chronic 

bronchitis, hospital and emergency room visits, work loss days, 

restricted activity days and respiratory symptoms, as well as 

visibility impairment. Ozone is associated with health effects, 

including hospital and emergency department visits, school loss 

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days and premature mortality, as well as injury to vegetation 

and climate effects. 

IV. Summary of the Final NSPS Rule 

A. What are the final actions relative to the NSPS for the Crude 

Oil 

and Natural Gas Production source category? 

We are revising the existing NSPS, which regulate VOC 

emissions from equipment leaks and SO2 emissions from sweetening 

units at onshore gas processing plants. In addition, we are 

promulgating standards for several new oil and natural gas 

affected facilities. The final standards apply to affected 

facilities that commence construction, reconstruction or 

modification after August 23, 2011, the date of the proposed 

rule. 

The listed Crude Oil and Natural Gas Production source 

category covers, at a minimum, those operations for which we are 

establishing standards in this final rule. Table 3 summarizes 

the 40 CFR part 60, subpart OOOO standards. Further discussion 

of these changes may be found below in this section and in 

sections V and IX of this preamble. 

TABLE 3. SUMMARY OF 40 CFR PART 60, SUBPART OOOO EMISSION 

STANDARDS 

Affected Facility Pollutant Standard Compliance Dates 

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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, nonwildcat and nondelineation 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 

Centrifugal compressors

with wet seals VOC 

Reduce emissions by

95 percent 

[INSERT DATE 60 DAYS

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 scfh

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 SO2 

Reduce SO2 emissions 

based on sulfur 

feed rate and 

sulfur content of 

acid gas 

[INSERT DATE 60 DAYS

AFTER DATE OF 

PUBLICATION IN THE 

FEDERAL REGISTER] 

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1. Standards for Gas Well Affected Facilities 

We are finalizing operational standards for completions of 

hydraulically fractured and refractured gas wells. For purposes 

of this rule, well completion is defined as the flowback period 

beginning after hydraulic fracturing and ending with either well 

shut in or when the well continuously flows to the flow line or 

to a storage vessel for collection, whichever occurs first. The 

final rule applies to three subcategories of fractured and 

refractured gas wells for which well completion operations are 

conducted: (1) Wildcat (exploratory) and delineation gas wells; 

(2) non-wildcat and non-delineation gas wells for which the 

reservoir pressure is insufficient for a REC, commonly referred 

to as a “green completion,” to be performed, as determined by a 

simple calculation involving reservoir pressure, well depth and 

flow line pressure at the sales meter (we refer to these wells 

as “low pressure gas wells”) and (3) other fractured and 

refractured gas wells. For subcategory (3) wells, each well 

completion operation begun on or after January 1, 2015, must 

employ REC in combination with use of a completion combustion 

device to control gas not suitable for entering the flow line 

(we refer to this as REC with combustion). For well completion 

operations at subcategory (1) wells (exploratory and delineation 

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gas wells), subcategory (2) wells (low pressure gas wells) and 

for well completion operations begun prior to January 1, 2015, 

at subcategory (3) gas wells, the final rule requires the 

control of emissions using either REC with combustion or just a 

completion combustion device. Owners and operators are 

encouraged to use REC with combustion during this period. 

Well completions subject to the standards are gas well 

completions following hydraulic fracturing and refracturing 

operations. These completions include those conducted at newly 

drilled and fractured wells, as well as completions conducted 

following refracturing operations at various times over the life 

of the well. As we explained in the proposal preamble, a 

completion operation associated with refracturing performed at a 

well is considered a modification under CAA section 111(a), 

because physical change occurs to the well resulting in 

emissions increases during the refracturing and completion 

operation. In response to comment, we further clarify this point 

in the final rule, including providing a specific modification 

provision for well completions in lieu of the General Provisions 

in 40 CFR 60.14. For a more detailed explanation, please see 

section IX.A of this preamble. The modification determination 

and resulting applicability of NSPS to the completion operation 

following refracturing of gas wells is limited strictly to the 

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gas well affected facility and does not by itself trigger 

applicability beyond the wellhead to other ancillary components 

that may be at the well site such as existing storage vessels, 

process vessels, separators, dehydrators or any other components 

or apparatus (that is, such equipment is not part of the 

affected facility). 

The final rule provides that uncontrolled well completions 

conducted on gas wells that are subsequently refractured on or 

after the effective date of this rule are modifications and are 

subject to the NSPS. However, gas wells that undergo completion 

following refracturing are not considered modified and, as a 

result, are not affected facilities under the NSPS if the 

completion operation is conducted with the use, immediately upon 

flowback, of emission control techniques otherwise required on 

or after January 1, 2015, for new wells and satisfies other 

requirements, including notification, recordkeeping and 

reporting requirements. 

In the final rule, we provide for a streamlined 

notification process for well completions at gas well affected 

facilities consisting of an email pre-notification no later than 

2 days in advance of impending completion operations. The email 

must include information that had been part of the 30-day 

advance notification, as described in the proposed rule, 

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including contact information for the owner and operator, well 

identification, geographic coordinates of the well and planned 

date of the beginning of flowback. 

In the final rule, the recordkeeping and reporting 

requirements for well completions also provide for a 

streamlining option that owners and operators may choose in lieu 

of the standard annual reporting requirements. The standard 

annual report must include copies of all well completion records 

for each gas well affected facility for which a completion 

operation was performed during the reporting period. The 

alternative, streamlined annual report for gas well affected 

facilities requires submission of a list, with identifying 

information of all affected gas wells completed, electronic or 

hard copy photographs documenting REC in progress for each well 

for which REC was required and the self-certification required 

in the standard annual report. The operator retains a digital 

image of each REC in progress. The image must include a digital 

date stamp and geographic coordinates stamp to help link the 

photograph with the specific well completion operation. 

2. Standards for Compressor Affected Facilities 

The final rule requires measures to reduce VOC emissions 

from centrifugal and reciprocating compressors. Compressors 

located at the wellhead or in the transmission, storage and 

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distribution segments are not covered by this final rule and, 

therefore, are not affected facilities. The final rule contains 

standards for wet seal centrifugal compressors located in the 

natural gas production segment and the natural gas processing 

segment up the point at which the gas enters the transmission 

and storage segment. The final standards require 95.0 percent 

reduction of the emissions from each wet seal centrifugal 

compressor affected facility. The standard can be achieved by 

capturing and routing the emissions to a control device that 

achieves an emission reduction of 95.0 percent. 

The operational standards for reciprocating compressors in 

the final rule require replacement of the rod packing based on 

usage. The owner or operator of a reciprocating compressor 

affected facility is required to change the rod packing 

immediately when hours of operation reach 26,000 hours 

(equivalent to 36 months of continuous usage). Alternatively, 

owners or operators can elect to change the rod packing every 36 

months in lieu of monitoring compressor operating hours. An 

owner or operator who elects to meet the 26,000 hour requirement 

is required to monitor the duration (in hours) that the 

compressor is operated, beginning on the date of initial startup 

of the reciprocating compressor affected facility, or on the 

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date of the previous rod packing replacement, whichever is 

later. 

3. Standards for Pneumatic Controller Affected Facilities 

We are also finalizing pneumatic controller VOC standards. 

The affected facility is a continuous bleed, natural gas-driven 

pneumatic controller with a natural gas bleed rate greater than 

6 scfh for which construction commenced after August 23, 2011, 

located (1) in the oil production segment between the wellhead 

and the point of custody transfer to an oil pipeline; or (2) in 

the natural gas production segment, excluding natural gas 

processing plants, between the wellhead and the point at which 

the gas enters the transmission and storage segment. Except for 

controllers located at natural gas processing plants, each 

continuous bleed, natural gas-driven pneumatic controller that 

emits more than 6 scfh is an affected facility if it is 

constructed or modified after August 23, 2011. Pneumatic 

controllers with a bleed rate of 6 scfh or less in the oil and 

natural gas production segment and all pneumatic controllers 

located in the natural gas transmission, storage and 

distribution segments are not covered by this final rule and, 

therefore, are not affected facilities. At natural gas 

processing plants, the affected facility is each individual 

continuous bleed natural gas-operated pneumatic controller, and 

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the final rule includes a natural gas bleed rate limit of zero 

scfh. The final emission standards for pneumatic controllers at 

natural gas processing plants reflect the emission level 

achievable from the use of non-natural gas-driven pneumatic 

controllers. At other locations in the oil and natural gas 

production segment, the final rule includes a natural gas bleed 

rate limit of 6 standard cubic feet of gas per hour for an 

individual pneumatic controller. The standards provide 

exemptions in cases where it has been demonstrated that the use 

of a natural gas-driven pneumatic controller with a bleed rate 

above the applicable standard is required. However, as discussed 

in section IX.C, the EPA is allowing a 1-year phase-in period 

for pneumatic controllers in the final rule. 

4. Standards for Storage Vessels 

The final rule contains VOC standards for new, modified or 

reconstructed storage vessels located in the oil and natural gas 

production, natural gas processing and natural gas transmission 

and storage segments. The final rule, which applies to 

individual storage vessels, requires that storage vessels with 

VOC emissions equal to or greater than 6 tpy achieve at least 

95.0 percent reduction in VOC emissions. For storage vessels 

constructed, modified or reconstructed at well sites with no 

wells already in production at the time of construction, 

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modification or reconstruction, the final rule provides a 30-day 

period from startup for the owner or operator to determine 

whether the magnitude of VOC emissions from the storage vessel 

will be at least 6 tpy. If the storage vessel requires control, 

the final rule provides an additional 30 days for the control 

device to be installed and operational. For storage vessels 

constructed, modified or reconstructed at well sites with one or 

more wells already in production at the time of construction, 

modification or reconstruction, these estimation and 

installation periods are not provided because an estimate of VOC 

emissions can be made using information on the liquid production 

characteristics of the existing wells. 

In addition, the final rule provides for a 1-year phase-in 

period for storage vessel controls. Refer to section IX.E.4 of 

this preamble for further discussion. 

5. Standards for Affected Facilities Located at Onshore Natural 

Gas Processing Plants 

For onshore natural gas processing plants, we are revising 

the existing NSPS requirements for LDAR to reflect the 

procedures and leak thresholds established by 40 CFR 60, subpart 

VVa. Subpart VVa lowers the leak definition for valves from 

10,000 ppm to 500 ppm, and requires the monitoring of 

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connectors. Pumps, pressure relief devices and open-ended valves 

or lines are also monitored. 

6. Standards for Sweetening Unit Affected Facilities at Onshore 

Natural Gas Processing Plants 

The final rule regulates SO2 emissions from natural gas 

processing plants by requiring affected facilities to reduce SO2 

emissions by recovering sulfur. The final rule incorporates the 

provisions of 40 CFR part 60, subpart LLL into 40 CFR part 60, 

subpart OOOO, and minor revisions were made to adapt the subpart 

LLL language to subpart OOOO. The final rule also increased the 

SO2 emission reduction standard from the subpart LLL requirement 

of 99.8 percent to 99.9 percent for units with sulfur production 

rate of at least 5 long tons per day. This change is based on 

reanalysis of the original data used in the subpart LLL BSER 

analysis. 

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

NSPS? 

The revisions to the existing NSPS standards and the new 

NSPS standards promulgated in this action are effective on 

[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]. 

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

The previous section summarized the requirements that the 

EPA is finalizing in this rule. This section will discuss in 

greater detail the key changes the EPA has made since proposal. 

These changes result from the EPA’s review of the additional 

data and information provided to us and our consideration of the 

many substantive and thoughtful comments submitted on the 

proposal. 

We believe the changes make the final rule more flexible 

and cost-effective, address concerns with equipment 

availability, streamline recordkeeping and reporting 

requirements and improve clarity, while fully preserving or 

improving the public health and environmental protection 

required by the CAA. 

A. Gas Well Affected Facilities 

We have revised the requirements for gas well affected 

facilities since proposal in response to comment. The final rule 

applies to three subcategories of fractured and refractured gas 

wells for which well completion operations are conducted: (1) 

wildcat (exploratory) and delineation gas wells; (2) non-wildcat 

and non-delineation gas wells for which the reservoir pressure 

is insufficient for a REC to be performed, as determined by a 

simple calculation involving reservoir pressure, well depth and 

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flow line pressure at the sales meter (we refer to these wells 

as “low pressure gas wells”); and (3) other fractured and 

refractured gas wells. In the proposed 40 CFR part 60, subpart 

OOOO, upon promulgation of this rule, each well completion or 

recompletion at a non-exploratory or non-delineation well would 

have had to employ REC with combustion. Because of uncertainties 

in the supply of equipment and labor over the near-term, we are 

now requiring this work practice standard for completion 

operations begun at subcategory (3) gas wells (non-exploratory 

and non-delineation wells) on or after January 1, 2015. Until 

this date, flowback emissions must either be controlled using 

REC or routed to a completion combustion device unless it is 

technically infeasible or unsafe to do so. Owners and operators 

are encouraged to use REC when available during this period. 

Completion operations at subcategory (1) gas wells (wildcat and 

delineation wells) and subcategory (2) gas wells (non-wildcat 

and non-delineation low pressure gas wells) begun on or after 

[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 

combustion device alone unless it is technically infeasible or 

unsafe to do so. 

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The final rule includes a specific modification provision 

for well completions in lieu of the General Provisions in 40 CFR 

60.14. For a more detailed explanation, please see section IX.A 

of this preamble. In addition, we have revised the definition of 

“flowback period” to more clearly define when the flowback 

period begins and ends. 

In the proposed rule, all completions at existing wells 

(i.e., those originally constructed on or before August 23, 

2011) that are subsequently fractured or refractured were 

considered to be modifications. In the final rule, completions 

of wells that are refractured on or after the rule’s effective 

date are not considered modified and, as a result, are not 

affected facilities under the NSPS, if the completion operation 

is conducted with the use, immediately upon flowback, of 

emission control techniques required on or after January 1, 

2015, for new wells and satisfies other requirements, including 

notification, recordkeeping and reporting requirements. 

In the proposed rule, we prescribed specific equipment to 

accomplish an REC. In the final rule, we have removed the 

required equipment specifications for REC and added operational 

standards that will result in minimizing emissions and 

maximizing product recovery. In light of the comments received, 

we conclude that it is inappropriate and unnecessary to prohibit 

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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 

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streamlining option that owners and operators may choose in lieu 

of the standard annual reporting requirements. The standard 

annual report must include copies of all well completion records 

for each gas well affected facility for which a completion 

operation was performed during the reporting period. The 

alternative, streamlined annual report for gas well affected 

facilities requires submission of a list, with identifying 

information of all affected gas wells completed, electronic or 

hard copy photographs documenting REC in progress for each well 

for which REC was required and the self-certification required 

in the standard annual report. The operator retains a digital 

image of each REC in progress. The image must include a digital 

date stamp and geographic coordinates stamp to help link the 

photograph with the specific well completion operation. 

Refer to section IX.B of this preamble and the Responses to 

Comments document, available in the docket, for detailed 

discussion regarding these changes. 

B. Centrifugal and Reciprocating Compressor Affected Facilities 

In the final rule, we have made changes that impact both 

reciprocating and centrifugal compressor affected facilities in 

response to comments requesting clarification. Because we are 

not finalizing standards covering them, centrifugal and 

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reciprocating compressors located in the transmission, storage 

and distribution segments are not affected facilities. 

In the proposed rule, all centrifugal compressors would be 

required to use dry seals. We had also solicited comment on the 

use of wet seals with controls as an acceptable alternative to 

dry seals due to potential technical infeasibility of using dry 

seals for certain applications. Based on comments received, the 

final rule requires that centrifugal compressors with wet seals 

reduce emissions by 95.0 percent. The standard can be achieved 

by capturing and routing emissions from the wet seal fluid 

degassing system to a control device that reduces VOC emissions 

by 95.0 percent. Testing, monitoring, recordkeeping, reporting 

and notification requirements associated with the control 

devices have also been added. In contrast to the proposed rule, 

in the final rule, centrifugal compressors with dry seals are 

not affected facilities. More detailed discussion of this change 

is presented in section IX.D of this preamble. 

As proposed, owners or operators of reciprocating 

compressor affected facilities were required to change rod 

packing after 26,000 hours of operation. This is equivalent to 

approximately 36 months of continuous operation. Based on 

comments we received, we are changing the final rule to provide 

operators the option of changing the rod packing every 36 months 

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instead of tracking compressor hours of operation and changing 

rod packing after 26,000 hours of operation. 

Refer to section IX.D of this preamble and the Responses to 

Comments document, available in the docket, for detailed 

discussion regarding these changes. 

C. Pneumatic Controller Affected Facilities 

For pneumatic controller affected facilities located in the 

oil and natural gas production segments, we have revised the 

definition of pneumatic controller affected facility from a 

single pneumatic controller to a single, continuous bleed, 

natural gas-driven pneumatic controller with a continuous bleed 

rate greater than 6 scfh for which construction, modification or 

reconstruction commenced after August 23, 2011. At natural gas 

processing plants, individual continuous bleed natural gasoperated pneumatic controllers for which construction, 

modification or reconstruction commenced after August 23, 2011, 

are affected facilities under this rule. As explained further in 

section IX.C of this preamble, this change provides clarity by 

more specifically defining the pneumatic controllers we intended 

to regulate in this final rule. In addition, only pneumatic 

controllers located prior to the point at which the gas enters 

the transmission and storage segment are subject to the NSPS. 

Because we are not finalizing standards covering them, 

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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 affected facility. We believe this is necessary for at 

least two reasons. First, owners and operators would demonstrate 

compliance based on information in the manufacturers’ 

specification. We have concluded that such information is not 

always included in current manufacturers’ specifications and a 

period of time is required for manufacturers to test their 

products and modify specifications to include the information. 

Second, we are not aware of any add-on control device that is or 

can be used to reduce VOC emissions from gas-driven pneumatic 

devices. 

Finally, language in the proposed rule could have been 

interpreted to mean that all pneumatic controllers installed in 

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any year after the proposal date must be reported each year, 

rather than those installed only during the reporting period. In 

order to clarify and streamline the recordkeeping and reporting 

requirements associated with pneumatic controllers, we are 

requiring only information concerning those affected facilities 

constructed, modified or reconstructed during the reporting 

period to be included in the annual report. 

Refer to section IX.C of this preamble and the Responses to 

Comments document, available in the docket, for detailed 

discussion regarding these changes. 

D. Storage Vessel Affected Facilities 

We have modified the definition of “storage vessel” to 

exclude surge control vessels, knockout vessels and pressure 

vessels designed to operate without emissions to the atmosphere. 

In addition, we have clarified that we consider a storage vessel 

that is skid-mounted or permanently attached to something that 

is mobile (such as trucks, railcars, barges or ships) to be 

subject to 40 CFR part 60, subpart OOOO if it is intended to be 

located at a site for at least 180 consecutive days. 

In the proposed rule, we established a throughput threshold 

for storage vessels below which they were not subject to the 

NSPS. In order to remove confusion with respect to the emission 

factors used to develop the throughput threshold and to address 

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comments indicating significant difficulty measuring throughput, 

we have revised the final rule such that storage vessels that 

emit 6 tpy of VOC or more are subject to the NSPS, based on our 

analysis in the proposed rule showing that the proposed NSPS is 

cost-effective for storage vessels with that level of VOC 

emissions. In the final rule, for storage vessels constructed, 

modified or reconstructed at well sites with no wells already in 

production at the time of construction, the final rule provides 

a 30-day period for the owner or operator to determine whether 

the magnitude of VOC emissions from the storage vessel will be 

at least 6 tpy. If the storage vessel requires control, the 

final rule provides an additional 30 days for the control device 

to be installed and operational. For storage vessels 

constructed, modified or reconstructed at well sites with one or 

more wells already in production at the time of construction, 

modification or reconstruction, VOC emissions can be determined 

prior to startup. Accordingly, these estimation and installation 

periods are not necessary and, therefore, not provided. 

Several requirements for storage vessels in the proposed 

rule pointed to 40 CFR part 63, subpart HH (the Oil and Natural 

Gas Production NESHAP). However, subpart HH regulates HAP while 

this NSPS regulates VOC. Therefore, in order to eliminate 

confusion caused by cross-referencing another regulation and to 

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tailor the requirements for VOC regulation, we have incorporated 

the storage vessel requirements from subpart HH into 40 CFR part 

60, subpart OOOO and modified those requirements, as appropriate 

for this rule. 

In the proposed rule, each storage vessel required to 

reduce emissions would have to comply upon promulgation. In the 

final rule, owners or operators are allowed a 1-year phase-in 

beginning [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 determining control efficiency. In 

addition, we believe that owners or operators will require a 

period of time to establish the need for controls and install 

them where called for. The 1-year phase-in will also allow 

owners or operators the necessary time to establish the need for 

a control device and procure and install the equipment. 

Refer to section IX.E of this preamble and the Responses to 

Comments document, available in the docket, for detailed 

discussion regarding these changes. 

E. Equipment Leaks Affected Facilities and Sweetening Unit 

Affected Facilities at Onshore Natural Gas Processing Plants 

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We have revised the identification of affected facilities 

for equipment leaks at natural gas processing plants. We 

proposed that compressors and equipment (as defined in the rule) 

located at onshore natural gas processing plants were affected 

facilities. As discussed above, compressors (reciprocating and 

centrifugal) have requirements under 40 CFR part 60, subpart 

OOOO that extend beyond the natural gas processing plant. To 

remove the duplicative requirements for compressors at natural 

gas processing plants, we have revised the identification of 

affected facility to exclude compressors from the standards that 

apply to equipment leaks at onshore natural gas processing 

plants. Refer to the Responses to Comments document, available 

in the docket, for detailed discussion regarding these affected 

facilities. 

F. Changes to Notification, Recordkeeping and Reporting 

Requirements 

In response to comment expressing concern with the burdens 

associated with demonstrating and monitoring compliance, we have 

reanalyzed the notification, recordkeeping and reporting 

requirements in the proposed rule and eliminated duplicative and 

unnecessary requirements for all emission points. For well 

completions, compressors, pneumatic controllers and storage 

vessels, we have removed the General Provisions notification 

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requirements in 40 CFR 60.7(a)(1), (3) and (4). These 

requirements relate to notification of construction and initial 

performance testing and are more suited to construction of more 

traditional facilities (e.g., gas processing plants, refineries 

and chemical plants) than the numerous individual pieces of 

apparatus (e.g., individual pneumatic controllers, compressor 

and storage vessels) that are “affected facilities” under this 

final rule. Specific notification and initial compliance 

demonstration requirements in the final rule make the General 

Provisions notification requirements unnecessary for gas well 

affected facilities. 

As mentioned previously, we have also streamlined the 

notification, recordkeeping and reporting requirements for gas 

well affected facilities. In place of a written notification of 

each well completion operation 30 days prior to the completion, 

owners or operators must submit a notification no later than 2 

days prior to the date of the completion. This notification may 

be submitted by email. To avoid duplicative and potentially 

conflicting advance notification requirements, the final rule 

provides that owners or operators who are subject to state 

regulations that require advance notification of well 

completions and have met those notification requirements are 

considered to have met the advance notification requirements of 

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the NSPS. Additionally, in lieu of the standard annual reporting 

requirements, the final rule allows submission of an annual 

report for gas well affected facilities that consists only of a 

list, with identifying information of all affected gas wells 

completed, electronic or hard copy photographs documenting REC 

in progress for each well for which REC was required and the 

self-certification required in the standard annual report. 

In the affirmative defense provisions of the rule, a 

citation was corrected, minor wording changes were made and 

reporting requirements were refined. The provisions we retained 

in the final rule are those we believe are necessary to assure 

regulatory agencies and the public that the owner or operator is 

in compliance with the final rule. Refer to section IX.F of this 

preamble and the Responses to Comments document, available in 

the docket, for detailed discussion regarding these changes. 

VI. Summary of the Final NESHAP Rules 

A. What are the final rule actions relative to the Oil and 

Natural Gas Production (subpart HH) source category? 

Table 4 summarizes the changes to 40 CFR part 63, subpart 

HH. Further discussion of these changes may be found below in 

this section and in sections VII and X of this preamble. 

TABLE 4. SUMMARY OF CHANGES TO 40 CFR PART 63, SUBPART HH 

Affected 

Source Nature of Change Standard 

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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/scmppmv 

“Associated 

equipment” 

Revised definition to 

exclude all storage

vessels N/A 

Valves – 

equipment

leaks 

Revised definition of 

leak 

LDAR for valves must be applied at

500 ppm 

All affected 

sources 

Eliminated exemption from

compliance during periods

of startup, shutdown and

malfunction Standards apply at all times 

Pursuant to CAA sections 112(d)(2) and (3), we have 

established MACT standards for small glycol dehydrators that 

were not regulated in the initial NESHAP. In addition, we have 

revised the definition of “associated equipment” to exclude from 

the definition of that term all storage vessels, not just those 

with potential for flash emissions (PFE). 

With regard to our CAA section 112(d)(6) review, we 

conclude that there have been no developments in practices, 

processes or control technologies for large glycol dehydrators 

and storage vessels with PFE. As noted at proposal, however, 

there have been relevant developments for equipment leaks, and 

we are finalizing the proposed revisions to the leak definition 

for valves at natural gas processing plants. Specifically, under 

CAA section 112(d)(6), we revised the leak definition for valves 

to 500 ppm, thus requiring the application of the leak detection 

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and repair requirement at this lower detection level. We did not 

make other revisions to the standards pursuant to our CAA 

section 112(d)(6) review. Our review under CAA section 112(f)(2) 

also did not result in revision to the standards. We found that 

the MACT standards in 40 CFR part 63, subpart HH (coupled with 

the new MACT standard for small glycol dehydrators) provide an 

ample margin of safety to protect public health and prevent 

adverse environmental effects. Accordingly, we are re-adopting 

those standards to satisfy the requirements of CAA section 

112(f). 

Additionally, we amended 40 CFR part 63, subpart HH to 

apply the standards at all times and made other revisions 

relative to periods of startup, shutdown and malfunction. 

Lastly, the final rule revises and adds certain testing and 

monitoring and related notification, recordkeeping and reporting 

requirements and makes certain other minor technical revisions 

to the NESHAP. 

1. Standards for Small Glycol Dehydration Units 

In this final rule, we have established MACT standards 

under CAA sections 112(d)(2) and (3) for small glycol 

dehydration units, which were left unregulated in the initial 

NESHAP. This subcategory consists of glycol dehydrators with an 

actual annual average natural gas flowrate less than 85,000 

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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 

(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 the final rule, as a result of our technology review 

under CAA section 112(d)(6), we are revising the leak definition 

for valves to 500 ppm, thus requiring the application of the 

LDAR requirement at this lower detection level. This leak 

definition applies only to valves at natural gas processing 

plants, and not other components. 

3. Notification, Recordkeeping and Reporting Requirements 

The final rule revises certain recordkeeping requirements 

of 40 CFR part 63, subpart HH. Specifically, facilities using 

carbon adsorbers as a control device are required to keep 

records of their carbon replacement schedule and records for 

each carbon replacement. In addition, owners and operators are 

required to keep records of the occurrence and duration of each 

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malfunction of operation (i.e., process equipment) or the air 

pollution control equipment and monitoring equipment. 

In conjunction with the new MACT standards for small 

existing glycol dehydration units, owners and operators of such 

affected units are required to submit an initial notification 

within 1 year after they become subject to the provisions of 

this subpart or by [INSERT DATE 1 YEAR AND 60 DAYS AFTER DATE OF 

PUBLICATION IN THE FEDERAL REGISTER], whichever is later. 

The final amendments to the NESHAP also include additional 

requirements for the contents of the periodic reports. The 

periodic reports are required to include periodic test results 

and information regarding any carbon replacement events that 

occurred during the reporting period. Additionally, periodic 

reports are required to include the number, duration, and a 

brief description for each type of malfunction which occurred 

during the reporting period and which caused or may have caused 

any applicable emission limitation to be exceeded. The periodic 

report is also required to include a description of actions 

taken by an owner or operator during a malfunction of an 

affected source to minimize emissions, including actions taken 

to correct a malfunction. 

B. What are the final rule amendments for the Natural Gas 

Transmission and Storage (subpart HHH) source category? 

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Table 5 summarizes the changes to 40 CFR part 63, subpart 

HHH. Further discussion of these changes may be found below in 

this section and in sections VII and X of this preamble. 

TABLE 5. SUMMARY OF CHANGES TO 40 CFR PART 63, SUBPART HHH 

Affected 

Source Nature of Change Standard 

Small glycol

dehydrators 

Established MACT 

standards for previously

unregulated source 

BTEX emission limit: 

New sources – 5.44x10-5 g/scm-ppmv

Existing sources – 3.01x10-4 g/scmppmv 

All affected 

sources 

Eliminated exemption from

compliance during periods

of startup, shutdown and

malfunction Standards apply at all times 

Pursuant to CAA section 112(d)(2) and (3), we have 

established MACT standards for small glycol dehydrators that 

were not regulated in the initial NESHAP. We have also amended 

40 CFR part 63, subpart HHH to apply the standards at all times, 

and made other revisions relative to periods of startup, 

shutdown and malfunction. Lastly, the final rule revises and 

adds certain testing and monitoring and related notification, 

recordkeeping and reporting requirements, as well as makes other 

minor technical revisions to the NESHAP. 

With regard to our CAA section 112(d)(6) review, we 

conclude that there have been no developments in practices 

processes or control technologies for large glycol dehydrators. 

We also found that the MACT standards in 40 CFR part 63, subpart 

HHH (coupled with the new MACT standard for small glycol 

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dehydrators) provide an ample margin of safety to protect public 

health and prevent adverse environmental effects. Accordingly, 

we are re-adopting those standards to satisfy the requirements 

of CAA section 112(f). Thus, our reviews under CAA sections 

112(d)(6) and 112(f)(2) did not result in any revisions to the 

standards. 

1. Standards for Glycol Dehydration Units 

In this final rule, we have established MACT standards for 

small glycol dehydration units in the Natural Gas Transmission 

and Storage source category. This subcategory consists of glycol 

dehydrators with an actual annual average natural gas flowrate 

less than 283,000 scmd or actual average benzene emissions less 

than 0.9 Mg/yr. The final MACT standard for this subcategory of 

small dehydrators requires existing affected sources to meet a 

unit-specific BTEX emission limit of 3.01x10-4 grams BTEX/scmppmv and new affected sources are required to meet a BTEX limit 

of 5.44x10-5 grams BTEX/scm-ppmv. 

2. Notification, Recordkeeping and Reporting Requirements 

The final rule revises certain recordkeeping requirements 

of 40 CFR part 63, subpart HHH. Specifically, facilities using 

carbon adsorbers as a control device are required to keep 

records of their carbon replacement schedule and records for 

each carbon replacement. In addition, owners and operators are 

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required to keep records of the occurrence and duration of each 

malfunction of operation (i.e., process equipment) or the air 

pollution control equipment and monitoring equipment. 

In conjunction with the promulgation of the MACT standards 

for small glycol dehydration units, the final rule requires that 

owners and operators of such affected units submit an initial 

notification within 1 year after the unit becomes subject to the 

provisions of this subpart or by [INSERT DATE 1 YEAR AND 60 DAYS 

AFTER DATE OF PUBLICATION IN THE FEDERAL REGISTER], whichever is 

later. 

The final amendments to the NESHAP also include additional 

requirements for the contents of the periodic reports. For 40 

CFR part 63, subpart HHH, the periodic reports are required to 

include periodic test results and information regarding any 

carbon replacement events that occurred during the reporting 

period. Additionally, periodic reports are required to include 

the number, duration, and a brief description for each type of 

malfunction which occurred during the reporting period and which 

caused or may have caused any applicable emission limitation to 

be exceeded. The periodic report is also required to include a 

description of actions taken by an owner or operator during a 

malfunction of an affected source to minimize emissions, 

including actions taken to correct a malfunction. 

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C. What is the effective date of this final rule and compliance 

dates for the standards? 

The effective date of this rule is [INSERT DATE 60 DAYS 

AFTER DATE OF PUBLICATION IN THE FEDERAL REGISTER]. 

The compliance date for new affected sources (those that 

commenced construction or reconstruction on or after August 23, 

2011) is immediately upon initial startup or the effective date 

of the standards,[INSERT DATE 60 DAYS AFTER DATE OF PUBLICATION 

IN THE FEDERAL REGISTER], whichever is later. 

The compliance date for existing small glycol dehydration 

units that are subject to MACT for the first time (i.e., those 

that commenced construction before August 23, 2011) is [INSERT 

DATE 3 YEARS AND 60 DAYS AFTER THE DATE OF PUBLICATION IN THE 

FEDERAL REGISTER]. 

An affected source at a production field facility that 

constructed before August 23, 2011, that was previously 

determined to be an area source but becomes a major source on 

[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. 

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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 since 

Proposal 

The previous section described the requirements that the 

EPA is finalizing in this rule. This section discusses in 

greater detail the key changes the EPA is making from the 

proposal. These changes result from the EPA’s review of the 

additional data and information provided to us and our 

consideration of the substantive comments submitted on the 

proposal. 

We have retained the same approach and methodology to 

establishing the standards as described at proposal. We have, 

however, made some changes in response to comments, which are 

described further below. One change resulted in revisions to the 

MACT emission limits for small glycol dehydration units. In 

addition, based on the comments received, we are not finalizing 

the MACT standard for the subcategory of storage vessels without 

the PFE, which was a subcategory that was left unregulated in 

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the 1999 40 CFR part 63, subpart HH rule. Specifically, based on 

our review of the comments, we believe that we need additional 

data and information to set an emission standard for storage 

vessels without the PFE, and we intend to collect the additional 

data and propose MACT emission standards under section 112(d)(2) 

and (3) of the CAA for such storage vessels. Finally, we are 

retaining the 0.9 Mg/yr compliance option for large dehydration 

units. 

A. What are the significant changes since proposal for the Oil 

and Natural Gas Production (subpart HH) source category? 

1. Changes made to amendments proposed under the authority of 

CAA sections 112(d)(2) and (3). 

Under the authority of sections 112(d)(2) and (3) of the 

CAA, we proposed amendments to 40 CFR part 63, subpart HH by 

adding requirements for previously unregulated units; 

specifically, we proposed standards for small glycol dehydration 

units and storage vessels without the PFE. 

In the final amendments for 40 CFR part 63, subpart HH, we 

have revised the proposed MACT standards for small glycol 

dehydration units in response to comments that we did not take 

into account variability in the development of the MACT floor. 

In our proposal, the MACT standards for existing affected 

sources was a unit-specific BTEX limit of 1.10x10-4 g BTEX/scmThis document is a prepublication version, signed by EPA Administrator, Lisa P. Jackson on 4/17/2012. We have

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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 

dehydration 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 is documented in the Response to Comments document 

and a technical memorandum, both of which are in the docket. 

Finally, as noted above, in response to comments, we are 

not finalizing MACT standards for storage vessels without the 

PFE in this rule. We received numerous comments expressing 

concerns with how we established the proposed standards for this 

subcategory. In response to such comments, we have re-evaluated 

the proposed MACT standards and concluded that we need (and 

intend to gather) additional data on these sources in order to 

analyze and establish MACT emission standards for this 

subcategory of storage vessels under section 112(d)(2) and (3) 

of the CAA. See the Response to Comments document for additional 

discussion. 

2. Changes Made to Amendments Proposed Under the Authority of 

CAA Section 112(f)(2) 

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We proposed to eliminate the 0.9 Mg/yr benzene compliance 

option for large glycol dehydration units because, in the 

proposed rule, we estimated that the emissions allowed as the 

result of this compliance option resulted in estimated cancer 

risks up to 400-in-1-million. We received multiple comments 

concerning our proposed risk estimate. After reviewing these 

comments, we discovered that we had significantly overestimated 

the allowable emissions associated with this compliance option. 

First, for several sources, including the source that we 

predicted had the 400-in-1 million MIR, we used an incorrect 

factor (or multiplier) to scale up actual emissions associated 

with sources that could utilize the compliance option level of 

0.9 Mg/yr to allowables. We used an incorrect factor due to an 

inadvertent transcription error in our calculations. Second, we 

learned that the risk assessment supporting the proposed rule 

erroneously included several area sources, which are not subject 

to 40 CFR part 63, subpart HH and thus should not have been 

included in the CAA section 112(f) risk assessment. After 

revising the risk assessment to remove area sources, and 

considering the MACT standard promulgated today for small glycol 

dehydrators pursuant to CAA sections 112(d)(2) and (3), the MIR 

for the Oil and Natural Gas Production source category based on 

actual and allowable emissions is 10-in-1 million, compared to 

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the 400-in-1 million3 based on allowable emissions and 40-in-1 

million based on actual emissions that were estimated in the 

proposed rule. 

As the result of our revised risk analysis, we have 

determined that approximately 120,000 people are estimated to 

have cancer risks at or above 1-in-1 million, compared to 

160,000 people estimated in the proposed rule. Total estimated 

cancer incidence from the source category is 0.02 excess cancer 

cases per year, or one case in every 50 years. This estimate is 

unchanged from the proposed rule because the incidence from a 

small number of sources typically does not affect total 

incidence reported to one significant figure. The estimate from 

the proposed rule of maximum chronic non-cancer TOSHI value 

(0.1) is unchanged, driven by naphthalene emissions from 

fugitive sources. The maximum acute non-cancer hazard quotient 

value (9, based on the California EPA reference exposure level 

(REL) for benzene) is also unchanged from the proposed rule. 

Although driven by the same pollutant that drives the MIR, 

benzene, the maximum acute hazard quotient value did not change 

At proposal, we used an incorrect factor (or multiplier) in calculating 

allowable emissions for the source that, at proposal, had an estimated MIR of

400-in-1 million. Since proposal, we have learned that this source is an 

area source and thus is not subject to the Subpart HH MACT standards. As

such, we removed this source from our section 112(f) risk analysis. In any

event, we have determined that even if this area source were to have actual

emissions at the 0.9 Mg/yr level, its risk would be 3-in-1 million. 

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from the proposed rule because the source driving the acute 

value was not identified as an area source and, thus, remained 

in the revised analysis. It is common for the maximum acute 

hazard quotient and cancer MIR not to coincide because the acute 

value is strongly dependent on short-term meteorology and the 

distance to the facility property boundary, whereas the MIR is 

dependent on long-term meteorology and the distance to census 

block receptors. There are 13 cases in the source category (out 

of approximately 1,000 facilities) where the REL is exceeded by 

more than a factor of 2. 

Based on the conservative nature of the acute exposure 

scenario used in the screening assessment for this source 

category, the EPA has judged that, considering all associated 

uncertainties, the potential for effects from acute exposures is 

low. Screening estimates of acute exposures were evaluated for 

each HAP at the point of highest off-site exposure for each 

facility (i.e., not just the census block centroids) assuming 

that a person is present at this location at a time when both 

the peak emission rate and worst-case dispersion conditions 

occur. Although the REL (which indicates the level below which 

adverse effects are not anticipated) is exceeded in this case, 

we believe the potential for acute effects is low for several 

reasons. The acute modeling scenario is worst-case because of 

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the confluence of peak emission rates and worst-case dispersion 

conditions. Also, the generally sparse populations near the 

facilities with the highest estimated 1-hour exposures make it 

less likely that a person would be near the plant to be exposed. 

We also conducted a facility-wide risk assessment. The 

maximum facility-wide risk estimate of 100-in-1 million is 

unchanged from the proposed rule. Also unchanged from proposal 

is the fact that the facility-wide risk is driven by emissions 

from reciprocating internal combustion engines (RICE) and these 

engines are not part of the Oil and Natural Gas Production 

source category. In fact, oil and natural gas production 

operations contribute only about one percent or less to the 

total facility-wide risks. In the last few years, the Agency 

has revised the MACT standards for certain RICE. See 75 FR 9648 

and 51570. Although it is difficult to discern from the 

available data which types of RICE are driving the facility-wide 

risk, it is important to note that the 2005 National Emissions 

Inventory (NEI) data on which we modeled risk did not take into 

account the recent MACT revisions to the RICE rule. Finally, our 

assessment that the potential for significant human health risks 

due to multipathway exposures or adverse environmental effects 

is low has not changed since proposal (see 76 FR 52774). 

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Consistent with the approach established in the Benzene 

NESHAP, the EPA weighed all health risk measures and 

information, including the maximum individual cancer risk, the 

cancer incidence, the number of people exposed to a risk greater 

than 1-in-1-million, the distribution of risks in the exposed 

population, and the uncertainty of our risk calculations in 

determining whether the risk posed by emissions from Oil and 

Natural Gas Production is acceptable. In this case, because the 

MIR is well below 100-in-1-million, and because a number of 

other factors indicate relatively low risk concern, including 

low cancer incidence, low potential for adverse environmental 

effects or human health multi-pathway, and unlikely chronic and 

acute noncancer health impacts, we conclude that the level of 

risk associated with the Oil and Natural Gas Production source 

category MACT standards (including the small glycol dehydrator 

MACT standard issued here) is acceptable.4 

 We reach the same conclusion even if we do not consider the new MACT 

for small glycol dehydrators in our acceptability determination.

Indeed, focusing solely on the standards in the existing MACT, the

level of risk associated with such standards would remain 10-in-1 

million, and thus our acceptability determination does not change.

There is one facility that is a small glycol dehydrator that has an

MIR of 10-in-1 million. After imposition of the MACT for small glycol

dehydrators, however, this unit would have an MIR of 7-in-1 million.

Also, see memorandum titled Supplemental Facility Information Obtained

from Various State/Local Agencies and Additional Analysis, March 20,

2012. 

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In making our proposed ample margin of safety determination 

under CAA section 112(f)(2), we subsequently evaluated the risk 

reductions and costs associated with various emissions control 

options to determine whether we should impose additional 

standards to reduce risks further. As stated above, we made 

certain revisions to the risk assessment in response to comments 

and the resulting MIR for 40 CFR part 63, subpart HH is 10-in-1 

million. We have not identified any emission control options 

that would reduce emissions and risk associated with subpart HH 

sources for glycol dehydration units and storage vessels. Our 

proposed amendment to remove the 0.9 Mg/yr compliance option 

does not affect the risk driver, which is fugitive emissions. As 

a result, we are retaining the 0.9 Mg/yr compliance option in 

the final rule. We have determined that the risks associated 

with the level of emissions allowed by the MACT standards are 

driven by fugitive emissions (i.e., leaks). 

Since a LDAR program is the typical method for reducing 

emissions from fugitive sources, we considered requiring a LDAR 

program to reduce risk for this source category. The NEI dataset 

for this source category contains approximately 2,500 emission 

points that we characterized as fugitive. These emission points 

are located at 639 facilities. The fugitive emissions associated 

with those 639 facilities are 747 tons of HAP. 

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In evaluating the effectiveness of a LDAR program at these 

facilities we looked at two different LDAR programs – one is a 

program equivalent to 40 CFR part 60, subpart VV, and the second 

is a more stringent program equivalent to 40 CFR part 60, 

subpart VVa.5

 A LDAR program equivalent to subpart VV can achieve 

emission reductions of approximately 39 percent with capital and 

annual costs of $237,700 and $79,419 per facility, respectively. 

Therefore, such a program for the 639 facilities would be 

expected to reduce emissions by 249 tons of HAP with total 

capital and annual costs of $152 million and $50.7 million, 

respectively. The cost effectiveness would be approximately 

$204,000 per ton of HAP. 

A LDAR program equivalent to 40 CFR part 60, subpart VVa 

can achieve emission reductions of approximately 43 percent 

overall with capital and annual costs of $241,000 and $82,900 

per facility, respectively. Therefore, an LDAR program for the 

639 facilities would be expected to reduce emissions by 275 tons 

of HAP, with total capital and annual costs of $154 million and 

$53 million, respectively. The cost effectiveness would be 

approximately $193,000 per ton of HAP reduced. These additional 

5

 See memorandum titled Equipment Leak Emission Reduction and Cost Analysis

for Well Pads, Gathering and Boosting Stations, and Transmission and Storage

Facilities Using Emission and Cost Data from the Uniform Standards, April 17, 

2012. 

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control requirements would reduce the MIR for the source 

category from 10-in-1 million to approximately 7-in-1 million. 

As explained in the proposal, in accordance with the 

approach established in the Benzene NESHAP, we weigh all health 

risk measures and information considered in the risk 

acceptability determination, along with the costs and economic 

impacts of emissions controls, technological feasibility, 

uncertainties and other relevant factors, in making our ample 

margin of safety determination and deciding whether standards 

are necessary to reduce risks further. Considering all of this 

information, we conclude that the costs of the options analyzed 

are not reasonable considering the emissions reductions and risk 

reductions potentially achievable with the control measures 

evaluated. Thus, we conclude that the MACT standards in 40 CFR 

part 63, subpart HH (coupled with the new MACT standard for 

small glycol dehydrators) provide an ample margin of safety to 

protect public health and prevent adverse environmental effects. 

Accordingly, we are re-adopting those standards to satisfy the 

requirements of CAA section 112(f). 

3. Changes Made to Standards Proposed Under the Authority of CAA 

Section 112(d)(6) 

As discussed in detail in the preamble for the proposed 

rule (76 FR 52784), we conducted a technology review for glycol 

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dehydration units, storage vessels and equipment leaks under the 

authority of CAA section 112(d)(6). We assessed developments in 

practices, processes and control technologies sources for those 

regulated under the initial NESHAP and determined that it was 

cost-effective to lower the leak definition for valves at 

natural gas processing plants. We did not identify developments 

in practices, processes and control technologies for glycol 

dehydration units and storage vessels. As a result of this 

assessment, we proposed revisions to the equipment leak 

requirements in 40 CFR part 63, subpart HH to lower the leak 

definition for valves to an instrument reading of at least 500 

ppm. No significant changes since proposal were made to the 

equipment leak standards proposed under the authority of section 

112(d)(6) of the CAA.6 

4. Other Changes to the Proposed Rule 

We are revising the emission reduction demonstrated using 

the manufacturers performance test from 98.0 percent to 95.0 

percent. Specifically, if an owner or operator chooses to 

install a combustion control device that is tested under, and 

passes, the prescribed manufacturers performance test the final 

rule states that the control device has demonstrated a 

6

 Memorandum from Brown, Heather, EC/R Inc., to Moore, Bruce, U.S. EPA, titled

Technology Review for the Final Amendments to Standards for the Oil and

Natural Gas Production and Natural Gas Transmission and Storage Source

Categories. 

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destruction efficiency of 95.0 percent. This change is a result 

of comments and data provided on the actual performance of these 

devices in the field. 

In the proposed rule, we proposed that the standards apply 

at all times and removed provisions that provided an exemption 

from the emission standards during SSM. In response to comments 

that the monitoring and reporting provisions related to 

excursions occurring during SSM events that remain in the 

subpart suggest exemption and therefore should be removed, we 

are removing these provisions in the final rule. 

Refer to the Reponses to Comments document, available in 

the docket, for detailed discussion regarding these changes. 

B. What are the significant changes since proposal for the 

Natural Gas Transmission and Storage (subpart HHH) source 

category? 

1. Changes Made to Amendments Proposed Under the Authority of 

CAA Sections 112(d)(2) and (3) 

Under the authority of sections 112(d)(2) and (3) of the 

CAA, we proposed amendments to 40 CFR part 63, subpart HHH by 

adding requirements for previously unregulated units; 

specifically, we proposed standards for small glycol dehydration 

units. 

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In the final amendments for 40 CFR part 63, subpart HHH, we 

have revised the proposed BTEX limits for small glycol 

dehydration units in response to comments that we did not take 

into account variability in the development of the MACT floor. 

We had proposed a unit-specific BTEX emission limit of 6.42x10-5 

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 3.10x10-4 g BTEX/scm-ppmv and for new affected sources is a 

BTEX limit of 5.44x10-5 grams BTEX/scm-ppmv. The process for 

developing these emissions limitations is documented in the 

response to comments document and a technical memorandum both of 

which can be found in the docket. 

2. Changes to Amendments Proposed Under the Authority of CAA 

Section 112(f)(2) 

We proposed to eliminate the 0.9 Mg/yr benzene compliance 

option for large glycol dehydration unit process vents because, 

in the proposed rule, we estimated that the emissions allowed as 

the result of this compliance option resulted in estimated 

cancer risks up to 90-in-1-million. In response to comments, we 

learned that the risk assessment supporting the proposed rule 

erroneously included some sources that have permanently shut 

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down, and several area sources, which are not subject to 40 CFR 

part 63, subpart HHH and, thus, should not have been included in 

the CAA section 112(f) risk assessment. After revising the risk 

assessment to remove these sources and considering the MACT 

standards promulgated here pursuant to CAA section 112(d)(2) and 

(3), the MIR for the Natural Gas Transmission and Storage source 

category based on actual and allowable emissions is 20-in-1 

million, compared to the 90-in-1 million based on allowable 

emissions and 20-in-1 million based on actual emissions 

estimated in the proposed rule. 

As the result of our revised risk analysis, we have 

determined that approximately 1,100 people are estimated to have 

cancer risks at or above 1-in-1 million, compared to 2,500 

people estimated in the proposed rule. Total estimated cancer 

incidence from the source category is 0.001 excess cancer cases 

per year, or one case in every 1,000 years. This estimate is 

unchanged from the proposed rule because the incidence from a 

small number of sources typically does not affect total 

incidence reported to one significant figure. The estimate from 

the proposed rule of maximum chronic non-cancer TOSHI value 

(0.2) is unchanged, driven by benzene emissions from fugitive 

sources. The maximum acute non-cancer hazard quotient value (4, 

based on the benzene REL) changed from the proposed rule; the 

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value in the proposed rule was 5, but was associated with an 

area source that was removed from the risk assessment. There are 

two cases in the source category (out of approximately 300 

facilities) where the REL is exceeded by more than a factor of 

2. 

Based on the conservative nature of the acute exposure 

scenario used in the screening assessment for this source 

category, the EPA has judged that, considering all associated 

uncertainties, the potential for effects from acute exposures is 

low. Screening estimates of acute exposures were evaluated for 

each HAP at the point of highest off-site exposure for each 

facility (i.e., not just the census block centroids) assuming 

that a person is present at this location at a time when both 

the peak emission rate and worst-case dispersion conditions 

occur. Although the REL (which indicates the level below which 

adverse effects are not anticipated) is exceeded in this case, 

we believe the potential for acute effects is low for several 

reasons. The acute modeling scenario is worst-case because of 

the confluence of peak emission rates and worst-case dispersion 

conditions. Also, the generally sparse populations near the 

facilities with the highest estimated 1-hour exposures make it 

less likely that a person would be near the plant to be exposed. 

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We also conducted a facility-wide risk assessment. The 

maximum facility-wide risk estimate of 200-in-1 million is 

unchanged from the proposed rule. Also unchanged from proposal 

is the fact that the facility-wide risk is driven by emissions 

from reciprocating internal combustion engines (RICE) and these 

engines are not part of the Natural Gas Transmission and Storage 

source category. In fact, natural gas transmission and storage 

operations contribute only about one percent or less to the 

total facility-wide risks. In the last few years, the Agency has 

revised the MACT standards for certain RICE. See 75 FR 9648 and 

51570. Although it is difficult to discern from the available 

data which types of RICE are driving the facility-wide risk, it 

is important to note that the 2005 NEI data on which we modeled 

risk did not take into account the recent MACT revisions to the 

RICE rule. Finally, our assessment that the potential for 

significant human health risks due to multipathway exposures or 

adverse environmental effects is low has not changed since 

proposal (see 76 FR 52774). 

Consistent with the approach established in the Benzene 

NESHAP, the EPA weighed all health risk measures and 

information, including the maximum individual cancer risk, the 

cancer incidence, the number of people exposed to a risk greater 

than 1-in-1-million, the distribution of risks in the exposed 

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population and the uncertainty of our risk calculations in 

determining whether the risk posed by emissions from natural gas 

transmission and storage is acceptable. In this case, because 

the MIR is well below 100-in-1-million, and because a number of 

other factors indicate relatively low risk concern, including 

low cancer incidence, low potential for adverse environmental 

effects or human health multi-pathway effects, and unlikely 

chronic and acute noncancer health impacts, we conclude that the 

level of risk associated with the Natural Gas Transmission and 

Storage source category MACT standards (including those MACT 

standards issued here) is acceptable.7 

In making our proposed ample margin of safety determination 

under CAA section 112(f)(2), we subsequently evaluated the risk 

reductions and costs associated with various emissions control 

options to determine whether we should impose additional 

standards to reduce risks further. As stated above, we made 

certain revisions to the risk assessment in response to comments 

and the resulting MIR for 40 CFR part 63, subpart HHH is 20-in-1 

7 We reach the same conclusion even if we do not consider the new MACT 

for small glycol dehydrators in our acceptability determination.

Indeed, focusing solely on the standards in the existing MACT, the

level of risk associated with such standards would remain 20-in-1 

million, and thus our acceptability determination would not change.

The glycol dehydrators analyzed all had risks well below 20-in-1

million. 

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million. We have not identified any emission control options 

that would reduce emissions and risk associated with subpart HHH 

sources for glycol dehydration units. Our proposed amendment to 

remove the 0.9 Mg/yr compliance option does not affect the risk 

driver, which is fugitive emissions. As a result, we are 

retaining the 0.9 Mg/yr compliance option in the final rule. 

We have determined that the risks associated with the level 

of emissions allowed by the MACT standards are driven by 

fugitive emissions (i.e., leaks). Since a LDAR program is the 

typical method for reducing emissions from fugitive sources, we 

evaluated the costs and emissions reductions associated with 

requiring such a program to reduce risk for this source 

category. The NEI dataset for the natural gas transmission and 

storage source category contains approximately 314 emission 

points that we characterized as being fugitive in nature. These 

emission points are located at 212 facilities. The fugitive 

emissions associated with those 212 facilities are 187 tons of 

HAP. 

In evaluating the effectiveness of a LDAR program at these 

facilities we looked at two different LDAR programs – one is a 

program equivalent to 40 CFR part 60, subpart VV, and the second 

is a more stringent program equivalent to 40 CFR part 60, 

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subpart VVa.8 A LDAR program equivalent to subpart VV can achieve 

emission reductions of approximately 51 percent with capital and 

annual costs of $361,800 and $142,600 per facility, 

respectively. Therefore, such a program for 212 facilities would 

be expected to reduce emissions by 95.4 tons of HAP and have 

total capital and annual costs of $76.7 million and $30.2 

million, respectively. The cost effectiveness would be 

approximately $317,000 per ton of HAP. 

A LDAR program equivalent to 40 CFR part 60, subpart VVa 

can achieve emission reductions of approximately 78 percent 

overall with capital and annual costs of $369,500 and $154,300 

per facility, respectively. Therefore, a LDAR program for 212 

facilities would be expected to reduce emissions by 146 tons of 

HAP with total capital and annual costs of $78.3 million and 

$32.7 million, respectively. The cost effectiveness would be 

approximately $224,000 per ton of HAP. These additional control 

requirements would reduce the MIR from the source category to 

approximately 3-in-1 million for the subpart VVa level of 

control and 7-in-1-million for the 40 CFR part 60, subpart VV 

level of control. 

8

 See memorandum titled Equipment Leak Emission Reduction and Cost Analysis

for Well Pads, Gathering and Boosting Stations, and Transmission and Storage

Facilities Using Emission and Cost Data from the Uniform Standards, dated 

April 17, 2012. 

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As explained in the proposal, in accordance with the 

approach established in the Benzene NESHAP, we weigh all health 

risk measures and information considered in the risk 

acceptability determination, along with the costs and economic 

impacts of emissions controls, technological feasibility, 

uncertainties and other relevant factors, in making our ample 

margin of safety determination and deciding whether standards 

are necessary to reduce risks further. Considering all of this 

information, we conclude that the costs of the options analyzed 

are not reasonable considering the emissions reductions and risk 

reductions potentially achievable with the control measures. 

Thus, we conclude that the MACT standards in 40 CFR part 63, 

subpart HHH (coupled with the new MACT standard for small glycol 

dehydrators) provide an ample margin of safety to protect public 

health and prevent adverse environmental effects. Accordingly, 

we are re-adopting those standards to satisfy the requirements 

of CAA section 112(f)(2). 

3. Changes Made to Amendments Proposed Under the Authority of 

CAA Section 112(d)(6) 

As discussed in detail in the preamble for the proposed 

rule (76 FR 52784), we conducted a technology review for glycol 

dehydration units under the authority of CAA section 112(d)(6). 

We did not identify developments in practices, processes and 

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control technologies for large glycol dehydration units. As a 

result of this assessment, we did not propose amendments to 40 

CFR part 63, subpart HHH. We have not made any changes since 

proposal under the authority of CAA section 112(d)(6).9

 Further 

discussion on our technology review analysis can be found in 

section X.C of this preamble, and in the Response to Comments 

document. 

4. Other Changes to the Proposed Rule 

We are revising the emission reduction efficiency 

demonstration using the manufacturer’s performance test from 

98.0 percent to 95.0 percent. Specifically, if an owner or 

operator chooses to install a combustion control device that is 

tested under, and passes, the prescribed manufacturer’s 

performance test, the final rule states that the control device 

has demonstrated a reduction efficiency of 95.0 percent. This 

change is a result of comments and data provided on the actual 

performance of these devices in the field. 

In the proposed rule, we proposed that the standards apply 

at all times and removed provisions that provided an exemption 

from the emission standards during SSM. In response to comments 

that the monitoring and reporting provisions related to 

excursions occurring during SSM events that remain in the 

9

 See footnote 6. 

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subpart suggest exemption and therefore should be removed, we 

are removing these provisions in the final rule. 

VIII. Compliance Related Issues Common to the NSPS and NESHAP 

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

The United States Court of Appeals for the District of 

Columbia Circuit vacated portions of two provisions in the EPA’s 

CAA section 112 regulations governing the emissions of HAP 

during periods of SSM. Sierra Club v. EPA, 551 F.3d 1019 (D.C. 

Cir. 2008), cert. denied, 130 S. Ct. 1735 (U.S. 2010). 

Specifically, the Court vacated the SSM exemption contained in 

40 CFR 63.6(f)(1) and 40 CFR 63.6(h)(1), that are part of a 

regulation, commonly referred to as the “General Provisions 

Rule,” that the EPA promulgated under section 112 of the CAA. 

When incorporated into CAA section 112(d) regulations for 

specific source categories, these two provisions exempt sources 

from the requirement to comply with the otherwise applicable CAA 

section 112(d) emission standard during periods of SSM. 

As proposed in the NESHAP, we have eliminated the SSM 

exemption in this rule. Consistent with Sierra Club v. EPA, the 

EPA has established standards in both rules that apply at all 

times. We have also revised Table 3 (the NESHAP General 

Provisions table) in several respects. For example, we have 

eliminated the incorporation of the NESHAP General Provisions’ 

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requirement that the source develop an SSM plan. We have also 

eliminated or revised certain NESHAP recordkeeping and reporting 

that related to the SSM exemption. The EPA has attempted to 

ensure that we have not included in the regulatory language, for 

the NSPS and NESHAP, any provisions that are inappropriate, 

unnecessary or redundant in the absence of the SSM exemption. 

In establishing the standards in both rules, the EPA has 

taken into account startup and shutdown periods and, for the 

reasons explained in section IX of this preamble for the NSPS 

and in section X of this preamble for the NESHAP, did not 

establish different standards for those periods. Based on the 

information available in the record about actual operations 

during startups and shutdowns, we believe that operations and 

emissions do not differ from normal operations during these 

periods such that it warrants a separate standard. Therefore, we 

have not proposed different standards for these periods. 

Periods of startup, normal operations and shutdown are all 

predictable and routine aspects of a source’s operations. 

However, by contrast, malfunction is defined as a “sudden, 

infrequent, and not reasonably preventable failure of air 

pollution control and monitoring equipment, process equipment, 

or a process to operate in a normal or usual manner * * * ” (40 

CFR 63.2) and as “any sudden, infrequent, and not reasonably 

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preventable failure of air pollution control equipment, process 

equipment, or a process to operate in a normal or usual manner * 

* * ” (40 CFR 60.2). The EPA has determined that CAA sections 

111 and 112 do not require that emissions that occur during 

periods of malfunction be factored into development of CAA 

section 111 or 112 standards. 

CAA section 111 standards – See section III of this 

preamble for a detailed discussion on how the EPA sets or 

revises CAA section 111 NSPS to reflect the degree of emission 

limitation achievable through the application of the BSER. 

CAA section 112 standards - Under CAA section 112, 

emissions standards for new sources must be no less stringent 

than the level “achieved” by the best controlled similar source 

and for existing sources, generally must be no less stringent 

than the average emission limitation “achieved” by the best 

performing 12 percent of sources in the category. Nothing in CAA 

section 112 directs the agency to consider malfunctions in 

determining the level “achieved” by the best performing or best 

controlled sources when setting emission standards. Moreover, 

while the EPA accounts for variability in setting emissions 

standards consistent with the CAA section 112 case law, nothing 

in that case law requires the agency to consider malfunctions as 

part of that analysis. CAA section 112 uses the concept of “best 

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controlled” and “best performing” unit in defining the level of 

stringency that CAA section 112 performance standards must meet. 

Applying the concept of “best controlled” or “best performing” 

to a unit that is malfunctioning presents significant 

difficulties, as malfunctions are sudden and unexpected events. 

Further, accounting for malfunctions in setting NESHAP or 

NSPS standards would be difficult, if not impossible, given the 

myriad different types of malfunctions that can occur across all 

sources in the category and given the difficulties associated 

with predicting or accounting for the frequency, degree and 

duration of various malfunctions that might occur. As such, the 

performance of units that are malfunctioning is not “reasonably” 

foreseeable. See, e.g., Sierra Club v. EPA, 167 F. 3d 658, 662 

(D.C. Cir. 1999) (“[T]he EPA typically has wide latitude in 

determining the extent of data-gathering necessary to solve a 

problem. We generally defer to an agency's decision to proceed 

on the basis of imperfect scientific information, rather than to 

‘invest the resources to conduct the perfect study.’”); see, 

also, Weyerhaeuser Co. v. Costle, 590 F.2d 1011, 1058 (D.C. Cir. 

1978) (“In the nature of things, no general limit, individual 

permit, or even any upset provision can anticipate all upset 

situations. After a certain point, the transgression of 

regulatory limits caused by ‘uncontrollable acts of third 

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parties,’ such as strikes, sabotage, operator intoxication or 

insanity, and a variety of other eventualities, must be a matter 

for the administrative exercise of case-by-case enforcement 

discretion, not for specification in advance by regulation.”). 

In addition, in the NESAHP context, the goal of a best 

controlled or best performing source is to operate in such a way 

as to avoid malfunctions of the source and accounting for 

malfunctions could lead to standards that are significantly less 

stringent than levels that are achieved by a well-performing 

non-malfunctioning source. Similarly, in the NSPS context, 

accounting for malfunctions when setting standards of 

performance under CAA section 111, which reflect the degree of 

emission limitation achievable through “the application of the 

best system of emission reduction” that the EPA determines is 

adequately demonstrated could lead to standards that are 

significantly less stringent than levels that are achieved by a 

well-performing non-malfunctioning source. The EPA’s approach to 

malfunctions is consistent with CAA section 112 and CAA section 

111 and is a reasonable interpretation of the statute. 

Finally, the EPA recognizes that even equipment that is 

properly designed and maintained can sometimes fail and that 

such failure can sometimes cause a violation of the relevant 

emission standard. See, e.g., State Implementation Plans: Policy 

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Regarding Excessive Emissions During Malfunctions, Startup, and 

Shutdown (September 20, 1999); Policy on Excess Emissions During 

Startup, Shutdown, Maintenance, and Malfunctions (February 15, 

1983). The EPA is, therefore, adding to the final NSPS and 

NESHAP an affirmative defense to civil penalties for violations 

of emission standards that are caused by malfunctions. See 40 

CFR 63.761 for sources subject to the Oil and Natural Gas 

Production MACT standards; 40 CFR 63.1271 for sources subject to 

the Natural Gas Transmission and Storage MACT standards 

(defining “affirmative defense” to mean, in the context of an 

enforcement proceeding, a response or defense put forward by a 

defendant, regarding which the defendant has the burden of 

proof, and the merits of which are independently and objectively 

evaluated in a judicial or administrative proceeding). We also 

have added other regulatory provisions to specify the elements 

that are necessary to establish this affirmative defense; a 

source subject to the Oil and Natural Gas Production or Natural 

Gas Transmission and Storage MACT standards must prove by a 

preponderance of the evidence that it has met all of the 

elements set forth in 40 CFR 63.762 and a source subject to the 

Natural Gas Transmission and Storage NSPS must prove by a 

preponderance of the evidence that it has met all of the 

elements set forth in 40 CFR 60.41Da (NSPS). See 40 CFR 22.24. 

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The criteria ensure that the affirmative defense is available 

only where the event that causes a violation of the emission 

standard meets the narrow definition of malfunction in 40 CFR 

60.2 (NSPS) and 40 CFR 63.2 (NESHAP), respectively, (sudden, 

infrequent, not reasonably preventable and not caused by poor 

maintenance and/or careless operation). For example, the final 

NSPS and NESHAP provide that to successfully assert the 

affirmative defense, the source must prove by a preponderance of 

the evidence that the violation “[w]as caused by a sudden, 

infrequent, and unavoidable failure of air pollution control and 

process equipment, or a process to operate in a normal or usual 

manner....” The criteria also are designed to ensure that steps 

are taken to correct the malfunction, to minimize emissions in 

accordance with 40 CFR 63.762 for sources subject to the Oil and 

Natural Gas Production MACT standards, 40 CFR 63.1272 for 

sources subject to the Natural Gas Transmission and Storage MACT 

standards, and 40 CFR 60.5415(h) for the Standards of 

Performance for Crude Oil and Natural Gas Production, 

Transmission and Distribution, and to prevent future 

malfunctions. For example, the final NSPS and NESHAP provide 

that the source must prove by a preponderance of the evidence 

that “[r]epairs were made as expeditiously as possible when a 

violation occurred...” and that “[a]ll possible steps were taken 

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to minimize the impact of the violation on ambient air quality, 

the environment and human health....” In any judicial or 

administrative proceeding, the Administrator may challenge the 

assertion of the affirmative defense and, if the respondent has 

not met its burden of proving all of the requirements in the 

affirmative defense, appropriate penalties may be assessed in 

accordance with section 113 of the CAA (see also 40 CFR part 

22.27). 

The EPA proposed and is now finalizing an affirmative 

defense in the final NSPS and NESHAP in an attempt to balance a 

tension, inherent in many types of air regulations, to ensure 

adequate compliance, while simultaneously recognizing that, 

despite the most diligent of efforts, emission standards may be 

violated under circumstances beyond the control of the source. 

The EPA must establish emission standards that “limit the 

quantity, rate, or concentration of emissions of air pollutants 

on a continuous basis.” 42 U.S.C. §7602(k)(defining “emission 

limitation and emission standard”). See, generally, Sierra Club 

v. EPA, 551 F.3d 1019, 1021 (D.C. Cir. 2008). Thus, the EPA is 

required to ensure that CAA section 112 emissions standards are 

continuous. The affirmative defense for malfunction events meets 

this requirement by ensuring that, even where there is a 

malfunction, the emission standard is still enforceable through 

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injunctive relief. While “continuous” standards, on the one 

hand, are required, there is also case law indicating that, in 

many situations, it is appropriate for the EPA to account for 

the practical realities of technology. For example, in Essex 

Chemical v. Ruckelshaus, 486 F.2d 427, 433 (D.C. Cir. 1973), the 

District of Columbia Circuit acknowledged that, in setting 

standards under CAA section 111, “variant provisions” such as 

provisions allowing for upsets during startup, shutdown and 

equipment malfunction “appear necessary to preserve the 

reasonableness of the standards as a whole and that the record 

does not support the ‘never to be exceeded’ standard currently 

in force.” See, also, Portland Cement Ass’n v. Ruckelshaus, 486 

F.2d 375 (D.C. Cir. 1973). Though intervening case law such as 

Sierra Club v. EPA and the CAA 1977 amendments call into 

question the relevance of these cases today, they support the 

EPA’s view that a system that incorporates some level of 

flexibility is reasonable. The affirmative defense simply 

provides for a defense to civil penalties for violations that 

are proven to be beyond the control of the source. By 

incorporating an affirmative defense, the EPA has formalized its 

approach to upset events. In a Clean Water Act setting, the 

Ninth Circuit required this type of formalized approach when 

regulating “upsets beyond the control of the permit holder.” 

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Marathon Oil Co. v. EPA, 564 F.2d 1253, 1272-73 (9th Cir. 1977); 

see, also, Mont. Sulphur & Chem. Co. v. EPA, 2012 U.S. App. 

LEXIS 1056 (Jan 19, 2012) (rejecting industry argument that 

reliance on the affirmative defense was not adequate). But see 

Weyerhaeuser Co. v. Costle, 590 F.2d at 1057-58 (holding that an 

informal approach is adequate). The affirmative defense 

provisions give the EPA the flexibility to both ensure that its 

emission standards are “continuous,” as required by 42 U.S.C. 

§7602(k), and account for unplanned upsets and, thus, support 

the reasonableness of the standard as a whole. 

Refer to preamble section IX for the NSPS, preamble section 

X for the NESHAP and the Response to Comments document for both 

the NSPS and the NESHAP, available in the docket, for detailed 

discussions regarding these changes. 

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

The final rule includes various notification, recordkeeping 

and reporting requirements that we believe provide a robust 

compliance assurance program, while reducing burden and 

streamlining requirements. The EPA also considered a variety of 

innovative compliance approaches that could maximize compliance 

and transparency, while minimizing burden on the regulated 

community and regulators. More detailed information on public 

comments received and the EPA’s responses are included in 

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sections IX and X of the preamble or in the response to comments 

document. 

1. Notification, Recordkeeping and Reporting Requirements 

For well completions, owners or operators are required to 

submit an email notification no later than 2 days prior to each 

anticipated well completion. The notification must identify the 

owner or operator and provide the American Petroleum Institute 

(API) well number, geographical coordinates of the affected 

wells and the estimated date of commencement of the flowback 

period immediately following hydrofracturing. The owner or 

operator must keep records identifying each well completion 

operation and documenting the portions of the flowback period 

when the gas was recovered, combusted or vented. 

Annually, owners or operators of all affected facilities 

under the NSPS, including gas wells, compressors, pneumatic 

controllers, storage vessels and gas processing plants, must 

report any deviation from the NSPS requirements during the 

reporting period. Each annual report must include a signed 

certification by a senior company official that attests to the 

truth, accuracy and completeness of the report. For affected gas 

wells, the report must also identify each well completion 

conducted during the reporting period and submit detailed 

completion records for each well as part of the annual report. 

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In the final rule, the recordkeeping and reporting 

requirements for well completions also provide a streamlining 

option that owners and operators may choose in lieu of the 

standard annual reporting requirements. The alternative, 

streamlined annual report for gas well affected facilities 

requires submission of a list, with identifying information of 

all affected gas wells completed, electronic or hard copy 

photographs documenting REC in progress for each well for which 

REC was required and the self-certification required in the 

standard annual report. The operator retains a digital image of 

each REC in progress. The image must include a digital date 

stamp and geographic coordinates stamp to help link the 

photograph with the specific well completion operation. The 

owner or operator is not required to submit detailed completion 

records as part of the annual report. 

For centrifugal compressors with wet seal systems, the 

annual report must include identification of each affected 

facility constructed, modified or reconstructed during the 

reporting period. The annual report for reciprocating 

compressors must identify each reciprocating compressor 

constructed, modified or reconstructed during the reporting 

period. The report also must include, for each affected 

compressor, the elapsed time of operation since the most recent 

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rod packing change as of the end of the reporting period. For 

affected pneumatic controllers and storage vessels, the annual 

report must identify each affected facility constructed, 

modified or reconstructed during the reporting period 

Owners or operators who conduct certain performance tests 

on control devices must report results of those tests using the 

Electronic Reporting Tool (ERT). Further discussion of reporting 

of emissions tests is presented in section VIII.D of this 

preamble. 

NESHAP 

The final amendments to 40 CFR part 63, subparts HH and 40 

CFR part 63, subpart HHH revise certain recordkeeping 

requirements. Specifically, facilities using carbon adsorbers as 

a control device are now required to keep records of their 

carbon replacement schedule and records of each carbon 

replacement. We are requiring that owners and operators that use 

a manufacturer’s tested control device keep records of visible 

emissions readings and flowrate calculations and records of 

periods when the pilot flame is absent. The final amendments 

require records of the date of each semi-annual maintenance 

inspection be maintained. Finally, owners and operators are 

required to keep records of the occurrence and duration of each 

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malfunction or operation of the air pollution control equipment 

and monitoring equipment. 

In conjunction with the final MACT standards for small 

glycol dehydration units, owners and operators of such units are 

required to submit an initial notification within 1 year after 

becoming subject to 40 CFR part 63, subpart HH or by [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 year 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 schedule for carbon adsorbers, if applicable; and 

data related to the manufacturer’s performance tests conducted 

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for certain models of control devices, if compliance is being 

achieved using the manufacturer’s performance tests. 

The final amendments to the NESHAP also include additional 

requirements for the contents of periodic reports. Each 

semiannual report must include a signed certification by a 

senior company official that attests to the truth, accuracy and 

completeness of the report. For both 40 CFR part 63, subpart HH 

and 40 CFR part 63, subpart HHH, in the final amendments, 

periodic reports are required to include periodic test results 

and information regarding any carbon replacement events that 

occurred during the reporting period. Owners and operators are 

also required to include in the periodic reports information 

regarding any excursions that occur when the inlet gas flow rate 

deviates from that identified in the manufacturer’s performance 

test, and any excursions caused when visible emissions exceed 

the maximum allowable duration. 

Owners or operators who conduct certain performance tests 

on control devices must report results of those tests using the 

ERT. Further discussion of reporting of emissions tests is 

presented in section VIII.C below. 

2. Innovative Compliance Approaches 

At proposal, given the number and diversity of sources 

potentially affected by the NSPS and/or the NESHAP, we solicited 

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comments on optional compliance tools that could reduce 

compliance burden and enhance transparency. Specifically, we 

asked for suggestions on: (1) registration of wells and advance 

notification of planned completions; (2) use of third party 

verification; and (3) electronic reporting using existing 

mechanisms. We received comments on each of the topics above and 

have presented summaries of those comments and the EPA’s 

responses in the Response to Comments document. The commenters 

were generally opposed to third party verification. However, one 

suggestion was a voluntary random verification program, similar 

to one used in the past for gasoline marketing, where operators 

who participated in this program potentially could receive lower 

priority for enforcement inspections by regulators. Other 

suggested innovative approaches include use of social media, 

including Facebook and Twitter, plus new technologies such as 

quick response codes, to provide timely public notification and 

access to compliance records for individual wells and other 

affected facilities. Other suggestions included use of a 

centralized database for industry and public access to 

compliance information. Further discussion of these approaches 

is provided in the response to comments. While we considered 

these suggestions, we did not adopt them in the final rule, for 

reasons explained further in the Responses to Comments document. 

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C. What are the requirements for submission of performance test 

data to the EPA? 

The EPA must have performance test data to conduct 

effective reviews of CAA sections 111, 112 and 129 standards, as 

well as for many other purposes, including compliance 

determinations, emission factor development and annual emission 

rate determinations. 

As stated in the proposal preamble, the EPA is taking a 

step to increase the ease and efficiency of data submittal and 

data accessibility. Specifically, the EPA is requiring owners 

and operators of oil and natural gas sector facilities to submit 

electronic copies of required performance test reports. 

As mentioned in the proposal preamble, data entry will be 

conducted through an electronic emissions test report structure 

called the ERT. The ERT will generate an electronic report which 

will be submitted to the EPA’s Central Data Exchange (CDX) 

through the Compliance and Emissions Data Reporting Interface 

(CEDRI). A description of the ERT can be found at 

http://www.epa.gov/ttn/chief/ert/index.html and CEDRI can be 

accessed through the CDX web site (www.epa.gov/cdx). 

The requirement to submit performance test data 

electronically to the EPA does not create any additional 

performance testing and would apply only to those performance 

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tests conducted using test methods that are supported by the 

ERT. A list of the pollutants and test methods supported by the 

ERT is available at http://www.epa.gov/ttn/chief/ert/index.html. 

The major advantages of electronic reporting are more fully 

explained in the proposal preamble. 

An important benefit of using the ERT is that the 

performance test data will become available to the public 

through WebFIRE. Having such data publicly available enhances 

transparency and accountability. 

In summary, in addition to supporting regulation 

development, control strategy development and other air 

pollution control activities, having an electronic database 

populated with performance test data will save industry; state, 

local and tribal agencies; and the EPA significant time, money 

and effort while improving the quality of emission inventories 

and, as a result, air quality regulations. 

IX. Summary of Significant NSPS Comments and Responses 

For purposes of this document, the text within the comment 

summaries was provided by the commenter(s) and represents their 

opinion(s), regardless of whether the summary specifically 

indicates that the statement is from a commenter(s) (e.g., “The 

commenter states” or “The commenters assert”). The comment 

summaries do not represent the EPA’s opinion unless the response 

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to the comment specifically agrees with all or a portion of the 

comment. 

A. Major Comments Concerning Applicability 

1. Activities that Constitute a Modification

 Comment: Referring to the definition of “modification” in 

section 111(a)(4) of the CAA, one commenter asserts that a 

modification occurs only if two things happen: (1) There must be 

a “physical change or change in the method of operation,” and 

(2) the change must result in an emissions increase. 

The commenter states that, in the context of the New Source 

Review program, the District of Columbia Circuit Court has 

opined that “Congress's use of the word ‘any’ in defining a 

‘modification’ means that all types of ‘physical changes’ are 

covered” (New York v. EPA, 443 F.3d 880, 890 (D.C. Cir. 2006)) 

and that the District of Columbia Circuit Court has determined 

that “the plain language of the CAA indicates that Congress 

intended to apply NSR to changes that increase actual emissions 

instead of potential or allowable emissions.” New York v. EPA, 

413 F.3d 3, 40 (D.C. Cir. 2005). 

However, according to the commenter, the Supreme Court has 

concluded that the CAA section 111 definition of modification 

does not have to have the same meaning under the NSPS and New 

Source Review (NSR) programs (Environmental Defense v. Duke 

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Energy Corp., 127 S. Ct. 1423, 1434 (2007)), and, thus, the EPA 

has latitude within the context of CAA section 111 to implement 

different rules regarding modifications. 

The commenter believes, in particular, that the EPA’s 

regulatory definition of “modification” under the NSPS program 

provides several categories of activities that alone, are not to 

be considered modifications, including “maintenance, repair, and 

replacement which the Administrator determines to be routine for 

a source category,” and “an increase in production rate that can 

be accomplished without a capital expenditure.” 40 CFR 60.14(e). 

The commenter believes these provisions reflect the fact that 

Congress established the NSPS program for “new” sources. 

According to the commenter, without these exclusions, even the 

most minor activities would convert an existing source into a 

“new source.” The commenter states that the premise behind 

characterizing these activities as not being “changes” is that 

they all contemplate that the plant will continue to be operated 

in a manner consistent with its original design and, thus, is 

not a “new” facility. 

We also received a number of comments objecting to 

consideration of recompletion activities10 as modifications, 

10 At proposal, EPA used the term “recompletion” to describe completions of

previously fractured new gas wells that are refractured at some future date,

and we specified that such actions are considered modifications. In addition,

we used the term “recompletion” to describe completions of existing wells 

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claiming that it is a significant departure from the definition 

of “modification” under the General Provision at 40 CFR 60.14. 

Some commenters argue that well completion expenditures do not 

meet the regulatory definition of “capital expenditure” while 

others argue that they are maintenance activities excluded in 40 

CFR 60.14 others note that we have not traditionally regulated 

temporary “construction” activities.11 

Response: In this final rule, the EPA addresses 

modifications in the context of well completions and has deleted 

the proposed definition of “modification,” though the underlying 

rationale presented in the proposal remains, and we are 

providing alternative regulatory text. Pursuant to this final 

rule and as discussed below, well completions conducted on gas 

wells that are refractured on or after the effective date of 

this rule are considered modifications and subject to the NSPS, 

with the exception of such well completions that, immediately 

upon flowback, use emission control techniques otherwise 

required for new wells and satisfy other requirements for gas 

(i.e., those wells that were constructed before August 23, 2011) that

subsequently are fractured for the first time or that are refractured.

11 We disagree with the commenter. Fracturing and refracturing are not

maintenance activities. On the contrary, these are essential processes that

allow production of gas from shale and other formations, either during the

initial development of a well or in development of new horizons within a

previously fractured well. We also disagree with the characterization that we

are regulating “construction activities.” Rather we are regulating the

emissions resulting from the physical change. 

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well facilities, including notification, recordkeeping and 

reporting requirements. 

As discussed in the proposal, the EPA has chosen to depart 

from the definition of modification in 40 CFR 60.14 with respect 

to regulation of wells that primarily produce natural gas. As 

explained in the proposal and elsewhere in the preamble for this 

rule, the VOC emissions from the flowback following refracturing 

of gas wells are significant, the EPA has identified costeffective controls to reduce VOC emissions during this operating 

phase, and these controls are required for only a relatively 

short time during the well’s operating life. The EPA therefore 

concludes that it is appropriate for treatment of these 

activities to depart from the definition of modification in 40 

CFR 60.14 to ensure that emissions from these activities are 

controlled. 

We do not in this package question the broad 

appropriateness of the NSPS General Provisions at 40 CFR 60.14. 

However, as the General Provisions on modification in 40 CFR 

60.14 themselves recognize, they may not be appropriate in all 

cases. Given the significant, although short-term, increase in 

emissions from flowback caused by refracturing activities when 

such activities are not controlled, and the cost-effective 

nature of the control on such emissions, we have concluded that 

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covering these refracturing activities is appropriate even if it 

requires departing from the General Provisions’ definition of 

modification. 

Specifically, we are providing in the final rule at 40 CFR 

60.5365: 

(h) The following provisions apply to gas well 

facilities that are hydraulically refractured. 

(1) A gas well facility that conducts a well 

completion operation following hydraulic refracturing 

is not an affected facility, provided that the 

requirements of §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. 

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(4) Sources initially constructed after August 

23, 2011, are considered affected sources regardless 

of this provision. 

As a result of this provision, a modification of a well, 

defined as “an onshore well drilled principally for production 

of natural gas,” occurs when a well is refractured on or after 

the effective date of this rule, except when the owner or 

operator of a well controls emissions during the completion 

operation by the use, immediately upon flowback, of emission 

control techniques otherwise required for new wells, as 

discussed more below.12 

Consistency with the Definition of Modification 

This provision is consistent with the statutory definition 

of modification contained in CAA 111(a)(4).13 As discussed in the 

proposal, CAA section 111(a)(4) defines a modification based on 

two requirements: (1) A physical change and (2) an emissions 

12 While we have not done so often, in situations such as this, where there 

is a defined set of physical changes that inevitably lead to an emissions

increase, regulatory certainty and clarity can be provided by, as EPA is

doing, providing a categorical listing of activities that constitute

modifications. See, e.g., 40 CFR 60.751 (addressing landfills; definition of

modification); 40 CFR 60.100a(c) (addressing refineries; stayed pending

reconsideration). 

13 We need not address if New York v. EPA, 443 F.3d 880, 890 (D.C. Cir. 2006)

compels the result here. As we explain, in the body of this preamble our

approach is consistent with CAA section 111(a)(4), and we provide a

reasonable rationale for adopting the approach we take here. 

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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 statutory definition of modification (the 

refracturing results in a physical change which causes flowback 

and an increase in emissions relative to the emissions level 

prior to the refracturing). Accordingly, the NSPS’ treatment of 

modification applies to completions of hydraulically refractured 

gas wells. 

One commenter contends that recompletion does not 

constitute physical change even if there is re-perforation 

because it is an expected part of well operation. However, both 

the CAA and our regulation define modification to mean “physical 

change” without providing any qualification to that term, thus 

indicating that the term “physical change” is very broad to 

include any physical change. The commenter’s interpretation of 

the term “physical change” is without support. 

Emissions Increase 

As a result of these physical changes, a multi-day period 

of flowback of natural gas, hydrocarbon condensate, water and 

sand is necessary to clean up the formation and wellbore prior 

to production of gas for sale. This flowback period is 

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characterized by release of substantial amounts of VOCcontaining natural gas and hydrocarbon condensate that would not 

have occurred absent the refracturing operation, thus meeting 

the second part of the statutory test – an increase in the 

amount of emissions. 

As discussed in the proposal, EPA’s data indicate that 

uncontrolled well completions with hydraulic refracturing 

consistently result in VOC emissions that were not present prior 

to such activities. Data in comments received also confirm that 

these uncontrolled refracturing activities result in significant 

VOC emissions. Our data indicate very low VOC emissions from gas 

wells (2.6 tpy on average) at the wellhead during ongoing 

production prior to such activities. In light of the above, we 

reasonably conclude that such activities result in an increase 

in the amount of VOC emissions and, therefore, constitute a 

modification. 

We reject the comments suggesting that we should adopt the 

prior fracturing activity as the baseline for determining if an 

emission increase has occurred.14 We note that these comments 

14 One commenter relies on a passage from a proposed, but never finalized,

rule preamble to argue that under the NSPS emission increase test prechange

emissions are based on the highest level achievable in the 5 years

immediately preceding a physical change. The passage, however, is not

addressing the NSPS test generally applicable to modifications, but, rather,

is addressing a specific regulatory provision applicable to modifications at

electric utility steam generating units (EUSGU). See 70 FR 61081, 61089

(October 20, 2005). Specifically, the preamble discussion is describing 40

CFR 60.14(h), which states that a change at an EUSGU will not be a 

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appear in part to rely upon a misunderstanding of the EPA’s 

longstanding practice that the relevant baseline for determining 

an emissions increase under the NSPS is not based on the 

potential emissions profile associated with a prior physical 

change or the original construction but rather the emissions 

immediately prior to the physical change. See 57 FR 32314, 32330 

(July 21, 1992) (explaining that, under CAA section 111(a), an 

emission increase is based on current potential emissions rather 

than original design capacity). Accordingly, under historical 

regulations, the proposed regulatory language and the final rule 

that “initial production volumes may have been higher than 

subsequent re-completions or refracturing operations because the 

formation has been depleted by production activities” does not 

mean that there would not be an emissions increase. Ongoing 

emissions during day-to-day production are very small and are 

not a function of well productivity, since these emissions 

originate from leaking valves and other components that do not 

leak more or less as production increases or declines. However, 

flowback emissions following refracturing are orders of 

magnitude greater than the production phase emissions. 

modification if "such change does not increase the maximum hourly emissions

achievable at the unit during the five years prior to the change." See, also,

57 FR 32314, 32330 (July 21, 1992) (adopting 40 CFR 60.14(h) and contrasting

the provision with the pre-existing test). 

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Moreover, adoption of a prior fracturing activity as the 

baseline for comparison here is inappropriate. The purpose of 

the refracturing activity is to increase production from its 

current level. As explained above, at least for the short term, 

VOC emissions from the affected facility increase as a direct 

result of the physical change.15 That is, these emissions would 

not have (and could not have) occurred without the physical 

change. Accordingly, we conclude that reliance on the prior 

fracturing activity as a baseline is inappropriate.16 

De minimis Exception 

We recognize that there are reasons to limit the scope of 

the modification definition so as to not include certain wellcontrolled refracturing activities performed by sources. We 

recognize that the approach that we are taking in this final 

rule differs from the approach that we have taken in the past, 

as it excludes certain emission increases associated with a 

physical change from constituting a modification based on the de 

15 Our data show that the magnitude of ongoing VOC emissions from a producing

gas well is approximately 2.6 tpy or about 14 pounds per day, while the

magnitude of VOC emissions is 23 tons over an average period of 7 days, or

about 6,600 pounds per day, during a completion operation following

refracturing. At this time, we do not have similar data on emissions from oil

wells. 

16 One commenter claims that one cannot determine whether a given well

completion activity qualifies as a modification based on the proposed

definition because it is infeasible to measure the amount of flowback 

emission according to the EPA in proposing a work practice standard. However,

nothing in CAA 111(a)(4) and 40 CFR 60.2 requires quantification of the

amount of emission increase, only that there be an increase as a result of

the physical change. In addition, the commenter’s argument would appear to

apply equally to any time we set a work practice. 

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minimis exception. This exception allows agency flexibility in 

interpreting a statute to prevent “pointless expenditures of 

effort” and has been previously recognized by the United States 

Court of Appeals for the District of Columbia Circuit as an 

appropriate tool when interpreting the CAA section 111(a)(4) 

definition of modification in the context of New Source Review. 

Alabama Power Co. v. Costle, 636 F.2d 323, 360 (D.C. Cir. 1979). 

Since the inception of the NSPS program, certain emission 

controls could be used by a source to avoid having an activity 

constitute a modification provided that the controls prevented 

emissions from increasing. As the District of Columbia Circuit 

explained: 

Under provisions of the regulations that are

not challenged in this litigation, the 

operator of an existing facility can make

any alterations he wishes in the facility

without becoming subject to the NSPS as long

as the level of emissions from the altered 

facility does not increase. Thus the level 

of emissions before alterations take place,

rather than the strict NSPS, effectively 

defines the standard that an altered 

facility must meet. 

Asarco Inc. v. EPA, 578 F.2d 319, 328-29 (D.C. Cir. 1978); see, 

also, 75 FR 54970, 54996 (September 9, 2010) (“However, sources 

always have the option of adding sufficient NOx control to avoid 

an hourly emissions increase and avoid thus triggering the 

modification provision.”). We have allowed such controls to 

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permit the source to avoid being considered “modified” if the 

controls fully negate the emissions increase. 

In this case, we are providing that where a source has in 

place, and, immediately upon flowback, applies emission controls 

equivalent to those required for a new source (as specified in 

40 CFR 60.5375(a)(1) through (4)), the physical change will not 

constitute a modification despite the small remaining emission 

increase. Specifically, well completions conducted by sources 

for refractured wells and with the use, immediately upon 

flowback, of emission controls equivalent to those required for 

new sources will not be considered a modification, due to the de 

minimis increase in emissions of such wells using these 

controls. Several unique factors justify finding that 

application of the de minimis doctrine is appropriate here. 

First, to qualify for the exclusion from the definition of 

modification the source must be using controls equivalent to 

those required were it to trigger the NSPS. As a result, the 

imposition of the NSPS would not yield additional regulatory or 

environmental benefits. See Environmental Defense Fund, Inc. v. 

EPA, 82 F.3d 451, 466 (D.C. Cir. 1996). Second, as a result of 

imposition of controls emissions are very low in magnitude. This 

is both with respect to the size of the increase associated with 

the physical change and the total emissions from the unit after 

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the physical change. Third, the emissions associated with the 

change, and peak emissions post change, are time-limited. A well 

completion is a discrete activity, occurring over a 3-10-day 

period on an occasional basis, which may be as infrequent as 

once every 10 years. This is different from the type of emitting 

activity typically regulated as a modification under NSPS, which 

would involve ongoing emissions indefinitely into the future. 

Further, a source qualifying for this exception must comply with 

the recordkeeping and reporting requirements that are required 

of new sources. Accordingly, the increase in emissions from the 

physical change, and the total amount of additional emissions, 

will be very small. 

We are providing the de minimis exception discussed above 

to provide states with flexibility in application of their 

permitting authority and resources. Commenters pointed out that 

a number of state permitting programs are triggered for sources 

that are subject to an NSPS as a result of a modification. The 

EPA recognizes that states are the most appropriate entities to 

determine whether and how sources should be permitted, and we 

have concern regarding potential impacts of this final rule on 

states’ permitting resources. Accordingly, with this final rule, 

we intend that states retain the discretion to determine whether 

refracturing activities by sources employing control techniques 

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that are required for new wells will require changes in that 

source’s permit status. 

Clarifying Changes 

Although we are not finalizing the proposed definition of 

“modification” for the reasons discussed above, we believe it is 

important to address certain comments regarding the proposed 

definition in order to clarify the agency’s intent as it relates 

to well completions. For example, we included “natural gas” in 

the proposed definition for “modification” in recognition that 

our proposed work practice requirements for well completions use 

natural gas as a surrogate for VOC. We consider natural gas to 

be an appropriate surrogate for VOC for well completion 

activities because our analyses of data on composition of 

natural gas at the wellhead indicated that emissions of natural 

gas during well completions contain various chemical species 

that are VOC. The inclusion of natural gas in the proposed 

definition for modification was not an indication that EPA was 

proposing natural gas as a pollutant to be regulated, as some 

commenters mistakenly thought. 

We also received comment objecting to defining 

“modification” based on increase in the “amount of emission” 

instead of “emission rate” as provided in the General Provisions 

for modifications in 40 CFR 60.14. We had intended but were not 

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clear in our proposed rule that the definition would apply only 

to well completions. In the final rule, we have promulgated the 

provisions discussed above regarding well provisions in lieu of 

the proposed definition for modification to clarify our intent. 

Finally, this provision is intended to address comments 

suggesting confusion associated with our proposed definition of 

“modification” and the separate, proposed provision in 40 CFR 

60.5420 that a workover is considered a modification. The second 

of these provisions is being removed in light of comments that 

there is no common understanding of this term and, as a result, 

it may be interpreted to cover more than the fracturing 

activities the EPA 

intended to cover.17 

In summary, as a result of the comments and considerations 

discussed above, the final rule provides that well completions 

conducted on gas wells that are refractured on or after the 

effective date of this rule are modifications and are subject to 

the NSPS. However, gas wells that undergo completion following 

refracturing, with the use, immediately upon flowback, of 

emission control techniques otherwise required for new wells and 

17 We are not considering “workovers” to be modifications because: (1) They

include truly routine activities; (2) in most instances we would anticipate

only a small emissions increase, if any; and (3) we have no reason to think

that these wells differ in emission profile or control options from nonfractured wells (or fractured wells after flow back), and accordingly we have

not identified a BSER that would apply following any such modification. 

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that satisfy other requirements for gas well facilities, 

including notification, recordkeeping and reporting 

requirements, are not considered modified and, as a result, are 

not affected facilities under the NSPS. This provision is 

consistent with the NSPS program’s history of allowing sources 

to use certain emission controls to avoid having an activity 

constitute a modification. In this situation, we consider it 

appropriate to require notification, recordkeeping and reporting 

requirements in order to ensure that a source is meeting the 

requirements to avail itself of this provision. We believe this 

approach will encourage early use of REC and will result in 

1,000 to 1,500 REC that would not otherwise occur during the REC 

phase-in period ending January 1, 2015, discussed in section 

IX.B of this preamble. 

2. Regulation of Methane and Other Pollutants

 Comment: One commenter believes that under CAA section 111, 

the EPA must regulate each dangerous pollutant emitted by 

sources in the oil and gas source category in more than de 

minimis quantities for which controls are available and asserts 

that the EPA has failed to do so. In particular, the commenter 

states that the EPA must regulate methane, particulate matter 

(PM), hydrogen sulfide and nitrogen oxides (NOX) from oil and gas 

operations. The commenter states that the EPA’s explanation of 

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why it declined to regulate certain pollutants does not discuss 

PM or hydrogen sulfide, address the most important sources of NOX 

or offer a legal justification for its failure to regulate 

methane. The commenter interprets the CAA to mean that the EPA 

must, every 8 years, (1) review its standards (as it has done 

here), (2) determine whether it is “appropriate” to revise them, 

including whether it is appropriate to add additional pollutants 

to the standards, and (3) if so, revise them accordingly. 

Response: In this rule, we are not taking final action with 

respect to regulation of methane. Rather, we intend to continue 

to evaluate the appropriateness of regulating methane with an 

eye toward taking additional steps if appropriate. On November 8, 

2010, EPA finalized reporting requirements for the petroleum and 

natural gas industry under 40 CFR Part 98, the regulatory 

framework for the Greenhouse Gas Reporting Program (GHGRP). 

Beginning in September 2012, this program requires annual 

reporting of greenhouse gases (GHG) from large emissions sources 

and fuel suppliers in the United States. Petroleum and natural 

gas facilities will report annual methane and carbon dioxide 

(CO2) emissions from equipment leaks and venting, and emissions 

of CO2, methane and nitrous oxide from flaring, onshore 

production stationary and portable combustion emissions, and 

combustion emissions from stationary equipment involved in 

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natural gas distribution. The EPA estimates that the rule will 

cover 85 percent of the total GHG emissions from the United 

States petroleum and natural gas industry with approximately 

2,800 facilities reporting. The data submitted under the GHGRP 

will provide important information on the location and magnitude 

of GHG emissions from petroleum and natural gas systems and will 

allow petroleum and natural gas facilities to track their own 

emissions, compare them to similar facilities and aid in 

identifying cost-effective opportunities to reduce emissions in 

the future. 

As noted in the proposal, the control measures that the EPA 

is requiring for VOC result in substantial methane reductions as 

a co-benefit. Over time, collection of data through the GHGRP 

and other sources will help EPA evaluate whether it is 

appropriate to directly regulate methane from the oil and gas 

sources covered by this rule. The EPA will be in a better 

position to characterize (1) the extent of methane emissions 

from these sources that will remain after imposition of controls 

required by this rule; and (2) whether additional measures are 

available and appropriate for addressing such emissions. 

With regard to other pollutants, including PM, H2S and NOX, 

many of the sources of PM and NOX within the Crude Oil and 

Natural Gas Production source category are within the scope of 

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units covered by other NSPS and will be evaluated in the context 

of subsequent revisions of those rules, if appropriate. This 

approach is consistent with what the agency articulated when we 

promulgated the original oil and gas rules. See 49 FR 2637. For 

example, NSPS covering stationary reciprocating internal 

combustion engines (40 CFR part 60, subparts IIII and JJJJ) and 

combustion turbines (40 CFR part 60, subpart KKKK) regulate 

emissions of PM and NOX from sources found in this category. 

These engines and turbines are found in a variety of locations 

in this category including gathering and boosting stations, 

natural gas processing plants and natural gas transmission and 

storage facilities. In addition, some mobile source regulations 

(40 CFR 1039) cover nonroad engines such as those used on 

drilling rigs, electrical generators and hydraulic fracturing 

pumps. As we discussed at proposal (see 76 FR 52756) most, if 

not all, of the process heaters and boilers used in this 

category fall below applicability thresholds for EPA’s boiler 

rules (40 CFR part 60, subparts Db and Dc). Although these 

smaller heaters and boilers are generally within the scope of 

this category, we received no quantitative data in the public 

comments on NOX or PM emissions from these units. Given the broad 

coverage of the PM and NOX sources in this category by other NSPS 

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we did not depart from the approach adopted in 1984 of 

considering these pollutants in development of other standards. 

Although the NSPS does not provide direct regulation of 

H2S, the VOC control requirements in the final rule achieve 

reductions of H2S a co-benefit in cases where H2S is otherwise 

emitted in the oil and natural gas production segment. While 

amine treatment and sulfur recovery are routinely employed both 

upstream and at natural gas processing plants to remove H2S from 

the natural gas stream, we believe that it would not be 

reasonable or cost-effective to require amine units and sulfur 

recovery for every emission point in the oil and natural gas 

production segment. We received no public comments suggesting 

other control technologies that could be applied to control H2S 

in the field. Such emissions occur in the field as fugitive 

emissions at the wellhead and vented emissions from well 

completions, storage vessels, pneumatic controllers and 

compressors. However, as mentioned above, the VOC control 

measures provided in the final rule for well completions, 

storage vessels, pneumatic controllers and compressors greatly 

reduce any H2S emissions along with the VOC emissions 

controlled. 

3. Expanded Scope of the Source Category 

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Comment: One commenter states that, in the preamble, the 

EPA makes reference to its proposal to significantly expand the 

scope of oil and gas operations that would be covered by the new 

NSPS, and states that ”[t]o the extent that there are oil and 

gas operations not covered by the currently listed Oil and 

Natural Gas source category, pursuant to CAA section 111(b) we 

hereby modify the category list to include all operations in the 

oil and natural gas sector” (citing 76 FR 52745, August 23, 

2011). The commenter is not aware of any authority pursuant to 

which the EPA may affect a significant expansion of the category 

list merely through the language of the preamble in an NSPS 

rulemaking. The commenter states that, in a related context, the 

CAA requires that the EPA engage in consultation with state 

governors and air pollution control agencies, suggesting that 

more than a preamble reference is needed in order to expand the 

category list and impose NSPS requirements on the new and unique 

affected sources addressed in this rule. See 42 U.S.C. 

§7411(f)(3). The commenter asserts that the sources the EPA 

seeks to regulate are different types of stationary sources than 

gas processing plant, and contends that oil and gas production 

wells are stationary sources, but are, clearly, not processing 

plants. 

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Response: Because EPA has concluded that the currently 

listed Oil and Natural Gas source category covers at least those 

operations in this industry for which we are finalizing 

standards, we need not address what steps the agency must take 

if expanding a source category.18 As we explained in the preamble 

to the proposed rule, when the EPA initially listed this source 

category, it did so in a document where it described its 

listings as broad. 76 FR at 52745.19 Contrary to commenters 

assertions, the EPA has viewed this source category listing very 

broadly. Specifically, when promulgating the first sets of 

standards of performance for this source category, we stated 

that the source category “encompass[es] the operations of 

exploring for crude oil and natural gas products, drilling for 

these products, removing them from beneath the earth’s surface, 

and processing these products from oil and gas fields for 

distribution to petroleum refineries and gas pipelines.” 49 FR 

at 2637 (emphasis added). That preamble linked the endangerment 

finding under CAA section 111(a) to the industry as a whole: 

“the crude oil and natural gas production industry causes or 

contributes significantly to air pollution that may reasonably 

18 For the same reason, we need not address the comment claiming that CAA

section 111(f)(3) requires that the EPA consult with state governors before

amending CAA section 111(b) listing.

19 While not required to do so, we have included the Background Information

Document for the listing rule in the docket for this rule. We note that those

documents shed no additional light on the scope of the listing beyond our

interpretation of the listing preamble described in the proposed rule. 

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be anticipated to endanger public health or welfare” (Emphasis 

added). 49 FR 2636. The statements above affirm our conclusion 

that the currently listed Oil and Natural Gas source category 

covers all operations for which we are setting standards. That 

the original NSPS’s only set standards for a limited set of 

sources within the category cannot be taken to imply that other 

units were not within the scope of this original listing. See, 

e.g., Nat’l Lime Ass’n v. EPA, 627 F.2d at 426 n. 27 (noting 

that the EPA set standards for only certain kiln types within 

the source category). Indeed, the preamble to the 1984 proposed 

NSPS rule directly addresses regulation of wells, concluding 

that the agency was not setting standards at that time; not 

because they were outside the scope of the source category, but 

because the agency was unable at that time to identify “[b]est 

demonstrated control technology.” 49 FR at 2637. As all of the 

units that we are regulating fall within the scope of the 

original listing, we need not address what steps would be 

necessary were we to expand the scope of the listing. 

B. Major Comments Concerning Well Completions 

1. Applicability and Exemptions 

a. Well Exemptions

 Comment: One commenter suggests adding “appraisal wells” as 

a third subcategory of well to be exempt from the REC 

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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 

cost to fracture, complete and produce the well, including 

installing a flow line, will be incurred. If the well logs 

indicate the well is not economically productive, then no 

fracturing occurs and the NSPS does not apply. The EPA, 

therefore, believes it is reasonable to require appraisal wells 

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that are hydraulically fractured to comply with Subcategory 3 

rule requirements. 

b. Threshold for Low Pressure (Low Volume) Gas Wells and Wells 

with Low or No VOC Emissions

 Comment: One commenter expresses support for the REC 

requirements and urges the EPA to limit the number of well 

completions exempted from the requirements as much as possible. 

Several commenters contend that not all well completions can be 

conducted successfully under a requirement to flow back to the 

flow line, since the imposition of the flow line backpressure 

may reduce the flowback gas velocity sufficiently so that it is 

not energetic enough to clean up the well of liquid and sand. 

One commenter recommends that any well whose reservoir pressure 

(measured at the wellhead immediately after perforation) is less 

than 4 times (in absolute units) the line pressure measured at 

the flow meter, would be exempt from any requirement to flow to 

sales during the flowback period. According to the commenter, 

variability in reservoir and line pressures across the United 

States makes setting a specific pressure threshold difficult. 

Response: The EPA has established three subcategories of 

wells in response to public comments, as described above. One of 

those categories comprises non-wildcat and non-delineation low 

pressure gas wells. Low pressure gas wells are defined as wells 

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with reservoir pressure and vertical well depth such that 0.445 

times static reservoir pressure (in pounds per square inch 

absolute (psia)) minus 0.038 times the vertical well depth (in 

feet) minus 67.578 psia is less than the flow line pressure at 

the sales meter. Thus, wells above this pressure differential 

must implement REC, while wells below this pressure differential 

are required to route emissions to a completion combustion 

device. 

The EPA solicited comment in the proposed rule on 

situations where REC may be infeasible and criteria and 

thresholds for distinguishing well completion operations in 

those situations from others where REC is feasible. As noted 

above, several commenters highlighted the technical issues that 

prevent an operator from implementing an REC on a low pressure 

gas well, which is the inability to attain a gas velocity 

sufficient to clean up the well when flowing against the flow 

line backpressure. Based on this information, the EPA agrees 

that a pressure differential threshold is reasonable and 

addresses the technical limitations of low pressure gas wells to 

produce to the flow line during completion. 

As noted above, a commenter recommended specific approaches 

to developing a pressure threshold, including specifying that 

any well whose reservoir pressure is less than 4 times (in 

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absolute units) the line pressure measured at the flow meter 

would be exempt from any requirement to flow to the flow line 

during the flowback period. This recommendation is based on a 

flowing bottom hole to reservoir pressure ratio of 1:2 and a 

line pressure to flowing bottom hole pressure of 1:2. The EPA 

concurs with the commenter that flowing bottom hole pressure can 

be represented as half of the reservoir pressure for this rule. 

The EPA disagrees with the commenter that line pressure can be 

represented as half of the flowing bottom hole pressure for this 

rule since this pressure relationship can be more accurately 

determined using the Turner equation for liquids unloading from 

a well paired with models relating fluid velocity to pressure 

drop. Therefore, the EPA has modeled a worst-case pressure drop 

factor between the line pressure and flowing bottom hole 

pressure and has established a pressure threshold using this 

factor and the 1:2 factor for flowing bottom hole pressure to 

reservoir pressure. The result of this modeling is the equation 

discussed above in the definition of low pressure gas wells. 

As discussed in the proposal preamble, potential control 

options are REC with combustion or a completion combustion 

device alone. Because REC may not always be technically feasible 

for wells that fall below the pressure threshold, the EPA has 

determined that the BSER for reducing VOC emissions for this 

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subcategory of wells is a completion combustion control device. 

However, the EPA encourages the use of REC with combustion 

should that be a viable option for any well within this 

subcategory. Therefore, in the final rule, for non-wildcat and 

non-delineation wells with a pressure drop below the 

differential described above, the EPA requires the use of either 

a completion combustion device or REC with combustion to control 

gas not suitable for entering the flow line. 

Comment: Several commenters address parameters for defining 

which well completions would be subject to REC requirements. 

Commenters request that the EPA exempt wells with low VOC 

concentrations from the REC requirements and not issue the 

proposed standards before reconsidering the emissions estimates. 

One commenter suggests that the EPA exempt hydraulically 

fractured natural gas horizontal wells with de minimis VOC 

concentrations because the cost per ton of VOC reductions is 

extremely high for these wells and the emissions from the 

combustion of the produced gas could worsen ozone formation in 

the area. Commenters also provide, as examples, some wells with 

low or no VOC as support for exempting wells with a low VOC 

content or for exempting certain classes of wells such as coal 

bed methane. Several commenters contend that coal bed methane 

wells have low VOC, while several other commenters contend that 

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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 costeffective to regulate, as the commenters recommend. For example, 

several commenters contend that CBM wells have low or no 

emissions. In response to comments received, the EPA assessed 

the VOC content of CBM wells, including a review of the gas 

composition data presented in the gas composition memo20 

available in the docket and in an article21 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 

20 Memorandum from Brown, Heather, EC/R Inc., to Moore, Bruce, EPA/OAQPS/SPPD,

Composition of Natural Gas for use in the Oil and Natural Gas Sector

Rulemaking, July 28, 2011. Docket ID No. EPA-HQ-OAR-2010-0505-0084.

21 Rice, Dudley, Composition and Origins of Coalbed Gas, U.S. Geological

Survey, Denver, Colorado. 

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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 

concentration threshold described above can be determined, to 

ensure compliance with the rule, an operator would have to 

determine with certainty before production, whether a particular 

well was going to be above or below the threshold in order to 

mobilize the necessary capture equipment and secure a flow line, 

etc. This would require the operator to determine the reservoir 

composition, e.g., the gas composition prior to separation, in 

advance of the well completion (i.e., the determination of 

whether the well would be subject to the NSPS would have to be 

performed before the information on which to base such a 

determination would be available). Although nearby existing 

wells could potentially provide some indication of the general 

VOC content of the gas from the future well in question, there 

would be no assurance of certainty. In addition, the operator 

would need to certify that the reservoir sample is going to stay 

consistent and representative of the gas stream throughout the 

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full completion process through multiple gas composition 

analyses. 

Taking into account the variability in VOC concentrations 

across reservoir types, the EPA’s cost analysis illustrates that 

these requirements are cost-effective, especially when taking 

into account the gas savings. Compliance with a VOC 

concentration threshold-based rule for well completions could 

actually increase the burden to the operator by requiring 

numerous compositional analyses to demonstrate compliance with 

the rule. 

c. Definition of Gas Well

 Comment: Several commenters mentioned that the proposed 

definition of “gas well” was unclear due to the term “principal 

production” used in describing what the well produces. One 

commenter requests that the definition of gas well be modified 

to be each respective state’s definition of gas well. The 

commenter states that, by doing this, the EPA would eliminate 

any confusion associated with having to apply different criteria 

(NSPS versus state regulations) for how to define a well-type in 

assessing the applicability of the rule. 

Response: In response to comments requesting further 

clarity in the definition, the EPA has revised the definition. 

The proposed definition was “Gas well means an onshore well, the 

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principal production of which at the mouth of the well is gas.” 

In the final rule, in response to the comments we received, the 

EPA has revised the definition to exclude the phrase “at the 

mouth of the well is gas.” Based on this revision, the 

definition for the final rule is “Gas well or natural gas well 

means an onshore well drilled principally for production of 

natural gas.” 

EPA’s intent in setting standards for completion of 

hydraulically fractured gas wells is to require reduced 

emissions completions for wells where infrastructure is 

generally present to get recovered natural gas to market. Our 

understanding is that owners and operators plan their operations 

to extract a target product and evaluate whether the appropriate 

infrastructure is available to ensure their product has a viable 

path to market before completing a well. We expect that the 

final rule will result in control of hydraulically fractured gas 

wells drilled in the four formation types generally accepted as 

gas-producing formations: (1) High-permeability gas, (2) shale 

gas, (3) other tight reservoir rock or (4) coal seam. We believe 

that the wording changes made to the definition of “gas well” 

clarify the intent so that implementing agencies and industry 

will not be burdened with complex applicability determinations. 

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With respect to using State gas well definitions, basing 

applicability on different definitions from State to State could 

introduce inconsistencies that are counter to the goal of 

nationwide regulation. We believe the NSPS, being a national 

rule, should contain a single definition applicable nationwide. 

However, states may choose to use a definition more expansive 

than our definition for their programs. 

Comment: One commenter states that, based on the EPA’s 

discussion in Section 4 of the Technical Support Document (TSD), 

it appears the EPA’s intent is to require reduced emissions 

completions only for natural gas wells. The commenter supports 

that the EPA applied reduced emissions completions only to 

natural gas wellhead facilities and excluded oil wellhead 

facilities and other types of gas wells which have little or no 

VOC emissions. The commenter states that, as shown on page 4-13 

on Table 4.4, Nationwide Baseline Emissions from Uncontrolled 

Oil and Gas Well Completions and Recompletions, of the TSD, 

there are only 134 tpy of VOC emissions from oil well 

completions and recompletions for the entire United States, 

which is not worth regulating. 

One commenter recommends the following revision: “Gas well 

means a well, the principal production of which at the mouth of 

the well is [add: hydrocarbon gas, not CO2]. . .Well means an oil 

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or gas well, a hole drilled for the purpose of producing oil or 

gas, or a well into which fluids are injected.” One commenter 

proposes the following revision: “Gas well means a well, [DELETE 

the principal production of which at the mouth of the well is 

gas] completed for production of natural gas from one or more 

gas zones or reservoirs. Such wells contain no completions for 

the production of crude oil.” The commenter also proposes the 

following revision: “Gas well means a well [STRIKETHROUGH: the 

principal production of which at the mouth of the well is gas.] 

[ADD TEXT: completed for production of natural gas from one or 

more gas zones or reservoirs. Such wells contain no completions 

for the production of crude oil.]” 

Response: Although some wells drilled in crude oil 

formations may produce associated gas along with the oil, 

without a gas infrastructure present, the EPA does not have 

sufficient data on VOC emissions during completion of 

hydraulically fractured oil wells to set standards for these 

operations at this time.22 As a result, the final rule will not 

affect drilling of oil wells. 

d. Availability of Infrastructure to Convey Gas to Market 

22 In the proposed rule, we briefly assessed well completions of hydraulically

fractured oil wells and did not believe that either REC or a completion

combustion device is cost effective for reducing VOC emissions from such

operations. We note, however, that this brief assessment of oil wells in the

proposed rule was based on limited information at the time and that more

information is needed for us to fully evaluate the VOC emissions and control

options for these operations. 

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Comment: Various commenters have asserted that, in some 

cases, REC cannot be performed on some wells because there is no 

gathering line available to convey gas produced during the 

completion flowback period. 

Response: As explained above, it is our understanding that 

owners and operators plan their operations to extract a target 

product and evaluate whether the appropriate infrastructure 

access is available to ensure their product has a viable path to 

market before completing a well. However, in the standards for 

gas well affected facilities, the provisions of 40 CFR 

60.5375(a)(1) through (4) apply to all fractured gas wells that 

are not exploratory wells, delineation wells or low pressure 

wells. These standards require that the well completion flowback 

be conducted using a combination of collection (i.e., REC), 

combustion and venting, depending on the characteristics of the 

flowback material and feasibility of routing the gas to a 

collection system to be conveyed to market. Section 

60.5375(a)(3) provides: 

“You must capture and direct flowback emissions that cannot be 

directed to the flow line to a completion combustion device . . 

.” 

We believe that owners and operators of gas wells subject 

to 40 CFR 60.5375(a) that require REC for a portion of the 

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flowback period will exercise due diligence in coordinating the 

completion event with availability of a flow line to convey 

captured gas to market. However, there may be cases in which, 

for some reason, the well is completed and flowback occurs 

without suitable flow line available. In those isolated cases, 

we believe 40 CFR 60.5375(a)(3) provides for gas not being 

collected and instead combusted or vented pursuant to that 

section. 

e. Fracturing of Wells Using Nitrogen and Carbon Dioxide 

Comment: One commenter suggested that wells that are 

fractured using nitrogen or CO2 should be exempt from the NSPS 

but did not provide supporting rationale. Other commenters 

expressed concern that inert gases such as nitrogen are not 

flammable, making compliance with the combustion provisions of 

the NSPS impossible. 

Response: We believe that the standards for well 

completions adequately address the concerns expressed by 

operators using nitrogen and/or CO2 for fracturing. We provided 

in the proposed rule, and further clarified in the final rule, 

that these standards require that the well completion flowback 

be conducted using a combination of collection (i.e., REC), 

combustion and venting, depending on the characteristics 

(including flammability) of the flowback material and 

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feasibility of routing the gas to a collection system to be 

conveyed to market. Both the proposed and final rules express 

our intent to require REC only where there is salable quality 

gas to the gather line. See 76 FR 52800 and 40 CFR 60.5375(a)(2) 

of the final rule. 

Section 60.5375(a)(3) in the final rule provides: “you must 

capture and direct flowback emissions that cannot be directed to 

the flow line to a completion combustion device, except in 

conditions that may result in a fire hazard or explosion, or 

where high heat emissions from a completion combustion device 

may negatively impact tundra, permafrost or waterways. 

Completion combustion devices must be equipped with a reliable 

continuous ignition source over the duration of flowback.” 

Under this provision, operators who employ energized 

fracturing using inert gases and cannot route the flowback gas 

to a collection system because of poor gas quality must direct 

the flowback to a completion combustion device with a continuous 

ignition source. Although part of the flowback gases directed to 

the combustion device would not be flammable, the ignition 

source will ignite the flammable portion of the flowback, 

including VOC. Therefore, the presence of inert gases such as 

nitrogen and CO2 in the flowback gas has no bearing on the VOC 

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reduction we expect to achieve through the NSPS or on compliance 

with provisions of the final rule. 

2. Rule Should Not Prescribe Equipment

 Comment: Several commenters suggest revising 40 CFR 

60.5375(a)(2) equipment requirements to be less prescriptive, 

especially in cases where use of specified or all listed 

equipment may not be necessary, and to provide flexibility to 

include newly developing technology. Other commenters assert 

that language in 40 CFR 60.5375(a)(1) and (2) stating that 

source owners or operators should “minimize the emissions 

associated with venting of hydrocarbon fluids and gas” and that 

“[a]ll salable gas must be routed to the gas gathering line as 

soon as practicable” is vague and recommended a requirement that 

facility owners follow a Best Management Practice (BMP) plan 

that the EPA could develop, informed by the Natural Gas STAR 

program. 

Response: The EPA agrees that prescribing specific 

equipment to accomplish a reduced emissions completion is not 

necessary and has revised the rule language to not prescribe 

specific equipment. The operational standards provided in the 

NSPS allow the operator flexibility to perform the REC using 

equipment and practices best determined by the operator. As a 

result, we believe that a BMP plan developed by the EPA would 

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not provide a higher degree of emissions control and could 

hinder innovation. 

3. Availability of Equipment and Trained Personnel 

Comment: Commenters state that the supply of REC equipment 

and personnel is insufficient to meet the requirements of the 

proposed rule, applied nationally. According to commenters, 

proper surface equipment, collection infrastructure and 

qualified personnel are not readily available; they assert that 

this equipment is fairly specialized, the shops licensed to make 

it are limited and some of the components require a long lead 

time. For these reasons, commenters indicate that compliance by 

the issuance date of the rule would be unrealistic and that the 

EPA should provide a longer compliance period. 

Response: Based on information submitted by commenters, we 

have reason to believe that, currently, there is already 

significant demand for REC equipment. For example, Colorado, 

Wyoming, the City of Fort Worth, Texas, and the City of 

Southlake, Texas, require REC under certain conditions. 

Additionally, public comments, reports to the EPA’s Natural Gas 

STAR Program and press statements from companies indicate that 

some producers implement REC voluntarily, based upon economic 

and environmental objectives. If REC were to be immediately 

required of all well completions, NSPS would place significant 

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additional demands on REC equipment supply and experienced 

personnel. 

As the near-term supply of REC equipment and trained 

personnel will be insufficient to meet the new national demand 

for equipment and labor, immediate compliance with the REC 

requirements could be impossible, potentially causing producers 

to delay well completions until appropriate equipment and labor 

are available. Resulting delays in well completions while 

awaiting equipment availability could cause a decrease in the 

nationwide natural gas supply and would drive up the cost of 

completions doing REC. It is not the EPA’s intent to set in 

motion a series of events through this rule that has the 

potential to affect 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 study23 on REC in collaboration with service 

providers. Based on this experience, the EPA has gained 

extensive information on this technology. Despite these efforts, 

23 Available at: 

http://www.epa.gov/gasstar/documents/reduced_emissions_completions.pdf. 

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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 

perform 20,000 REC per year. About 1,600 units performing 20,000 

REC/year implies a REC productivity rate of about 12.5 

REC/year/unit, or roughly each unit performing one REC per 

month, on average. 

The NSPS proposal estimated 9,300 REC performed for new 

natural gas well completions and 12,200 REC performed for 

existing natural gas well completions following refracturing 

would be required, in addition to those already required by 

state regulations. In the analysis supporting the final rule, 

the EPA revised estimates show 11,403 hydraulically fractured 

and 1,417 hydraulically refractured natural gas well completions 

will be performed in a representative year, which includes 

completions in states which currently have REC requirements. The 

revised estimate also reflects a change in the refracture 

frequency of existing wells from 10 percent to 1 percent based 

on information provided by commenters. Of the total 

hydraulically fractured well completions, the EPA estimates that 

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about 11,300 REC will be required nationally on the basis of the 

final rule’s provisions for wildcat (exploratory) and 

delineation wells, flowback gas pressure and natural gas well 

completions conducted on existing gas wells that are 

subsequently fractured or refractured. This estimate excludes 

REC required by state regulations. 

Assuming a REC unit performs 12.5 REC/year, as is asserted 

by the commenter, about 900 units would be required. This 

implies a current shortfall of about 600 units, based upon the 

numbers and assumptions provided by the commenter. The commenter 

states that industry can deliver about 50 units per quarter, 

after a 1-year build-up period. Given that the EPA does not have 

an alternative estimate of the number of REC units industry can 

produce per year, we adopt the estimate of 50 units per quarter 

for this analysis, although the EPA disagrees with the 

assumption that a 1-year build-up period is required. Using the 

commenter’s assumptions, it would take about 4.25 years to meet 

demand. This scenario is depicted in Scenario A in Table 6 

below, assuming compliance is initiated at the beginning of the 

second quarter, 2012, and the industry begins delivering 50 

units per quarter roughly 1 year after the compliance date. 

Surveys conducted by one commenter indicate that nine 

companies expect to perform more REC than the current stock is 

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capable of. Given this growing demand, it is reasonable to 

assume industry can deliver units during the buildup period of 

the first year of implementation, which would reduce the time 

required to meet full demand another year to a total of about 

3.25 years (Scenario B). 

The EPA also assessed whether the productivity of equipment 

in use could be higher than the 12.5 REC/year/unit derived from 

the comment, and the potential impact of such increase on the 

equipment supply. The EPA estimated that flowback periods will 

typically be 3 to 10 days with 7 being a reasonable average. 

Therefore, because it is likely that a REC unit could be moved 

to another well site and be in operation in less than 20 to 27 

days, it is reasonable to conclude that each REC unit can 

perform more than 12.5 REC/year. 

If the utilization rate of REC units is increased gradually 

from performing 12.5 REC/year/unit to 14 to 18 REC/year/unit, 

the time required to build the supply of REC units decreases 

(Scenarios C-G). As Table 6 shows, each 1 REC/year/unit increase 

reduces the buildup time by about 1 quarter. As is shown in 

Scenarios C and G, increasing the utilization rate of REC to 14 

to 18 REC/unit/year with industry supplying new units beginning 

with the compliance date would provide between 1.75 and 2.75 

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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 

11,30 11,30 11,30 11,30 11,30 11,30 11,30

RECs Required 1 1 1 1 1 1 1 

RECs/year/uni

t 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 

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 

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Because of uncertainties in the supply of equipment and 

labor over the near-term, and based on our analysis described 

above, the EPA concludes that REC may not always be available 

through 2014. Therefore, during this period, the BSER for well 

completions is to combust completion emissions. REC with 

combustion as an alternative to combustion is permitted by the 

rule so that facilities that are able to obtain REC equipment 

may still capture completion emissions using a REC. After 

January 1, 2015, capturing completion emissions using a REC will 

be considered BSER. This period will permit the companies 

producing REC units to increase production to levels sufficient 

to meet new demand. In addition, because more REC will be 

performed as a result of this rule, the EPA believes that 

producers will take advantage of scale economies and use REC 

units at a higher rate of productivity than the rate implied by 

comments received. 

The EPA believes that the NSPS, as finalized, will minimize 

the risks of producers slowing well completion-related 

activities to obtain appropriate equipment and labor. While 

there would be NOx formation as a result from the additional 

combustion of completion emissions during the phase-in period, 

VOC emissions reductions would be maintained because completion 

emissions will be either combusted or captured. The EPA 

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maintains that the benefit of the VOC reduction during the 

phase-in period far outweighs the secondary impact of NOx 

formation during pit flaring. The phase-in period would also 

minimize the possibility that the cost of REC equipment and 

labor increases over the near-term, enabling producers to better 

plan efficient use of existing and new capital and labor, and 

providing additional time for innovation in REC technologies 

and/or practices. We believe this period provides ample time for 

this technology to be built and available for use. 

At the same time, for wells undergoing recompletions during 

the period prior to January 1, 2015, the terms of 40 CFR 60.5365 

(h), which specify that “[a] gas well facility that conducts a 

well completion operation following hydraulic refracturing is 

not an affected facility, provided that the requirements of 

section 60.5375 are met,” may provide an additional incentive 

for producers to use REC units prior to January 1, 2015, if they 

can obtain appropriate equipment and labor. Also, considering 

the requirement in some states that any source subject to a 

federal NSPS must get a state minor source air permit, we 

anticipate that the desire to avoid even short term delays 

caused by state permitting, as well as the associated costs, 

will serve as an incentive for the use of REC during well 

completion operation following hydraulic refracturing, including 

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operations prior to January 1, 2015. Furthermore, as January 1, 

2015, approaches it is highly likely that providers of REC 

equipment and related services will be increasing availability 

of such equipment and services in ways that benefit supply and 

price. For these reasons, the EPA anticipates that during the 

period between promulgation and January 1, 2015, between 1,000 

and 1,500 wells will be recompleted with REC units, 

notwithstanding the requirements of 40 CFR 60.5375(a) and the 

combustion option they provide. 

4. Cost and Emissions Calculations

 Comment: Some commenters request the EPA to fully explain 

or reconsider the 10-percent rate of refracturing of wells. 

Response: In response to comment, the EPA has reevaluated 

the assumption that, on average, each fractured gas well is refractured every 10 years, which equates to approximately 10 

percent of fractured gas wells being re-fractured each year, 

based on drilling and re-fracture records from an industry 

representative. Based on its review of the comment, including 

references noted in the comment and other information available 

to the agency, the EPA concluded that it had overestimated the 

re-fracturing frequency. The information reviewed by the EPA, 

which, altogether, represent over 20,000 gas wells over multiple 

years, some as far back as 2000, indicate that the annual 

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recompletion frequency can be as low as 0.1 percent and as high 

as 0.8 percent. Based on this information, the EPA has revised 

its estimate of re-fracturing frequency from 10 percent to 1 

percent of fractured gas wells per year. The EPA rounded the 

figures provided by the companies to reflect the uncertainty in 

the data. 

5. Definition of Affected Facility

 Comment: Several commenters assert that a well completion 

is different from a well workover and should be better defined 

in the rule. 

Response: Based on the comments received, the EPA 

acknowledges that the term “workover” is a general term that may 

have a number of different meanings. Based on the various 

definitions of the term provided by the commenters, we realize 

that workover may be interpreted to include routine maintenance 

activities that we did not intend to cover under the rule and 

which result in no increase in emissions. Therefore, in the 

final rule we have revised the definition of “well completion 

operation” to exclude the term “workover” and, instead, include 

the phrase “with hydraulic fracturing.” 

C. Major Comments Concerning Pneumatic Controllers 

1. Definition of Affected Facility 

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Comment: Some commenters request that the EPA consider 

excluding or exempting emergency and/or safety system devices 

(such as a pilot operated pressure relief valve). According to 

one commenter, safety system devices typically do not emit gas 

unless there is an emergency, have a near-zero VOC-level static 

state and, if regulated, could be replaced by substandard, 

cheaper technology of spring operated valves which would create 

much more leakage of gas into the environment. 

With regard to emergency situations, another commenter 

argues that the proposed standards that apply to pneumatic 

controller affected facilities (40 CFR 60.5390(b)) could inhibit 

safe plant operation during an emergency because they require 

that each pneumatic controller located at a natural gas 

processing plant have zero natural gas emissions. According to 

the commenter, a gas-powered controller is a reliable 

alternative for safe plant operation during emergencies, and the 

commenter suggests that the final rule include an exception to 

allow gas plants to use natural gas-driven pneumatic controllers 

for emergency plant shutdown and subsequent startup. 

With regard to high-bleed pneumatic controllers, several 

commenters request that the EPA further explain when the use of 

high-bleed pneumatic controllers is allowed and provide specific 

examples of exemptions. The commenters suggest exemptions that 

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address situations such as those where the natural gas includes 

impurities that could increase the likelihood of fouling a lowbleed pneumatic controller, such as paraffin or salts; where 

weather conditions could degrade pneumatic controller 

performance; during emergency conditions; where flow is not 

sufficient for low-bleed pneumatic controllers; where 

electricity is not available; and where engineering judgment 

recommends their use to maintain safety, reliability or 

efficiency. Several commenters request that the EPA provide 

additional information about how to demonstrate that the use of 

high-bleed pneumatic controllers is predicated, as stated in 

proposed 40 CFR 60.5390(a). The commenters suggest that this 

exemption is very vague, will allow for excessive emissions and 

is not enforceable. 

Response: The EPA included in the proposed rule exemptions 

from the NSPS to allow the use of a controller with a natural 

gas bleed rate greater than 6 scfh due to functional needs. 

These exemptions include, but are not limited to, response time, 

safety and actuation of valves. These functional exemptions to 

the requirement address the commenters’ concerns of safety, 

emergency and otherwise non-routine situations that require the 

use of a controller with a natural gas bleed rate greater than 6 

scfh. In response to comments regarding vagueness of the 

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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 highbleed devices may be isolated from the gas pressure with a valve 

and operated manually on an intermittent basis. The commenter 

wants clarification in the rule that will allow an operator to 

use a high-bleed device if it is operated in a manner that keeps 

its emission levels less than 6 scfh. 

One commenter requests that the EPA clarify in the final 

rule that the distribution segment and self-contained devices 

that release gas to a downstream pipeline instead of to the 

atmosphere are exempt. Another commenter argues that no-bleed 

pneumatic devices have zero emissions and, thus, should not be 

included in the proposed rule. 

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One commenter discusses the use of solar-powered 

controllers, fuel-cell powered controllers and mechanicallycontrolled devices in remote locations as an alternative to 

natural gas where grid electricity is not available. This 

commenter also recommends that the EPA set a zero emissions 

standard based upon no-bleed devices wherever electricity 

(either from a grid or from field power sources) is available 

within a reasonable distance from the facility and suggests that 

the EPA could establish an exemption to no-bleed devices where 

low-bleed devices are necessary because no-bleed devices cannot 

be feasibly installed. 

Another commenter states the definition of “pneumatic 

controller” is unclear and should be revised. 

Response: In the final rule, the EPA has revised the 

definition of “affected facility” for pneumatic controllers in 

the production 

segment24 to address a number of the comments described above. 

Specifically, for pneumatic controllers at gas processing plants 

where the standard is zero bleed rate, we have defined the 

affected facility as a continuous bleed natural gas-driven 

24 The NSPS does not cover pneumatic controllers in the distribution segment.

The EPA did not address those controllers in the proposed rule. Although the

EPA had proposed standards for pneumatic controllers in the transmission and

storage segment, for reasons explained in section IX.C.2 of this preamble,

the EPA did not include such standards in the final rule. 

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pneumatic controller. For other areas in the production segment 

(i.e., excluding gas processing plants), where the standard is a 

bleed rate of 6 scfh or less, we have defined the affected 

facility as a continuous bleed natural gas-driven pneumatic 

controller operating at a bleed rate greater than 6 scfh. By 

defining the pneumatic controllers affected facilities to be 

continuous bleed and gas-driven, we clarify that the NSPS does 

not apply to intermittent bleed devices, no-bleed pneumatic 

devices (by design), self-contained devices and devices driven 

by instrument air. The revised definitions also exclude from the 

NSPS coverage owners and operators who are already using 

(including replacement) pneumatic controllers that meet the 

applicable standards, thus, relieving them from the cost and 

other burdens related to compliance. 

Regarding the comments related to solar-powered 

controllers, fuel-cell powered controllers, mechanicallycontrolled devices and no-bleed devices wherever electricity is 

available, we considered these types of devices in the BSER 

analysis, as discussed in the TSD. Any such controller system 

would require a backup system (consisting of at least an 

electrical generator) to operate the controllers when the 

primary system was inoperable. When considering the cost of the 

backup system, these options were not cost-effective. We, 

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therefore, do not believe that they are BSER for reducing VOC 

emissions from pneumatic controllers where grid electricity is 

not available. We also decline to set a zero emission standard 

“wherever electricity ... is available within a reasonable 

distance,” as a commenter suggests. We have no information, nor 

has the commenter provided any, on how to determine the 

suggested “reasonable distance.” 

Comment: Several commenters request an exemption for all 

affected facilities handling gas with less than 10-percent VOC 

content by weight. Some commenters offer suggestions for such 

exemption, such as requiring recordkeeping of the gas VOC 

content in order for a facility to maintain the exemption. 

One commenter believes that the EPA should delete the 

pneumatic controller requirements because most of the gas 

emitted is methane, and there is little VOC emission reduction 

benefit. Another commenter suggests limiting applicability to 

pneumatic controllers at natural gas processing plants or 

upstream of processing that exceeds a defined VOC threshold. 

Several commenters opine that pneumatic device definitions 

and applicability should be based on VOC emissions, not natural 

gas as a surrogate. Commenters assert that the 6 scfh highbleed/low-bleed threshold value is unsupported, that natural gas 

VOC content varies widely and that, in most cases, 

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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. According 

to the commenters, regulating the use of compressed air or 

“instrument air” or other gas having little or no VOC would 

impose a significant burden on the industry without any added 

benefit. 

Response: The EPA disagrees with the comment that the 

pneumatic controller standards must be based on VOC emissions 

instead of natural gas bleed rate as a surrogate for VOC 

emissions rate. Natural gas is being used as a surrogate for VOC 

given the proportional relationship between them. When a natural 

gas stream is emitted to the atmosphere, VOC in the gas also 

reaches the atmosphere since it is a component of the natural 

gas stream. The natural gas emissions occur without any physical 

separation, chemical separation or chemical reaction process of 

the chemical species within the natural gas; therefore, the 

proportion of VOC in natural gas is not altered during the 

course of being emitted to the atmosphere, and natural gas is an 

appropriate surrogate for VOC. As an example, when the natural 

gas emissions change, the VOC emissions change proportionately. 

In addition, measuring the VOC content of a pneumatic 

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controller’s bleed gas adds cost burden to companies and, to the 

EPA’s knowledge, vendors/manufacturers do not report the VOC 

emissions from a pneumatic controller primarily because the VOC 

emissions would depend on the gas composition at the site the 

pneumatic controller is located. 

In the preamble to the proposed rule, the EPA set forth its 

BSER analysis for pneumatic controllers. In the TSD, the EPA has 

provided cost-effectiveness calculations for the proposed 

pneumatic device emission limits. The commenters do not dispute 

the EPA’s analysis. Rather, the commenters ask that the EPA 

establish a VOC threshold. However, the commenters have not 

provided information on how an appropriate threshold can be 

established. One commenter suggests a threshold of 10-percent 

VOC content by weight, but has not provided supporting 

information justifying this threshold. However, for the reasons 

stated in the response to comment in section IX.C.2 of this 

preamble, the EPA has decided not to cover in this final rule 

the pneumatic controllers in the transmission and storage 

segment. With respect to those controllers we are not taking 

final action at this time. 

Comment: One commenter suggested that the EPA provide a 

phase-in period to allow manufacturers and companies time to 

designate which controllers qualify as low-bleed. This commenter 

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further notes that bleed rates are not specified for pneumatic 

controllers or are inconsistently represented without 

distinguishing between the continuous bleed stream and the 

actuation stream rates within the gas consumption 

specifications. 

Response: In the proposed rule, for pneumatic controllers25 

in the production segment other than gas processing plants, the 

EPA proposed a performance standard of a natural gas bleed rate 

of 6 scfh to reflect the use of a low-bleed controller, which we 

had determined to be the BSER for reducing VOC emissions from 

pneumatic controllers in the production segment.26 Owners and 

operators would demonstrate compliance based on information in 

the manufacturers’ specifications for the pneumatic controllers, 

which we had believed would provide either the bleed rate or 

relevant information for such determination. Upon further 

investigation, in light of the comments, we conclude that such 

information is not always included in current manufacturers’ 

specifications. We anticipate that manufacturers who currently 

do not provide the relevant information for determining bleed 

25 For the reasons explained earlier in this section, we have changed the

definitions of the pneumatic controller affected facility in the production

segment other than gas processing plants to be a continuous bleed natural gas

driven pneumatic controller with a natural gas bleed rate greater than 6

scfh. This change does not affect the proposed BSER analysis and VOC limit,

which apply to high-bleed pneumatic controllers in the final rule.

26 For reasons explained in section IX.C.2 of this preamble, unrelated to the

comment at issue, the final rule does not include standards for pneumatic

controllers in the transmission and storage segment. 

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rate would adjust to this need and begin testing their products 

and provide the necessary information on the products’ 

specifications. Based on public comments and other available 

information, the EPA believes that an adjustment period is 

needed, during which owners and operators could face increased 

cost and, in some instances, difficulty in obtaining necessary 

supplies due to the limited number of currently available 

controllers with adequate documentation for determining bleed 

rate. In light of the above, we conclude that a low-bleed 

controller is not the BSER for pneumatic controller affected 

facilities in the production segment (excluding gas processing 

plants) during this first year. As explained in the proposed 

rule, we are not aware of any add-on controls that are or can be 

used to reduce VOC emissions from gas driven pneumatic devices. 

76 FR 52760. One commenter broadly suggests that we consider 

flares, combustion devices and vapor recovery, but provides no 

supporting information. In light of the above, we conclude that 

there is no BSER for pneumatic controller affected sources in 

the production segment (excluding gas processing plants) during 

the “adjustment period” mentioned above. 

In determining the length of the adjustment period, the EPA 

evaluated relevant comments and available information, including 

information from promulgation and implementation of 40 CFR part 

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98, subpart W of the Greenhouse Gas Reporting rule. Subpart W 

requires operators to conduct a complete inventory and report to 

EPA the number of low- and high-bleed pneumatic devices, as 

those terms are defined in subpart W, over a 3-year period 

(i.e., 1/3 of their devices every year over a 3-year period) 

starting January 2011. We believe that efforts are well under 

way for manufacturers to provide necessary information to help 

facilities subject to subpart W determine the pneumatic 

controllers’ bleed rates and comply with the reporting rule 

requirements, 1/3 of which must be reported by September 2012 

and another third by September 2013 and the entire inventory by 

September 2014. In light of the above, we do not believe that 

owners and operators would face the difficulty described above 

beyond the first year after this NSPS becomes effective. After 

this first year of “adjustment period,” we believe owners and 

operators should have no problem securing controllers with 

relevant documentation for determining bleed rate. Therefore, 

beginning the second year, the BSER remains the low-bleed 

controllers, as proposed. 

For the reasons stated above, the final rule contains no 

standards for pneumatic controller affected facilities in the 

production segment during the first year after this rule becomes 

effective, but, thereafter, requires that all new and modified 

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affected facilities to meet a VOC limit of 6 scfh natural gas 

bleed rate to reflect the use of a low-bleed controller. The 

need for adequate manufacturers’ specifications is not an issue 

for pneumatic controllers at natural gas processing plants. For 

pneumatic controller affected facilities at natural gas 

processing plants, we had proposed a zero VOC emission limit, 

the compliance of which can be demonstrated by the use of a nongas-driven controller system. As noted by commenters, most 

natural gas processing plants already use non-gas-driven 

technology such as instrument air systems for safety and 

operational reasons. While one cannot distinguish gas-driven 

pneumatic controllers of different bleed-rates without 

information from manufacturers, a non-gas-driven controller can 

be easily identified by visual inspection. Therefore, no change 

is made since proposal to the standards for pneumatic controller 

affected facilities at gas processing plants. 

In response to comments that units already in stock at the 

time of proposal cannot be used, the EPA clarifies that 

pneumatic controllers that were already in stock or ordered 

prior to August 23, 2011, are considered existing sources and, 

therefore, their installation is not subject to the pneumatic 

controllers NSPS in this final rule. 

2. Controllers in the Transmission and Storage Segment 

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Comment: Several commenters requested the EPA reevaluate 

requirements for pneumatic controller/devices in the natural gas 

transmission segment of the industry. The commenters argue that 

the proposed rule’s applicability is too broad and would result 

in an undue recordkeeping and permitting burden. 

Several commenters recommend that 40 CFR part 60, subpart 

OOOO should limit pneumatic controller applicability to upstream 

processes. Some commenters suggest that, for natural gas 

transmission and storage, either pneumatic controllers should be 

completely excluded or subpart OOOO should limit applicability 

to equipment located at “conventional” facilities, e.g., within 

the fence line at a compressor stations. One commenter 

recommends limiting the emission limit requirement to 

controllers at natural gas processing plants or locations 

upstream from gas processing that exceed a defined VOC 

threshold. The commenter suggests that this exclusion would 

reduce administrative costs in two ways: Mandatory recordkeeping 

and reporting would be removed and the documentation required to 

explain why excluded controllers would no longer be necessary 

would be removed. Another commenter suggests that the EPA state 

in the final rule that NSPS/NESHAP applicability alone should 

not trigger minor source permitting requirements. 

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Response: The EPA agrees that cost and other compliance 

burdens are important considerations in a rulemaking. In fact, 

the EPA believes that such consideration is particularly 

important here given that coverage of the transmission sector 

would result in a significant number of sources and owner and 

operators that are not subject to the current standards. 

Specifically, were we to finalize standards, we estimate that we 

would end up covering an additional 67 sources. We estimate VOC 

emissions from these units to be 0.1 tpy per facility or about 6 

tpy nationwide for new sources, which is well below the level 

emitted by other affected facilities in this sector. 

While our analysis suggests that this is an important set 

of sources to regulate, given the large number of sources, and 

the relatively low level of VOC emitted from these sources, we 

have concluded that additional evaluation of these compliance 

and burden issues is appropriate prior to taking final action on 

pneumatic controllers in the transmission and storage segment. 

For this reason, the requirements for pneumatic controllers in 

the final rule only apply to production through processing 

segments. Our current data indicate that the VOC content of the 

natural gas used for pneumatic controllers in the transmission 

and storage segment is low, while higher VOC content natural gas 

is used in the segments we are regulating. Also, for the reasons 

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explained in the previous response to comment, no VOC threshold 

will be included in this regulation. 

3. Cost and Emissions Calculations

 Comment: One commenter asserts that the EPA’s estimate of 

14,000 new and replaced controllers in a given year is grossly 

underestimated. By the commenter’s data and calculations, 

approximately 750,000 controllers in Texas alone may need to be 

replaced (unless an exemption is granted) once a well becomes 

subject to the new rule. 

Response: The commenter incorrectly claims that the EPA’s 

estimate of the number of pneumatic controllers installed in a 

given year is 14,000. In Section 5.3.2 of the TSD, the EPA 

explains its methodology for estimating the number of pneumatic 

controllers in both gas/oil production and gas transmission and 

storage. Table 5-3 of the TSD gives a breakdown of snap-acting 

versus bleed controllers and shows the total number of 

controllers to be 33,673. The commenter did not provide data to 

support its claim that there are 750,000 pneumatic controllers 

in Texas, or that all of them have bleed rates higher than the 

proposed NSPS requirements such that any future replacement 

would require the use of a different model (i.e., low bleed or 

no bleed, depending on its location) of controller. In any 

event, the EPA has analyzed and determined that such replacement 

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is cost-effective. One explanation for the commenter’s high 

estimate may be a misunderstanding of the applicability of the 

final rule. We remind the commenter that the final rule does not 

apply to existing sources, unless the existing source is 

replaced, modified or reconstructed after August 23, 2011. 

D. Major Comments Concerning Compressors 

1. Compressors in the Transmission and Storage Segment

 Comment: One commenter stated that the agency should exempt 

reciprocating and centrifugal compressors in the transmission 

and storage sector located after the point of custody transfer, 

because there is low-VOC content in natural gas from that 

sector. Another commenter urged the EPA to revise 40 CFR 60.5365 

to exclude centrifugal compressors not associated with the Crude 

Oil and Natural Gas Production, Transmission, and Distribution 

sector. One commenter noted that some large natural gas 

customers (who are not in the Crude Oil and Natural Gas 

Production, Transmission, and Distribution sector) have natural 

gas centrifugal compressors that are used to increase the 

pressure of natural gas for use in an industrial process, or to 

compress natural gas used as the fuel in compressed natural gas 

vehicles. 

One commenter argued further that even without regard to 

fundamental flaws stated in the five factors or methods, there 

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still would be only trivial and inconsequential VOC reductions 

relative to the national VOC inventory. The commenter observed 

that achieving VOC reductions of 1 percent of the national 

anthropogenic VOC inventory would require over 21,000 

regulations at 6.9 tpy, and that the EPA’s estimated annual VOC 

reductions for compressors was similarly inconsequential. Nor, 

said the commenter, had the EPA adequately considered 

administrative burdens associated with reporting, recordkeeping 

and permitting. The commenter said the trivial, incremental 

emissions reductions that would result from the rule failed to 

justify the associated compliance costs and that the final rule 

should exclude transmission and storage sources. Another 

commenter expressly called on the EPA to reanalyze VOC emissions 

reductions and to reassess whether the rule would be cost 

effective. Also taking issue with supportive data, another 

commenter said the EPA should suspend rulemaking and expand its 

fact-finding to include a statistically significant sampling of 

affected sources. One commenter suggested that the EPA exclude 

centrifugal compressor facilities that compress natural gas that 

is less than 10 percent, weight basis, VOC. The commenter stated 

that compression of gas that does not contain VOC should not be 

subject to standards for VOC. The commenter believes this is 

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consistent with equipment leak rules which do not regulate 

components that are not in VOC service. 

Response: The EPA agrees with the commenter that natural 

gas in the transmission and storage segment has low-VOC content. 

The EPA notes that cost and other compliance burdens are 

important considerations in a rulemaking. We estimated the VOC 

emissions reductions from these units located in the 

transmission and storage segment to be 14.1 tpy for 

reciprocating compressors and 6.6 tpy for centrifugal 

compressors, which is well below the level emitted by other 

affected facilities in this segment. The EPA has not fully 

considered compliance burden for reciprocating and centrifugal 

compressors in the transmission and storage segment and is, 

therefore, not ready to take final action with respect to these 

sources. While our analysis suggests that this is an important 

set of sources to regulate, given the number of sources, and the 

relatively low level of VOC emitted from these sources, we have 

concluded that additional evaluation of these compliance and 

burden issues is appropriate prior to taking final action on 

reciprocating and centrifugal compressors in the transmission 

and storage segment. 

Also, no VOC threshold will be included in this regulation 

given the arbitrary nature of defining one using available data. 

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We believe this revision also addresses centrifugal compressors 

not associated with the Crude Oil and Natural Gas Production, 

Transmission, and Distribution sector. 

2. Dry Seals Versus Wet Seals

 Comment: Several commenters address the issue of whether 

the EPA should permit the use of a system other than dry seal to 

control emissions from centrifugal compressors. Some commenters 

provide information on situations where dry seal systems for 

centrifugal compressors are not technically feasible, such as 

where gas composition is inadequate, in some processing plants 

that already have a capture system in place, and in retrofits of 

some existing compressors due to housing design or operational 

requirements. Commenters opine that the rule should allow 

compliance using either system, depending upon particular 

circumstances, and should not preclude use of a wet sealequipped compressor with controls capable of meeting a 95­

percent VOC control efficiency or routing captured seal-oil gas 

to a fuel gas, recycling or other processing system. According 

to another commenter, it would not be feasible to capture gas 

that escapes from a centrifugal compressor and route it back to 

a low-pressure fuel stream for combustion as fuel gas; although 

such a process would capture a minimal amount of VOC emissions, 

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the high cost of equipment to recapture the emissions would make 

the method described cost-prohibitive. 

Commenters generally concurred that a 95-percent reduction 

in emissions was achievable through installing a capture system 

on a wet seal compressor. In addition, commenters disagreed with 

the EPA’s cost estimates and concluded that a wet seal capture 

system is cost effective. 

Response: In the preamble to the proposed rule, the EPA 

proposed that a dry seal system is the BSER for centrifugal 

compressors, but solicited comments on situations where the use 

of a dry seal is infeasible or otherwise inappropriate and wet 

seal is the only option. 76 FR 52762. As noted above, several 

commenters provided information on situations where dry seals 

are not technically feasible. Therefore, the EPA has concluded 

that dry seal is not the BSER for all new and modified 

centrifugal compressors. Instead, the EPA separately evaluates 

the control options for wet seal compressors. The EPA has 

identified one control option through its review of available 

information, including comments and other information obtained 

since proposal. The option is to route captured seal-oil gas to 

the compressor suction, fuel gas system or flare, all of which 

can achieve 95-percent control efficiency. 

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Based on the discrepancy between commenters’ and the EPA’s 

cost data, the EPA re-evaluated its cost information for this 

control option. The EPA cost estimates in the proposed rule 

assumed the use of a new flare to combust the captured seal oil 

gas, and, based on commenter information, the EPA is revising 

this assumption since a flare or other combustion source is 

expected to be available in gas processing facilities. From 

reviewing comments received, the EPA is aware that the captured 

gas is not always routed to a flare but in many cases is routed 

back to the compressor suction or fuel system. Given this 

information, the EPA has re-evaluated the costs for the 

centrifugal compressor wet seal capture system and determined a 

system of this type, in which the seal oil degassing vents are 

routed to fuel gas, compressor suction or an existing flare 

would cost $22,000. The estimated cost includes an intermediate 

pressure degassing drum, new piping, gas demister/filter and a 

pressure regulator for the fuel line. With this cost, the 

estimated VOC control cost effectiveness is $161/ton of VOC for 

the processing segment. If savings are included, the cost 

effectiveness for VOC control is -$2,408/ton of VOC. 

In light of the above, we have determined that the control 

option described above is the BSER for wet seal compressors. 

Accordingly, the final NSPS would require that wet seal 

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compressors reduce emission by 95 percent. For dry seal 

compressors, the only emission control option we have identified 

is the use of dry seal. Accordingly, there is no requirement in 

the final rule for dry seal compressors, and dry seal 

compressors are not affected facilities under the NSPS. 

3. New Source Definition

 Comment: Several commenters oppose the proposal in 40 CFR 

60.5365(b) and (c) that a reciprocating compressor be considered 

as “commenced construction” on the date of installation at a 

facility. Commenters argue that the EPA was “arbitrary and 

capricious” in proposing to apply the concept of “commenced 

construction” in the NSPS context to a relocated compressor, 

because the agency had no “reasoned explanation” for making the 

change and that applying the concept of “commenced construction” 

to a relocated compressor is contrary to the plain language of 

the CAA. 

Response: The EPA traditionally defines the term “commence 

construction,” as it applies to an equipment, to mean the time 

an owner or operator has entered into a contractual obligation 

to acquire the equipment. This is reflected in the definition of 

“commenced” in the General Provisions at 40 CFR 60.2, as well as 

in the relevant NSPS (see, e.g., 40 CFR 60.4230(a) of subpart 

JJJJ). We, therefore, agree with the commenters that our 

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proposed definition of “commence construction” in 40 CFR 

60.5365(b) and 40 CFR 60.5365(c) as the time of installation is 

a deviation from our traditional view. Upon reviewing the 

comments and re-evaluating the proposed definition, we conclude 

that there is no discernible difference between the compressors 

at issue and other equipment subject to NSPS that would make 

such deviation necessary or appropriate in this case. We have, 

therefore, removed these specific definitions of “commence 

construction” in 40 CFR 60.5365(b) and 40 CFR 60.5365(c) in the 

final rule. 

The NSPS also does not apply to relocated compressors. As 

provided in the NSPS General Provisions at 40 CFR 60.14(e)(6), 

relocation of an existing facility is not modification. 

E. Major Comments Concerning Storage Vessels 

1. Applicability Threshold Metric

 Comment: Numerous commenters objected to the EPA’s proposed 

use of liquid throughput to determine which storage vessels 

should be subject to the standards, asserting that the high 

variability in volatility of stored liquids and other parameters 

affecting emissions makes throughput a poor indicator of VOC 

emissions. The commenters indicate that, as a result, basing 

applicability on throughput would bring many storage vessels 

with low VOC emissions (some less than 1 tpy) under the standard 

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and the required emission controls would not be cost-effective. 

Some commenters point out that certain storage vessels with high 

emissions might not be subject to the standards based on 

throughput. 

Response: In its BSER analysis for storage vessels, the EPA 

estimated the VOC emissions for storage vessels with various 

levels of throughputs to determine the cost effectiveness of 

control. In that analysis, the EPA estimated that storage 

vessels with throughput rates of 1 barrel per day (bpd) of 

condensate or 20 bpd of crude oil are equivalent to VOC 

emissions of 6 tpy and determined that control is cost effective 

for these storage vessels. The EPA agrees with the comments that 

throughput is not a good indicator of VOC emissions and, 

therefore, not appropriate for determining the standards’ 

applicability. However, the EPA has received no comment 

contesting the EPA’s conclusion that regulating storage vessels 

emitting 6 tpy or more of VOC is cost effective and appropriate 

(the basis of our proposed throughput limit). Accordingly, in 

the final rule, the storage vessels NSPS applies to those 

emitting 6 tpy or more of VOC. This change from proposal would 

ensure that controls will be required only on those storage 

vessels where they can be applied cost effectively. This 

approach also allows for broader coverage across all types of 

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storage vessels, regardless of the fluid that is stored or where 

the storage vessel may be located. The final rule reflects this 

change and has established a VOC emissions threshold of 6 tpy 

for storage vessels to require control. Based on our revised 

cost analysis, we determined that storage vessels with VOC 

emissions equal to or greater than 6 tpy or greater were cost 

effective to control at $3,400/ton of VOC. The final rule 

requires each facility to determine its own emission factor and 

calculate the estimated emissions from each storage vessel. 

2. Definition of Affected Facility

 Comment: Numerous commenters commented on the definition of 

storage vessel in 40 CFR part 60, subpart OOOO, calling for 

greater clarity and consistency and requesting that certain 

activities or equipment be included or excluded from the 

definition. 

Response: The EPA agrees with the commenters who assert 

that a more specific and consistent definition of a storage 

vessel is needed. The revised definition more clearly focuses on 

identifying which units are considered storage vessels under 

this subpart and which units are not and describes a storage 

vessel using terminology similar to that used in 40 CFR 63, 

subpart HH. We believe it is important to be somewhat consistent 

in terminology because the NSPS and NESHAP both apply to the oil 

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and natural production segment where these tanks are primarily 

located. We also removed the emissions threshold from the 

definition and, instead, based the standard in 40 CFR 60.5395 on 

the VOC emission rate of the storage vessel. In response to 

comments requesting clarification on whether mobile units are 

considered storage vessels, we have set a minimum amount of time 

(180 consecutive days) that the storage vessel must be stationed 

at the same site before it is subject to 40 CFR part 60, subpart 

OOOO. Our reasoning for setting this minimum amount of time is 

discussed in the response to comment immediately below. 

Additionally, we have not excluded wastewater storage vessels, 

as the NSPS requires control for all storage vessels emitting at 

least 6 tpy of VOC. Further, some wastewater tanks containing 

significant amounts of organic compounds could exceed VOC 

emissions of 6 tpy. Finally, the revised definition includes 

specific exemptions for process vessels and pressure vessels to 

clarify that these units are not considered storage vessels. 

Since the applicability of subpart OOOO, as finalized, is not 

based on throughput, we believe it is not necessary to specify 

which types of stored materials are regulated and which are not, 

as suggested by commenters. If a stored material is emitting at 

least 6 tpy of VOC, then the storage vessel will need to reduce 

its VOC emissions by 95 percent. 

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Comment: Some commenters assert that the EPA should limit 

applicability to storage vessels that are stationary and should 

clarify the meaning of “stationary” to include or exclude 

certain types of storage vessels. 

Additionally, the EPA received comments requesting that the 

stationary aspect of the “storage vessel” definition should be 

consistent with other rules, while acknowledging the particular 

scenarios unique to the oil and gas production segment. The 

commenter notes that the stationary aspect of a storage vessel 

is typically addressed by the EPA in terms of whether it is 

reasonably portable, although the EPA sometimes addresses 

portability based on the size of the vessel. The commenter 

states that another criterion specified by the EPA in several 

regulations is that “vessels permanently attached to motor 

vehicles” are not storage vessels, and the EPA has issued a 

determination that this exemption extends to storage vessels 

“equipped with a permanently attached wheel assembly and a truck 

hitch” (U.S. Environmental Protection Agency, letter from George 

T. Czerniak to Ken Comey, Flint Hills Resources L.P., September 

2, 2004). According to the commenter, this renders most socalled frac tanks, Baker tanks, International Organization for 

Standardization tanks, etc., exempt from the storage vessel 

provisions when this form of definition is used. However, the 

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commenter recognizes that such storage vessels sometimes become 

effectively “stationary” in oil and gas production operations 

and suggests that storage vessels should be deemed stationary if 

they remain at a given site for more than 180 consecutive days, 

consistent with the period of time allowed under 40 CFR 60.14(g) 

to achieve compliance after a modification. The commenter notes 

that this 180-day period is reasonable given that the definition 

of non-road engines in 40 CFR 89.2 allows a period of 12 

consecutive months. 

The commenter also points out that cost effectiveness of 

the proposed control measures has been evaluated under the 

assumption that storage vessels remain in place for the useful 

life of the control equipment, and, thus, the control costs are 

amortized over a period of years. Since the cost per ton of 

emission reductions would be much higher if the controls were 

applied to a storage vessel that is only on site temporarily, 

the commenter believes that a cost-effectiveness analysis for 

permanent storage vessels would not be valid for temporary 

storage vessels, and, thus, the control requirements for 

permanent storage vessels are not justified for temporary 

storage vessels. The commenter provides recommended language for 

the definition of “storage vessel” that addresses this and other 

concerns. Another commenter similarly states that costly control 

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requirements are not appropriate for temporary storage vessels 

(on site less than 180 days). 

Response: Based on the commenter’s suggestion, the EPA has 

revised the definition of storage vessel to clarify that a 

storage vessel is subject to 40 CFR part 60, subpart OOOO if it 

remains on a given site for more than 180 consecutive days. 

In general, we agree with the commenter’s discussion about 

the EPA’s past practices related to storage vessels. In 

particular, we agree that the inherent differences between 

“mobile” or temporary storage vessels in this source category 

and other categories indicate that they should be regulated 

differently. As mentioned in the previous response, there are 

many storage vessels in this source category that travel from 

site to site, so we did not feel it was appropriate to exclude 

all of these mobile storage vessels from control requirements. 

Many temporary storage vessels in this source category are 

typically bringing in material such as fracking fluid to well 

sites and can stay at a well site for up to several months in 

order to receive flowback. These storage vessels are considered 

to be an essential part of the drilling and production 

operation, more akin to how permanent storage vessels are 

utilized in the refining and organic chemical manufacturing 

sectors, rather than to conventional tank trucks that are 

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typically excluded in other EPA rules. Therefore, we believe 

that 180 days is an appropriate period of time to establish a 

temporary tank as being subject to 40 CFR part 60, subpart OOOO, 

and, therefore, potentially required to install controls. 

3. References to MACT Standards

 Comment: The EPA received comment asserting that the 

outcome of its best demonstrated technology (BDT) analysis for 

proposed 40 CFR part 60, subpart OOOO was calculated to achieve 

the same level of control as 40 CFR part 63, subpart HH – 

undermining the BDT determination and effectively (and 

unlawfully) extending subpart HH major source MACT requirements 

to area source storage vessels. 

As a result, the commenter asserts that the EPA’s analysis 

precludes other potentially relevant regulatory alternatives – 

such as marginally less effective controls that might be applied 

to a broader range of storage vessels. The commenter states that 

the EPA’s failure to consider other control techniques and other 

levels of control efficiency that might be achieved by its 

preferred techniques is arbitrary and capricious. 

Response: The commenter incorrectly asserts that the EPA’s 

NSPS for storage vessels was designed to achieve the same level 

of control as MACT in 40 CFR part 63, subpart HH. In Portland 

Cement Assoc. v. EPA, 665 F.3d 177(D.C. Cir. 2011), the United 

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States Court of Appeals for the District of Columbia Circuit 

rejected an argument that the EPA adopted NESHAP PM standards 

for NSPS, noting that the EPA arrived at the same limit for both 

NESHAP and NSPS using two different mechanisms. Similarly, in 

this case, although both the NESHAP and the NSPS require 95­

percent control, the EPA established the two standards based on 

separate mechanisms. The EPA established the MACT standard in 

1998 pursuant to section 112(d)(2) and (3) of the CAA. In 

contrast, the EPA established the NSPS based on BSER analysis 

under CAA section 111. The BSER analysis for storage vessels 

consists of the same steps as those for other affected sources 

evaluated in the proposed NSPS. Specifically, the EPA evaluated 

available information to identify VOC control options. The EPA 

then assessed various aspects of the control options, including 

their VOC reduction potentials, their cost effectiveness and 

secondary air impacts. The commenter did not claim that any part 

of the EPA’s BSER analysis above was inaccurate or 

inappropriate. For the reasons stated above, the commenter’s 

assertion is without support. 

The commenter also claims that the EPA only analyzed two 

controls and, therefore, failed to consider other “potentially 

relevant regulatory alternatives.” However, the commenter did 

not identify any other control option for the EPA’s 

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consideration. The commenter simply suggests that the EPA should 

consider some less effective controls, which the commenter 

claims would have led to greater coverage. Without more 

information, it is unclear whether a less effective control than 

that we have identified would, in fact, qualify as BSER for 

controlling VOC emissions from storage vessels or would have 

resulted in coverage of additional storage vessels. 

Comment: Two commenters state that the cost of the 

performance tests, monitoring, recordkeeping, etc., that are 

required through cross-references to 40 CFR 63, subpart HH were 

not adequately considered by the EPA in the cost-effectiveness 

determination for 40 CFR part 60, subpart OOOO, which applies to 

dispersed locations that do not have electricity or automation, 

and have limited remote transmitting unit space. 

Response: The EPA does not take into account monitoring, 

recordkeeping and reporting costs in determining cost 

effectiveness of controls and in evaluating BSER. Based on this 

and other comments detailed in the response to comments for this 

final rulemaking, the EPA removed from 40 CFR part 60, subpart 

OOOO the citations to the requirements for performance tests, 

monitoring, recordkeeping, etc., in 40 CFR part 63, subpart HH 

and incorporated these subpart HH requirements into subpart 

OOOO. During the incorporation process, we made minor revisions 

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to the subpart HH requirements, as appropriate for subpart OOOO. 

For example, we removed references to glycol dehydrators and 

paragraphs listed as “reserved.” 

4. Availability of Control Equipment

 Comment: Some commenters believe that there will be a 

shortage of control equipment available to meet the proposed 

storage vessel requirements, and recommend revisions to the 

compliance deadline for storage vessels based on a variety of 

considerations, including the availability of control devices, 

lead time needed for manufacturer testing of their combustors to 

be compliant with the NSPS and time needed to install the 

compliant devices. 

Response: We agree that it will likely take some time 

beyond the promulgation date of the NSPS for combustor 

manufacturers to have control devices constructed, tested, 

documented and available for operators to install in efforts to 

comply with the storage vessel requirements of the NSPS. Under 

the final rule, operators are not required to conduct individual 

performance tests on combustors installed in the field if the 

combustor manufacturer tests and documents for the owner or 

operator that the model achieves a control efficiency of 95.0 

percent. The time required for testing and documentation is 

often longer than for a single model when manufacturers provide 

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multiple models for varying applications based on capacity. We 

believe this testing and documentation program would require an 

“adjustment period” for manufacturers to be ready to supply the 

operators with the correct equipment they need. 

We considered whether it would be feasible for on-site 

testing to mitigate the shortage of manufacturer tested 

combustors. Although owners and operators can test their 

individual combustors in the field to determine combustor 

efficiency, such emissions testing is expensive and can only be 

performed if testing consultants are available to conduct the 

testing. We believe that immediately after the effective date of 

the NSPS there will be a shortage of available testing 

consultants concurrent with the shortage of pre-tested combustor 

models. As a result, we conclude that on-site testing would not 

sufficiently mitigate the difficulty of owners and operators 

complying with the NSPS. 

We evaluated whether controls other than combustors would 

be available during this adjustment period. Although vapor 

recovery units (VRU) can provide 95.0-percent control for 

storage vessels and are one means of meeting the storage vessel 

standards in the NSPS, VRU cannot be used in every situation. 

For example, storage vessels located remotely where there is no 

available electrical service may not be able to be controlled 

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using VRU. In addition, storage vessels with low concentration 

emission streams or fluctuating emissions may not be amenable to 

control by VRU. Further, VRU installations would also require 

on-site testing, and owners and operators would be hampered by 

the same consultant shortage situation described above for 

combustors. 

In light of the above, we conclude that there is no BSER 

for storage vessel affected sources during the first year after 

promulgation, which we believe is appropriate for the adjustment 

period mentioned above. At the end of this adjustment period, we 

believe owners and operators should have no problem securing 

control devices that are manufacturer-tested and have 

appropriate documentation for determining control efficiency. 

Accordingly, the final rule provides for a 1-year phase-in 

beginning [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 

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source to achieve compliance, depending on the area of the 

state. Wyoming allows only 30 days in ozone nonattainment areas, 

60 days for concentrated development areas or 90 days elsewhere 

in the state. The EPA believes that 60 days is a reasonable 

period for controlling new storage vessels at wells sites with 

no wells already in production. 

However, for replacement storage vessels or additional 

storage vessels at well sites with one or more wells already in 

production, we believe the operator already should have 

information on liquid composition and throughput. This 

information would allow estimation of VOC emissions to determine 

applicability of control requirements and for acquisition and 

installation of a control device concurrent with the replacement 

or additional storage vessel being installed. In the final rule, 

for storage vessels constructed, modified or reconstructed at 

well sites with no well already in production, we have provided 

for a 30-day period for throughput to stabilize and for the 

operator to estimate VOC emissions to determine whether a 

control device will be required. If VOC emissions are estimated 

to be at least 6 tpy, the operator is provided an additional 30 

days for the control device to become operational. We believe 

that the Wyoming experience illustrates that this will be 

sufficient time to size and obtain suitable controls. 

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F. Major Comments Concerning Notification, Recordkeeping and 

Reporting Requirements 

1. 30-Day Notification and Annual Reports

 Comment: Multiple commenters state that the 30-day advance 

notification of well completions under 40 CFR 60.5420(a) should 

be removed from the final rule. Commenters assert that this and 

notification requirements in 40 CFR 60.7(a) are unduly 

burdensome and costly, not adequately explained, not related to 

verifying compliance with the proposed rule and could conflict 

with the need to protect proprietary business information. 

Multiple commenters also note that industry’s estimate of 

annual completions is several times higher than the EPA’s 

estimate of 20,000 completions following fracturing and 

completions following refracturing annually. The commenters 

believe that these requirements will likely overwhelm both 

regulated entities and state regulators alike. Commenters offer 

suggestions, including requiring annual certifications or 

maintaining records available for inspection, reducing the 

proposed advance notification requirement to 5-10 days and 

considering notification programs such as those in Texas and 

Wyoming. Different commenters support or oppose requiring a 30­

day advance notice with follow-up notification of 1-2 days 

before an impending completion. 

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Several commenters suggest that the EPA should coordinate 

with state and local agencies to eliminate duplicative 

recordkeeping and reporting requirements, and that records of 

interest other than those submitted to the respective Oil and 

Gas Commissions should only be required to be retained and 

available upon inspection, similar to other permit requirements. 

Several commenters do not agree that an annual report under 

40 CFR 60.7(a)(1), 40 CFR 60.7(a)(3) and 40 CFR 60.7(a)(4) adds 

any value for verifying compliance and the EPA should remove 

this requirement from the final rule. The commenters add that 

the best method for compliance is for an owner or operator to 

maintain necessary records and to have the records available for 

review during an on-site inspection. One commenter suggests the 

annual report should include for each type of affected facility 

(1) the total number of affected facilities at the site; (2) the 

number of facilities that became affected facilities during the 

reporting period; (3) the number of exempted facilities; and (4) 

the number of affected facilities with a non-compliance 

situation during the reporting period. One commenter suggests 

that it would be easier for facilities to submit an annual 

report on a set date each year, and multiple affected facilities 

could be included in a single report. Two commenters propose 

that all notifications for each year be delivered in a single 

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annual report corresponding to the reporting period in which the 

affected facilities become subject to the rule. One commenter 

suggests that operators should be required to keep records at 

the nearest manned office, but reports should only be required 

if they are requested by the EPA. 

The commenters recommend, where feasible, streamlining the 

final notification and reporting requirements to eliminate 

unduly burdensome notification and reporting requirements. 

Response: The EPA agrees that certain notification, 

recordkeeping and reporting requirements in the General 

Provisions are unduly burdensome for the new affected facilities 

in this NSPS. For that reason, well completions, pneumatic 

controllers and storage vessels will be exempt from the 

notifications required by 40 CFR 60.7(a)(1), (3) and (4). We 

agree that notifications of well completions should be as 

streamlined as possible to remove excess burden from both the 

owners and operators and regulatory agencies, as well. As a 

result, we have removed the 30-day advance notification 

requirement and instead are requiring an advance notice via 

email to the EPA or delegated authority no later than 2 days 

prior to completion. 

To avoid duplicative and potentially conflicting 

notification requirements and to relieve notification burden 

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from owners and operators, we have added a provision in the 

final rule that, if an owner or operator has met the state 

requirements for advance notification of well completions, then 

the owner and operator are considered to have met the advance 

notification requirement for gas well completions under the 

NSPS. 

We also believe that the operator should be provided 

flexibility to use new technology to document compliance that 

would result in less paperwork burden on the part of the 

operators themselves and on regulators. To lessen the reporting 

burden, the final recordkeeping and reporting requirements for 

well completions also provide for a streamlining option that 

owners and operators may choose in lieu of the standard annual 

reporting requirements. The standard annual report must include 

copies of all well completion records for each gas well affected 

facility for which a completion operation was performed during 

the reporting period. The alternative, streamlined annual report 

for gas well affected facilities requires submission of a list, 

with identifying information of all affected gas wells 

completed, electronic or hard copy photographs documenting REC 

in progress for each well for which REC was required and the 

self-certification required in the standard annual report. The 

operator retains a digital image of each REC in progress. The 

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image must include a digital date stamp and geographic 

coordinates stamp to help link the photograph with the specific 

well completion operation. Operators are not required to take 

advantage of the optional recordkeeping and reporting approach, 

as some may choose to follow the standard reporting 

requirements. Under either approach, the report must include a 

record of all deviations during the reporting period in cases 

where well completion operations with hydraulic fracturing were 

not performed in compliance with the requirements for each gas 

well affected facility.

 Comment: One commenter requested that the EPA add a selfcertification requirement to the annual report similar to that 

used in the title V program. The commenter recommended that the 

final rule require the annual report to include a statement 

signed by a senior official of the facility attesting to the 

truth, accuracy and completeness of the report. 

The commenter also requested that the EPA require that the 

annual reports be submitted electronically to facilitate making 

the reports publicly available. The commenter suggested using 

social media outlets, smart phone applications and other 

electronic means to make the annual reports readily available. 

Response: The EPA agrees that self-certification is an 

important mechanism for assuring the public that the information 

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submitted by each facility is accurate. In addition, the title V 

program has successfully employed self-certification since its 

inception. Therefore, we are requiring self-certification, based 

on requirements in the title V program, in the final rule. 

While we agree that having annual reports readily available 

to the public is a desirable goal, we did not identify any 

reporting programs or electronic databases that may be used for 

this purpose without significant modification. Therefore, we are 

not requiring annual reports to be submitted electronically, but 

we will continue to evaluate this option in the future. 

2. Duplicative Recordkeeping and Reporting Requirements

 Comment: Multiple commenters state that the notification, 

recordkeeping, monitoring and annual reporting requirements in 

the proposed NSPS are duplicative and extremely burdensome for 

operators and for state regulators with limited resources. The 

commenters make both general and specific recommendations to 

revise the reporting requirements in the final rule to eliminate 

duplication and reduce burden or better inform the public and 

regulatory agencies about deviations. Some commenters would 

eliminate all or some reports, while others argue that reporting 

is an essential compliance and enforcement mechanism and that 

additional information should be provided. Some commenters feel 

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that an owner or operator should maintain necessary records and 

have them available for review. 

Commenters want the compliance assurance requirements to be 

appropriate for the oil and gas industry and commensurate to the 

environmental benefit that will be generated. For example, some 

commenters feel that the EPA should exempt small sources 

regulated under this rule from the notification and reporting 

requirements. 

Response: We have considered these and other related 

comments presented in the response to comments regarding the 

proposed reporting requirements. The EPA agrees that certain 

notification, recordkeeping and reporting requirements are 

unduly burdensome and believes it is important to minimize the 

burden of reporting requirements. However, as noted in several 

comments, states and other enforcement entities are confronting 

limited resources and visiting sites is not always practical and 

is particularly challenging in this industry. For that reason, 

the EPA believes notifications and reporting requirements are 

vital to ensure compliance with our regulations. Therefore, the 

EPA has evaluated the proposed notification, recordkeeping and 

reporting requirements in an effort to streamline the 

requirements to reduce burden on both industry and enforcement 

at the same time, assuring compliance with the NSPS. In the 

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final rule, the EPA has removed or otherwise revised proposed 

reporting requirements that the EPA believes to be duplicative 

or unnecessary, including, but not limited to, those raised in 

the comments. These changes will streamline the reporting 

process and reduce the reporting burden on sources, including 

small sources. For example, as previously discussed, well 

completions and continuous bleed natural gas controllers are 

exempt from the notifications required by 40 CFR 60.7(a)(1), 40 

CFR 60.7(a)(3) and 40 CFR 60.7(a)(4). In addition, the EPA has 

revised the rule language such that only continuous bleed 

natural gas controllers installed, modified or replaced during 

the reporting period are reported in the annual report. In 

addition, the EPA has revised the 30-day individual notification 

requirement for well completions, as discussed above. 

3. Electronic Reporting of Emissions Data

 Comment: Commenters suggest a variety of ways in which 

electronic reporting could be structured and implemented, with 

attention to coordination with various CAA requirements and 

programs to avoid duplicative and potentially burdensome 

requirements. Several commenters support electronic reporting of 

emissions data from all sources to be stored on existing EPA 

databases, such as the Electronic Greenhouse Gas Reporting Tool 

(e-GGRT) or added to the Toxics Release Inventory, and available 

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to the public. These commenters believe that communities must 

have access to air quality information in order to protect 

public health. One commenter objects to the use of e-GGRT as a 

reporting mechanism in place of a state’s own tracking system, 

where the state has enforcement responsibility for the emissions 

date and tracking of sources subject to the proposed rule. The 

commenters also suggested a variety of ways in which electronic 

reporting could be structured and implemented. 

Several commenters oppose the implementation of electronic 

reporting at this time and are concerned that an ERT will result 

in numerous complications and undue additional burden. The 

commenters point out that the EPA’s experience with e-GGRT 

indicates that considerable time and resources are needed to 

develop and implement efficient systems and to ensure that 

electronic reporting enhances efficiency rather than incurring 

additional burden on affected sources. The commenters state that 

a potential disadvantage associated with an ERT is that new 

and/or alternative test methods would not be in the system. In 

addition, the commenters believe that an ERT could be 

complicated and burdensome for smaller companies that lack 

environmental personnel or experience with electronic reporting 

under other rules. The commenters suggest that if the EPA 

delegates authority to states to implement and enforce the 

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standards, some states may be unable or unwilling to accept 

electronic reports. The commenters urge the EPA to consider 

other more simplified options to report only the needed 

information. 

Response: While the EPA supports and encourages electronic 

reporting, after further consideration of all the comments, we 

do not believe the e-GGRT is the appropriate mechanism for 

electronic reporting under this rule, as recommended by some 

commenters. The e-GGRT is not designed to accept all of the 

types of information required to be reported under the final 

rule, and significant modification of the system would be 

required to make it operational for this rule. 

However, the final rule does include reporting of 

performance test data via the ERT. The EPA must have performance 

test data to conduct effective reviews of CAA sections 112 and 

129 standards, as well as for many other purposes, including 

compliance determinations, emission factor development and 

annual emission rate determinations. In conducting these 

required reviews, the EPA has found it ineffective and time 

consuming, not only for us, but also for regulatory agencies and 

source owners and operators, to locate, collect and submit 

performance test data because of varied locations for data 

storage and varied data storage methods. In recent years, 

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though, stack testing firms have typically collected performance 

test data in electronic format, making it possible to move to an 

electronic data submittal system that would increase the ease 

and efficiency of data submittal and improve data accessibility. 

In the final rule, as a step to increase the ease and 

efficiency of data submittal and improve data accessibility, the 

EPA is requiring the electronic submittal of select performance 

test data. Data entry will be through an electronic emissions 

test report structure called the ERT. The ERT will generate an 

electronic report which will be submitted using the CEDRI. The 

submitted report is submitted through the EPA’s CDX network for 

storage in the WebFIRE database making submittal of data very 

straightforward and easy. Webfire is the EPA's online emissions 

factor repository, retrieval and development tool. The WebFIRE 

database is open to the public and contains the EPA’s 

recommended emissions factors for criteria and HAP for 

industrial and non-industrial processes. Emissions data 

collected from the oil and natural gas sector, as well as many 

other sectors, will be used to update our emissions factors. The 

data will also be used by the EPA's rule writers to make better 

informed decisions and learn more detailed information about 

emissions from sources. The electronic reporting requirement in 

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this rule (and other NSPS/NESHAP rules) is only for test methods 

that are supported by the ERT. 

One major advantage of submitting performance test data 

through the ERT is a standardized method to compile and store 

much of the documentation required to be reported by this rule. 

Another advantage is that the ERT clearly states what testing 

information would be required. Another important benefit of 

submitting these data to the EPA at the time the source test is 

conducted is that it should substantially reduce the effort 

involved in data collection activities in the future. 

State, local and tribal agencies can also benefit from a 

more streamlined and accurate review of electronic data 

submitted to them. The ERT allows for an electronic review 

process rather than a manual data assessment making review and 

evaluation of the data and calculations easier and more 

efficient. Finally, another benefit of submitting data to 

WebFIRE electronically is that these data will greatly improve 

the overall quality of the existing and new emission factors by 

supplementing the pool of emissions test data for establishing 

emissions factors and by ensuring that the factors are more 

representative of current industry operational procedures. A 

common complaint heard from industry and regulators is that 

emission factors are outdated or not representative of a 

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particular source category. With timely receipt and 

incorporation of data from most performance tests, the EPA will 

be able to ensure that emission factors, when updated, represent 

the most current range of operational practices. 

X. Summary of Significant NESHAP Comments and Responses 

For purposes of this document, the text within the comment 

summaries was provided by the commenter(s) and represents their 

opinion(s), regardless of whether the summary specifically 

indicates that the statement is from a commenter(s) (e.g., “The 

commenter states” or “The commenters assert”). The comment 

summaries do not represent the EPA’s opinion unless the response 

to the comment specifically agrees with all or a portion of the 

comment. 

A. Major Comments Concerning Previously Unregulated Sources 

Comment: One commenter asserts that, although the EPA’s 

original MACT analysis covered all storage vessels, it issued a 

MACT standard at that time that applied to storage vessels with 

the PFE only. The commenter states that, while they support the 

EPA’s effort to correct this omission, the initial analysis for 

the tanks that the agency did regulate in 1999 was seriously 

flawed, and the proposed rule provides no justification for 

continuing to rely on a 13-year old analysis to propose a MACT 

standard for an entirely new universe of storage vessel sources. 

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Thus, according to the commenter, the EPA’s failure to properly 

calculate the MACT floor in setting the MACT standard for 

storage vessels violates CAA section 112(d)(2) and (3). 

The commenter states that, because this method has been 

found to be unlawful and substantially more data are available 

at this time, the EPA must now recalculate the MACT floor and 

MACT limits for tanks with the PFE. Cement Kiln Recycling 

Coalition, et. al. v. U.S. EPA, 255 F.3d 855, 863-64 (D.C. Cir. 

2001). The commenter asserts that, in addition and partly as a 

consequence of its unlawful reliance on the prior standards, the 

EPA also has failed to fulfill the beyond-the-floor requirement 

of CAA section 112(d)(2). The commenter opines that, absent an 

up-to-date analysis based on current emission controls, an 

appropriate beyond-the-floor determination cannot be made. 

Two commenters do not believe that the dataset used is 

representative of currently operating small glycol dehydrators. 

One commenter believes that the EPA has not satisfied section 

112(d)(2) and (3) of the CAA and that the EPA needs to calculate 

the MACT 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 

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sources within the category or subcategory. The commenter 

reports that more current data sources may be available, such as 

dehydrator emissions data reported to state agencies in annual 

emission reports or in permit applications. 

One commenter opines that the EPA’s proposal misses the 

opportunity and fails to fulfill the agency’s responsibility to 

properly calculate the MACT for all sources in this sector based 

on current, reliable and representative emission test data. The 

commenter believes that, by relying on an incomplete and 

outdated dataset to set MACT floors and limits, the EPA has 

ignored data demonstrating trends in practices, processes and 

technologies and the resulting improved performance that CAA 

section 112(d) mandates. The commenter asserts that the EPA 

ignores the potential HAP emissions that the control devices 

themselves emit by failing to collect such emissions data from 

facilities that have installed control devices. The commenter 

argues that the EPA must collect the appropriate emission test 

data needed in order to recalculate and set a proper MACT for 

glycol dehydrators, storage vessels and equipment leaks. 

One commenter states that section 112 of the CAA requires 

the EPA to set a NESHAP for each category or subcategory of 

“major sources” of HAP emissions. 42 U.S.C. §7412(d)(1). The 

commenter asserts that the EPA must set CAA section 112(d) 

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emission standards based on “maximum achievable control 

technology” or “MACT.” The commenter states that the EPA largely 

bases its MACT proposal for small glycol dehydrators on 

emissions data collected from the industry during the 

development of the original MACT standards. 76 FR 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 technological developments that have occurred during 

the past 13 years. According to the commenter, the EPA has not 

provided a reasoned explanation of how those data could be 

representative of currently operating glycol dehydrators and 

associated emission reductions, and how proposals based on those 

data can currently meet the MACT requirements for new and 

existing sources. The commenter states that the dehydrator 

technology performance in 1997 was not accurately reflected in 

the legacy EPA dataset and has advanced significantly in the 

past 13 years. Consequently, according to the commenter, the EPA 

has not provided a reasoned explanation of how those data could 

be representative of currently operating glycol dehydrators and 

associated emission reductions, and how proposals based on those 

data can currently meet the MACT requirements for new and 

existing sources. The commenter believes this is critical 

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because the 2005 NEI data reveal that improvements in the 

environmental performance of the category have progressed such 

that there are far more units in service with lower emissions 

than reflected in the 1997 data. 

One commenter states that the EPA did not collect recent 

data regarding emissions of HAP, including BTEX, from small 

glycol dehydrators in either source sector in support of this 

rulemaking. Instead, according to the commenter, the EPA appears 

to have relied on data collected in the prior MACT rulemaking, 

going back to 1998 or prior. The commenter believes that the 

EPA’s analysis is flawed and questionable because it simply 

relies on the best-performing sources that existed a decade ago 

and fails to identify the best controlled sources today. The 

commenter contends that it is unlikely that these MACT standards 

reflect either the current best controlled similar source 

emissions or the average of the top 12 percent of the currently 

best controlled sources. The commenter states that, while the 

EPA appropriately proposes to set a MACT limit for these sources 

for the first time, the EPA’s use of out-dated data fails to 

demonstrate that its proposed limit is stringent enough in light 

of significant developments in emission control technologies and 

practices that have occurred since 1998. 

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Response: One commenter argues that EPA has not satisfied 

sections 112(d)(2) and (3) of the CAA, because the MACT 

standards set in the 1999 rule have not been re-calculated using 

current data. To the extent the commenter is arguing that CAA 

section 112(d)(6) requires that the EPA recalculate the MACT 

standards set in 1999, based on current emissions test data, the 

commenter is incorrect. In NRDC v. EPA, 529 F.3d 1077, 1084 

(D.C. Cir. 2008), the District of Columbia Circuit held that it 

“[did] not think the words ‘review, and revise as necessary’ can 

be construed reasonably as imposing any such obligation” to recalculate the MACT floors. NRDC v. EPA, 529 F.3d 1077, 1084 

(D.C. Cir. 2008). 

Moreover, in this action, we did not re-open the MACT 

standards in 40 CFR part 63, subpart HH for large glycol 

dehydrators, storage vessels with the PFE and equipment leaks 

for or in 40 CFR part 63, subpart HHH for large glycol 

dehydrators. As such, the commenter’s request that we recalculate those standards based on current emissions data is 

outside the scope of this rulemaking. We did, however, conduct a 

CAA section 112(d)(6) technology review for subpart HH and 

determined that there have been no developments in practices, 

processes or control technologies for large glycol dehydrators, 

storage vessels with the PFE and equipment leaks and that there 

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have been developments for equipment leaks. See Technology 

Review for the Final Amendments to Standards for the Oil and 

Natural Gas Production and Natural Gas Transmission and Storage 

Source Categories and responses on section 112(d)(6) comments 

below. We also conducted a CAA section 112(d)(6) technology 

review for subpart HHH and determined that there have been no 

developments in practices, processes or control technologies for 

large glycol dehydrators. Id. 

The remaining comments focus on the data the agency used to 

set the proposed MACT standards for small glycol dehydrators, 

which were left unregulated in the 1999 rule. The commenters 

claim that the data the EPA used to set the BTEX MACT standards 

for the small glycol dehydrators subcategory are outdated and 

that the EPA must collect new data. However, CAA section 

112(d)(3) specifically provides that the Agency is to determine 

the average emission limit achieved by the best performing 12 

percent of existing sources “(for which the Administrator has 

emissions information”). Thus, the EPA is not required to 

collect information if it determines that the information it has 

is sufficient for it to calculate the MACT standards consistent 

with the requirements of CAA section 112. Although the available 

emissions information is over a decade old, the available 

controls for reducing BTEX emissions from small glycol 

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dehydrators and their control efficiencies have remained the 

same during this period, and the commenters have not provided 

any data to the contrary.27 We, therefore, believe the data we 

have are still representative of the performance of the small 

dehydrators. 

Moreover, we believe that the collection and analysis of 

additional data would take time and further delay control of 

these sources, which we do not think is warranted where, as 

here, we believe the data on BTEX emissions for the subcategory 

of small glycol dehydrators are still representative of these 

sources’ performance today and the commenter did not provide any 

data that indicates otherwise. 

Finally, for small glycol dehydrators, we considered using 

more current available data, like the 2005 NEI, however, the NEI 

dataset lacks specific information that we believe is relevant 

to identifying the best performing units. Specifically, the NEI 

data lacks information on inlet HAP content and gas throughput, 

both of which affect a glycol dehydrator’s HAP emissions. Inlet 

HAP content varies from well site to well site. A wellcontrolled glycol dehydrator at a well site with high inlet HAP 

content may have higher HAP emissions than a totally 

27 Memorandum from Brown, Heather, EC/R Inc., to Moore, Bruce, U.S. EPA,

titled Technology Review for the Final Amendments to Standards for the Oil

and Natural Gas Production and Natural Gas Transmission and Storage Source

Categories. Dated April 17, 2012. 

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uncontrolled glycol dehydrator at a well site with a low inlet 

HAP content. Natural gas throughput also affects a glycol 

dehydrator’s overall emissions (i.e., low throughput units will 

tend to have lower overall emissions, and vice versa). For the 

reasons stated above, in addition to emissions, we need to 

consider the inlet HAP content and gas throughput of the small 

glycol dehydrators in order to properly identify the best 

performing sources and establish the MACT standard for this 

subcategory. However, information on natural gas throughput and 

inlet HAP content is not included in the NEI or any other 

readily available data source. Therefore, we used the 1997 data 

which included such information for the small dehydrators. 

Comment: One commenter supports the EPA’s regulation of 

previously unregulated sources in the oil and natural gas sector 

and the commenter asserts that CAA sections 112(c) and 112(k) 

(Urban Air Toxics Strategy) support their position regarding the 

regulation of previously unregulated sources. The commenter 

asserts that historical regulation of emission sources within 

the sector leaves a large number of dehydrators, storage vessels 

and equipment at gas processing plants unregulated. 

Additionally, the commenter states that historical regulation 

has also not limited emissions from a number of other emission 

sources (i.e., wells, pneumatic devices, compressor seals, 

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valves, or flanges or other production equipment located at oil 

and gas production facilities or natural gas storage 

transmission facilities). 

One commenter supports the EPA’s recognition of the need to 

control emissions from previously uncontrolled emission points 

and commends the EPA on addressing small glycol dehydration 

units and storage vessels without the PFE. The commenters 

request that the EPA address all of the uncontrolled HAP 

emission points of which it is aware. 

Response: This rule establishes MACT standards for major 

sources of small glycol dehydrators that were left unregulated 

in the 1999 MACT rule. As explained further below, in several 

recent rulemakings, we have chosen to fix certain underlying 

defects in existing MACT standards under CAA sections 112(d)(2) 

and (3), which are the provisions that directly govern the 

initial promulgation of MACT standards (see National Emission 

Standards for Hazardous Air Pollutants From Petroleum 

Refineries, October 28, 2009, 74 FR 55670; and National Emission 

Standards for Hazardous Air Pollutants: Group I Polymers and 

Resins; Marine Tank Vessel Loading Operations; Pharmaceuticals 

Production; and the Printing and Publishing Industry, April 21, 

2011, 76 FR 22566). We believe that this approach is reasonable 

because using those provisions ensures that the process and 

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considerations are those associated with initially establishing 

a MACT standard, and it is reasonable to make corrections 

following the process that would have been followed if we had 

not made an error at the time of the original promulgation. We 

appreciate the commenter’s support for regulating small glycol 

dehydrators. 

Although the agency had proposed MACT standards under CAA 

sections 112(d)(2) and (3) for the subcategory of storage 

vessels without the PFE, we are not finalizing those standards 

here. Based on our review of the comments, we believe that we 

need additional data in order to set an emission standard for 

these vessels. We intend to collect the appropriate data and 

propose a MACT emission standard under CAA sections 112(d)(2) 

and (3) of the CAA. 

The commenter identifies certain emission sources, other 

than small glycol dehydrators and storage vessels without the 

PFE (e.g., wells), that it alleges are uncontrolled. CAA section 

112(n)(4)(A) prohibits aggregation of emissions from any oil and 

gas exploration or production wells (with their associated 

equipment) in determining major source status or for any purpose 

under CAA section 112. In light of this prohibition on 

aggregation, and the fact that the sources identified by the 

commenter likely would not, if viewed alone, qualify as a major 

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source, it is not clear whether emissions from the sources 

identified by the commenter can be addressed by a major source 

NESHAP.28 

The commenter also references CAA section 112(k) (and the 

Urban Air Toxic Strategy). CAA section 112(k) is designed to 

address area source emissions in urban areas. This rule involves 

a review of 40 CFR part 63, subparts HH and HHH, both of which 

address major sources, not area sources. Further, oil and gas 

production facilities are typically not sited in urban areas. 

To the extent that the commenter is requesting EPA to list 

area source oil and gas production wells, such a request is 

outside the scope of this action. See CAA section 112(n)(4)(B) 

(specifying certain requirements for listing “oil and gas 

production wells (with its associated equipment)” as an area 

source category). 

B. Major Comments Concerning the Risk Review

 Comment: One commenter states that the EPA’s analysis for 

40 CFR part 63, subpart HH revealed two facilities (Hawkins Gas 

Plant, Hawkins, Texas, and Kathleen Tharp 2, Huffman, Texas) 

with a cancer MIR greater than 100-in-1 million based on MACT 

28 Even if the commenter were to identify an unregulated emission point 

under the NESHAP, it can always petition the agency to revise the 1999

MACT standards. 

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allowable emissions. The commenter notes that since the EPA 

determined that these facilities had a cancer MIR greater than 

100-in-1 million based on MACT allowable emissions, the EPA 

determined that the risks are unacceptable for the Oil and 

Natural Gas Production MACT source category and additional 

regulation was needed. However, the commenter believes these 

results are entirely incorrect due to fundamental errors in the 

EPA’s calculations of MACT allowable risk for these two 

facilities. In addition, even if the analysis had been correct, 

the commenter states there are significant issues associated 

with the data for both of these facilities, which the commenter 

discusses in detail, that the commenter believes are sufficient 

to invalidate the results and the EPA’s conclusion that risks 

from the Oil and Natural Gas Production source category are 

unacceptable. 

Response: We have reviewed our risk results for the Oil and 

Natural Gas Production source category and agree with the 

commenter that a number of errors were made in our analysis, 

including those noted by the commenter. As explained in VII.A.2 

of this preamble, we have revised the risk assessment for this 

major source category to correct certain mistakes made in the 

analysis supporting the proposed rule. 

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Based on our revised risk assessment, in which we evaluated 

the risks that remain after promulgation of the original MACT 

standards, as well as the MACT standards for small glycol 

dehydrators established in this final rule, we have determined 

the risks for the Oil and Natural Gas Production major source 

category are acceptable and that the MACT standards (including 

those promulgated here for small glycol dehydrators) provide an 

ample margin of safety. Further, we are retaining the 0.9 Mg/yr 

benzene compliance alternative, which we had proposed to remove 

based on our incorrect conclusion that this alternative was 

driving the risk for this major source category. 

Comment: One commenter states that the EPA bases the 

decision to eliminate the 0.9 Mg/yr benzene emission limitation 

for 40 CFR part 63, subpart HHH on two basic factors: (1) It 

would reduce the cancer MIR from 90-in-1 million to 20-in-1 

million, and (2) the cost effectiveness to comply with this 

option is reasonable. The commenter states that both of these 

conclusions are erroneous. 

First, the commenter states that removal of 0.9 Mg/yr 

benzene alternative does not reduce risk. The commenter states 

that the EPA’s own technical analysis indicates that removal of 

the 0.9 Mg/yr benzene alternative would have no effect on the 

MIR. 

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Secondly, the commenter states that the EPA’s cost analysis 

is severely flawed. The commenter also states that the EPA noted 

at proposal, that the cost-effectiveness associated with 

removing the 0.9 Mg/yr benzene compliance alternative for 

natural gas transmission and storage facilities was reasonable. 

However, the commenter explained that the cost estimates used by 

the EPA in the ample margin of safety determination are 

inadequate. According to the commenter, the EPA did not conduct 

any analysis using actual data. Rather, the commenter notes that 

the EPA used costs estimated for small dehydrators and made 

general assumptions to estimate an upper-end cost effectiveness 

for removing the 0.9 Mg/yr benzene alternative limit for large 

dehydrators at natural gas transmission and storage facilities. 

The commenter believes that, in general, the emission reductions 

for dehydrators forced to switch from the 0.9 Mg/yr benzene 

alternative to 95-percent control would be considerably less 

than those achieved by small dehydrators. The commenter further 

notes that the cost-effectiveness calculated for small 

dehydrators is based on a 95-percent reduction from an 

uncontrolled baseline level. According to the commenter, if a 

large dehydrator has installed controls to meet the 0.9 Mg/yr 

alternative benzene limitation, the cost effectiveness must be 

based on the incremental reduction between the existing controls 

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and 95 percent. The commenter states that the EPA has provided 

no evidence that these incremental reductions would be greater 

than or equal to the 95-percent reductions that would be 

achieved for smaller dehydrators. In conclusion, the commenter 

states that the rationale used by the EPA in the preamble to 

support the removal of the 0.9 Mg/yr compliance alternative for 

dehydrators at natural gas transmission and storage facilities 

under section 112(f)(2) of the CAA is not supported by any of 

the background technical documentation and analyses. The 

commenter believes that the EPA has no basis under any other CAA 

authority for this action. 

Response: In response to comments, we re-examined our risk 

assessment for the Natural Gas Transmission and Storage source 

category and discovered a number of errors, which we have 

discussed in more detail in section VII.B.2 of this preamble. As 

explained in that section, we have revised the risk assessment 

for this major source category to correct the mistakes. Based on 

our revised risk assessment, in which we evaluated the risks 

that remain after promulgation of the original MACT standards, 

as well as the MACT standards for small glycol dehydrators in 

this final rule, we have determined that the risks for the Oil 

and Gas Transmission and Storage major source category are 

acceptable and that the MACT standards (including those 

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promulgated here) provide an ample margin of safety. Further, we 

are retaining the 0.9 Mg/yr benzene compliance alternative, 

which we had proposed to remove based on our incorrect 

conclusion that it was driving the risk for this major source 

category. We agree with the commenter that removal of the 0.9 

Mg/yr benzene compliance alternative does not reduce risks for 

this major source category. Because we are retaining this 

compliance alternative, we need not address the comment on the 

cost effectiveness of removing this alternative. 

C. Major Comments Concerning the Technology Review

 Comment: One commenter states that, in conducting an 8-year 

review, the EPA must “look back” at the earlier standard and 

ascertain whether: (1) The standard was adopted using procedures 

that comply with the law as it has come to be interpreted by the 

courts; (2) the EPA had sufficiently accurate and comprehensive 

data at the time of the initial standard setting respecting the 

emissions profile of the category and properly identified the 

best performing unit(s); and (3) the EPA had properly used the 

available data. 

The commenter states the EPA then must “look around” using 

currently available data and determine whether: (1) The 

emissions profile of the industry has changed in a way that 

would substantially affect the MACT floor calculations (the 

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commenter adds that this includes consideration of any increase 

in the number of good performing units available for use in the 

existing source MACT floor calculation and in the performance of 

the best performing unit); (2) data gaps or uncertainties that 

affected the earlier decision have been resolved in the interim 

or can be resolved using new information available to the 

agency; (3) costs or other factors have changed in a way that 

would substantially affect the “beyond-the-floor” determination; 

(4) the use of improved practices, processes or technologies 

(including improvements in the performance of existing 

technologies) has become more prevalent than at the time of the 

initial standard setting; or (5) whether newer regulatory 

requirements, work practices or emission limitations (including 

state and local jurisdiction air pollution standards and federal 

enforcement actions), which are more stringent than the existing 

CAA section 112(d) standard, have shown the achievement or 

achievability of greater emission reductions than the existing 

standard requires. 

Response: As explained in the preamble to the proposed 

rule, our technology review focused on the identification and 

evaluation of “developments in practices, processes, and control 

technologies” since the promulgation of the MACT standards for 

the two oil and gas source categories at issue here. We first 

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reviewed the available information. In this regard, we reviewed 

a variety of sources of data, including data obtained in 

subsequent air toxics rules to see if any practices, processes 

and control technologies considered in these actions could be 

applied to emission sources in the source categories at issue 

here. We also consulted the EPA’s Reasonably Available Control 

Technology (RACT)/Best Available Control Technology 

(BACT)/Lowest Achievable Emission Rate (LAER) Clearinghouse 

(RBLC) 

and the Natural Gas STAR program. At proposal, we explained that 

we consider any of the following to be a “development”: 

- Any add-on control technology or other equipment that was 

not identified and considered during MACT development; 

- Any improvements in add-on control technology or other 

equipment (that was identified and considered during MACT 

development) that could result in significant additional 

emission reduction; 

- Any work practice or operational procedure that was not 

identified and considered during MACT development; and 

- Any process change or pollution prevention alternative that 

could be broadly applied that was not identified and 

considered during MACT development. 

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The commenter views CAA section 112(d)(6) differently. It 

appears to argue that CAA section 112(d)(6) requires that the 

EPA recalculate the MACT based on current data and technology. 

The same argument was posed to the District of Columbia Circuit, 

and the Court “[did] not think that the words ‘review, and 

revise as necessary’ can be construed reasonably as imposing any 

such obligation.” NRDC v. EPA, 529 F.3d 1077, 1084 (D.C. Cir. 

2008). Thus, contrary to the commenter’s assertion, the EPA is 

not required pursuant to CAA section 112(d)(6) to re-calculate 

the floors it set in 1999. 

To the extent the commenter is arguing that CAA section 

112(d)(6) mandates that the EPA correct any deficiency in an 

underlying MACT standard when it conducts the “technology 

review” under that section, we disagree. We believe that CAA 

section 112 does not expressly address this issue, and the EPA 

has discretion in determining how to address a purported flaw in 

a promulgated standard. CAA section 112(d)(6) provides that the 

agency must review and revise “as necessary.” The “as necessary” 

language must be read in the context of the provision, which 

focuses on the review of developments that have occurred since 

the time of the original promulgation of the MACT standard and 

thus should not be read as a mandate to correct flaws that 

existed at the time of the original promulgation. 

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In several recent rulemakings, we have chosen to fix 

underlying defects in existing MACT standards under CAA sections 

112(d)(2) and (3), the provisions that directly govern the 

initial promulgation of MACT standards (see National Emission 

Standards for Hazardous Air Pollutants From Petroleum 

Refineries, October 28, 2009, 74 FR 55670; and National Emission 

Standards for Hazardous Air Pollutants: Group I Polymers and 

Resins; Marine Tank Vessel Loading Operations; Pharmaceuticals 

Production; and the Printing and Publishing Industry, April 21, 

2011, 76 FR 22566). We believe that our approach is reasonable 

because using those provisions ensures that the process and 

considerations are those associated with initially establishing 

a MACT standard, and it is reasonable to make corrections 

following the process that would have been followed if we had 

not made an error at the time of the original promulgation. As 

explained elsewhere, we are not finalizing MACT standards for 

the subcategory of storage vessels without the PFE, which were 

unregulated in the 1999 rule, because after evaluating the 

available data and comments received, we believe that we need 

additional data in order to set an emission standard for these 

vessels. We are, however, finalizing MACT standards under CAA 

sections 112(d)(2) and (3) for the subcategory of small glycol 

dehydration units. 

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With regard to our CAA section 112(d)(6) review, we found 

no significant developments in practices, processes and control 

technologies for reducing emissions from large glycol 

dehydrators and storage vessels with PFE.29 Accordingly, we are 

not revising these standards under CAA section 112(d)(6). 

The EPA also conducted a technology review evaluating 

various options for controlling HAP emissions from equipment 

leaks. As described in the proposed rule (76 FR 52784), we 

evaluated advancements in controlling this emissions source 

since the original standards were promulgated, including the 

emission reduction potential and associated cost-effectiveness 

of these advancements. As a result of our review, we revised 

the leak definition for valves at natural gas processing plants 

to 500 ppm, thus, requiring the application of the LDAR 

requirement at this lower detection level. As discussed above, 

the commenter appears to be arguing that the EPA must redo the 

MACT floor and beyond-the-floor analysis under CAA sections 

112(d)(2) and (3) within its CAA section 112(d)(6) technology 

review, which we disagree. 

Comment: One commenter states that the EPA’s technology 

review for storage vessel control technologies is limited and 

makes incorrect assumptions. The commenter contends that without 

29 See footnote 25. 

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further support, the public cannot understand and the EPA cannot 

justify its proposed decision; therefore, the EPA’s proposal is 

arbitrary and capricious. The commenter adds that the EPA must 

conduct an updated beyond-the-floor analysis for storage 

vessels, by determining the “maximum degree of reduction in 

emissions” that is achievable, as required under CAA section 

112(d)(2). The commenter states that the proposed rule fails to 

provide any discussion of a beyond-the-floor determination for 

storage vessels. 

One commenter states that the EPA must examine advances in 

vapor recovery unit technology and reconsider floating roof 

technology for tanks containing liquids that do not have the 

PFE. The commenter contends that the EPA improperly rejected 

technology advances and developments in pollution prevention 

systems found in its own RBLC database and employed by its own 

Natural Gas STAR partners. Specifically, according to the 

commenter, the EPA failed to evaluate the performance achieved 

by systems that use thermal or catalytic oxidizers, either alone 

or in combination with condensers. According to the commenter, 

the EPA’s RBLC review identified a BACT determination for 

dehydrator efficiency of 98 percent. The commenter also urges 

the EPA to evaluate the use of combustion devices and vapor 

recovery units that capture vent steam from the tank and turn it 

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into a saleable product by recompressing the hydrocarbon vapors. 

The commenter contends that the EPA rejects technology advances 

by asserting that those technologies were considered in the 1999 

rulemaking, but fails to provide support for its decision in 

either the record of the 1999 rulemaking or the current record. 

The commenter contends that the EPA must provide a basis for its 

decisions and conclusions. 

Response: For the reasons discussed in the prior response, 

the EPA disagrees with the commenter’s assertion that it must 

re-do the MACT floor calculations, including the beyond-thefloor determination, for the standards that the agency set in 

1999. As to the technologies identified by the commenter, they 

were in existence and considered by the EPA at the time the EPA 

promulgated the original MACT standards for storage vessels.3031 

In addition, we are not finalizing control requirements for 

storage vessels without the PFE, as described in section VII.A 

of this preamble. The record does not support the assertion that 

the technologies identified by the commenter have advanced in 

terms of HAP emission reduction or have become significantly 

more cost effective. As explained in the preamble to the 

proposed rule (76 FR 52785), we examined technologies that were 

similar to the cover and route emissions to a control device 

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

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that the MACT floor requires and, thus, would not result in 

reductions beyond the existing MACT requirements. Further, 

evaluation of technologies in the RBLC did not produce any 

applicable practices, processes or control technologies that 

were not considered during the original MACT for storage vessels 

with flash emissions.32 

D. Major Comments Concerning Notification, Recordkeeping and 

Reporting Requirements 

1. Annual Reports

 Comment: One commenter requested that the EPA add a selfcertification requirement to the annual report similar to that 

used in the title V program. The commenter recommended that the 

final rule require the annual report to include a statement 

signed by a senior official of the facility attesting to the 

truth, accuracy and completeness of the report. 

The commenter also requested that the EPA require that the 

annual reports be submitted electronically to facilitate making 

the reports publicly available. The commenter suggested using 

social media outlets, smart phone applications and other 

electronic means to make the annual reports readily available. 

Response: The EPA agrees that self-certification is an 

important mechanism for assuring the public that the information 

32 See footnote 25. 

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submitted by each facility is accurate. In addition, the title V 

program has successfully employed self-certification for since 

its inception. Therefore, we are requiring self-certification, 

based on requirements in the title V program, in the final rule. 

While we agree that having annual reports readily available 

to the public is a desirable goal, we did not identify any 

reporting programs or electronic databases that may be used for 

this purpose without significant modification. Therefore, we are 

not requiring annual reports to be submitted electronically, but 

we will continue to evaluate this option in the future. 

2. Electronic Reporting of Emissions Data 

Several commenters raised similar issues regarding 

reporting of emissions data under the NESHAP as under the NSPS, 

described supra, and our responses there apply equally here. 

Please see comments and responses in section IX.F.3 of this 

preamble. 

XI. What are the cost, environmental and economic impacts of the 

final NESHAP and NSPS amendments? 

A. What are the air impacts? 

For the oil and natural gas sector NESHAP and NSPS, we 

estimated the emission reductions that will occur due to the 

implementation of the final emission limits. The EPA estimated 

emission reductions based on the control technologies selected 

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by the engineering analysis. These emission reductions 

associated with the final amendments to 40 CFR part 63, subpart 

HH and 40 CFR part 63, subpart HHH are based on the estimated 

population in 2008. Under the finalized limits for glycol 

dehydration units, we have estimated that the HAP emissions 

reductions will be 670 tons for existing units subject to the 

final emissions limits. 

For the NSPS, we estimated the emission reductions that 

will occur due to the implementation of the final emission 

limits. The EPA estimated emission reductions based on the 

control technologies selected by the engineering analysis. These 

emission reductions are based on the estimated population in 

2015. 

The primary baseline used for the impacts analysis of our 

NSPS for completions of hydraulically fractured natural gas 

wells takes into account REC conducted pursuant to state 

regulations covering these operations and estimates of REC 

performed voluntarily. To account for REC performed in regulated 

states, the EPA subsumed emissions reductions and compliance 

costs in states where these completion-related emissions are 

already controlled into the baseline. Additionally, based on 

public comments and reports to the EPA's Natural Gas STAR 

program, the EPA recognizes that some producers conduct well 

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completions using REC techniques voluntarily for economic and/or 

environmental objectives as a normal part of business. To 

account for emissions reductions and costs arising from 

voluntary implementation of pollution controls, the EPA used 

information on total emission reductions reported to the EPA by 

partners of the EPA Natural Gas STAR. This estimate of this 

voluntary REC activity in the absence of regulation is also 

included in the baseline.33 More detailed discussion on the 

derivation of the baseline is presented in a technical 

memorandum in the docket, as well as in the Regulatory Impact 

Analysis (RIA). 

Additionally, in the RIA, we provide summary-level 

estimates of emissions reductions and engineering compliance 

costs for a case where no voluntary REC are assumed to occur. 

This alternative case is presented in order to show impacts if 

conditions were such that REC were no longer performed on a 

voluntary basis, but, rather, were compelled by the regulation, 

and serves, in part, to capture the inherent uncertainty in 

33 Voluntary short-term actions (such as REC) are challenging to capture

accurately in a prospective analysis, as such, reductions are not guaranteed

to continue. However, Natural Gas STAR represents a nearly 20-year voluntary

initiative with participation from 124 natural gas companies operating in the

United States, including 28 producers, over a wide historical range of

natural gas prices. This unique program and dataset, the significant impact

of voluntary REC on the projected cost and emissions reductions (due to

significant REC activity), and the fact that REC can actually increase

natural gas recovered from natural gas wells (offering a clear incentive to

continue the practice), led the agency to conclude that it was appropriate to

estimate these particular voluntary actions in the baseline for this rule. 

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projecting voluntary activity into the future. As such, this 

alternative case establishes the full universe of emissions 

reductions that are guaranteed by this NSPS (those that are 

required to occur under the rule, including those that would 

likely occur voluntarily). While the primary baseline may better 

represent actual costs (and emissions reductions) beyond those 

already expected under business as usual, the alternative case 

better captures the full amount of emissions reductions where 

the NSPS acts as a backstop to ensure that emission reduction 

practices occur (practices covered by this rule). 

Under the final NSPS, we have estimated that the emissions 

reductions to be about 190,000 tons VOC affected facilities 

subject to the NSPS. The NSPS is also expected to concurrently 

reduce 1.0 million tons methane and 11,000 tons HAP. We estimate 

that direct reductions in HAP, methane and VOC for the final 

rules combined total about 12,000 tons, 1.0 million tons and 

190,000 tons, respectively. If voluntary action is not deducted 

from the NSPS baseline, the emissions reductions achieved by the 

final NSPS in HAP, methane and VOC are estimated at about 19,000 

tons, 1.7 million tons and 290,000 tons, respectively. 

The EPA received several comments regarding the emission 

factor selected to calculate whole gas emissions (and the 

associated VOC emissions) from hydraulically fractured well 

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completions. Comments focused on the data behind the emission 

factor, what the emission factor is intended to represent and 

the procedures used to develop the emission factor from the 

selected data sets. We reviewed all information received and 

have decided to retain the data set and the analysis conducted 

to develop the emission factor of 9,000 thousand cubic feet 

(Mcf) per completion. More detailed discussion is presented in a 

technical memorandum on this subject in the docket. 

B. What are the energy impacts? 

Energy impacts in this section are those energy 

requirements associated with the operation of emission control 

devices. Potential impacts on the national energy economy from 

the rule are discussed in the economic impacts section. There 

would be little national energy demand increase from the 

operation of any of the environmental controls analyzed under 

the final NESHAP amendments and final NSPS. 

The final NESHAP amendments and final NSPS encourage the 

use of emission controls that recover hydrocarbon products, such 

as methane and condensate that can be used on-site as fuel or 

reprocessed within the production process for sale. We estimated 

that the final standards will result in net annual costs savings 

of about $11 million (in 2008 dollars) due to the recovery of 

salable natural gas and condensate. Thus, the final standards 

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have a positive impact associated with the recovery of nonrenewable energy resources. 

C. What are the cost impacts? 

The estimated total capital cost to comply with the final 

amendments to 40 CFR part 63, subpart HH for major sources in 

the Oil and Natural Gas Production source category is 

approximately $2.6 million. The total capital cost for the final 

amendments to 40 CFR part 63, subpart HHH for major sources in 

the Natural Gas Transmission and Storage source category is 

estimated to be approximately $140,000. All costs are in 2008 

dollars. 

The total estimated net annual cost to industry to comply 

with the final amendments to 40 CFR part 63, subpart HH for 

major sources in the Oil and Natural Gas Production source 

category is approximately $3.3 million. The total net annual 

cost for final amendments to 40 CFR part 63, subpart HHH for 

major sources in the Natural Gas Transmission and Storage source 

category is estimated to be approximately $180,000. These 

estimated annual costs include: (1) The cost of capital, (2) 

operating and maintenance costs, (3) the cost of monitoring, 

inspection, recordkeeping and reporting (MIRR) and (4) any 

associated product recovery credits. All costs are in 2008 

dollars. 

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The estimated total capital cost to comply with the final 

NSPS is approximately $25 million in 2008 dollars. The total 

estimated net annual cost to industry to comply with the final 

NSPS is estimated to be approximately $170 million in 2008 

dollars. This annual cost estimate includes: (1) The cost of 

capital, (2) operating and maintenance costs and (3) the cost of 

MIRR. This estimated annual cost does not take into account any 

producer revenues associated with the recovery of salable 

natural gas and hydrocarbon condensates. 

When revenues from additional product recovery are 

considered, the final NSPS is estimated to result in a net 

annual engineering cost savings overall. When including the 

additional natural gas recovery in the engineering cost 

analysis, we assume that producers are paid $4/Mcf for the 

recovered gas at the wellhead. The engineering analysis cost 

analysis assumes the value of recovered condensate is $70 per 

barrel. Based on the engineering analysis, about 43 million Mcf 

(43 billion cubic feet) of natural gas and 160,000 barrels of 

condensate are estimated to be recovered by control requirements 

in 2015. Using the price assumptions, the estimated revenues 

from natural gas and condensate recovery are approximately $180 

million in 2008 dollars. 

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Using the engineering cost estimates, estimated natural gas 

product recovery and natural gas product price assumptions, the 

net annual engineering cost savings is estimated for the final 

NSPS to be about $15 million. Totals may not sum due to 

independent rounding. 

If voluntary action is not deducted from the baseline, 

capital costs for the NSPS are estimated at $25 million and 

annualized costs without revenues from product recovery for the 

NSPS are estimated at $330 million. In this scenario, given the 

assumptions about product prices, estimated revenues from 

product recovery are $350 million, yielding an estimated cost of 

savings of about $22 million. 

As the price assumption is very influential on estimated 

annualized engineering costs, we performed a simple sensitivity 

analysis of the influence of the assumed wellhead price paid to 

natural gas producers on the overall engineering annualized 

costs estimate of the final NSPS. At $4.22/Mcf, the price 

forecast reported in the 2011 Annual Energy Outlook in 2008 

dollars, the annualized cost savings for the final NSPS are 

estimated at about $24 million. As indicated by this difference, 

the EPA has chosen a relatively conservative assumption (leading 

to an estimate of few savings and higher net costs) for the 

engineering costs analysis. The natural gas price at which the 

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final NSPS breaks-even from an estimated engineering costs 

perspective is around $3.66/Mcf. A $1/Mcf change in the wellhead 

natural gas price leads to a $43 million change in the 

annualized engineering costs of the final NSPS. Consequently, 

annualized engineering costs estimates would increase to about 

$29 million under a $3/Mcf price or decrease to about -$58 

million under a $5/Mcf price. For further details on this 

sensitivity analysis, please refer the RIA for this rulemaking 

located in the docket. 

D. What are the economic impacts? 

The analysis of energy system impacts EPA performed using 

the United States Department of Energy’s (DOE) National Energy 

Modeling System (NEMS) shows that domestic natural gas 

production is not likely to change in 2015 as a result of the 

final rules, the year used in the RIA to analyze impacts. 

Average natural gas prices are also not estimated to change in 

response to the final rules. Domestic crude oil production is 

not expected to change, while average crude oil prices are 

estimated to decrease slightly (about $0.01/barrel or about 0.01 

percent at the wellhead for onshore production in the lower 48 

states). All prices are in 2008 dollars. The NEMS-based analysis 

estimates in the year of analysis, 2015, that net imports of 

natural gas and crude oil will not change. 

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E. What are the benefits of this final rule? 

The final Oil and Natural Gas NSPS and NESHAP amendments 

are expected to result in significant reductions in existing 

emissions and prevent new emissions from expansions of the 

industry. These final rules combined are anticipated to reduce 

12,000 tons of HAP, 190,000 tons of VOC (a precursor to both PM 

(2.5 microns and less) (PM2.5) and ozone formation) and 1.0 

million tons of methane (a GHG and a precursor to global ozone 

formation). These pollutants are associated with substantial 

health effects, welfare effects and climate effects. 

With the data available, we are not able to provide 

credible health benefit estimates for the reduction in exposure 

to HAP, ozone and PM2.5 for these rules, due to the differences 

in the locations of oil and natural gas emission points relative 

to existing information and the highly localized nature of air 

quality responses associated with HAP and VOC reductions. This 

is not to imply that there are no benefits of the rules; rather, 

it is a reflection of the difficulties in modeling the direct 

and indirect impacts of the reductions in emissions for this 

industrial sector with the data currently available.34 In 

34 Previous studies have estimated the monetized benefits-per-ton of reducing 

VOC emissions associated with the effect that those emissions have on ambient 

PM2.5 levels and the health effects associated with PM2.5 exposure (Fann,

Fulcher, and Hubbell, 2009). While these ranges of benefit-per-ton estimates 

provide useful context for the break-even analysis, the geographic 

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Page 243 of 588 

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 PM2.5 in the RIA for 

this rule. These qualitative effects are briefly summarized 

below, but for more detailed information, please refer to the 

RIA, which is available in the docket. One of the HAP of concern 

from the oil and natural gas sector is benzene, which is a known 

human carcinogen. VOC emissions are precursors to both PM2.5 and 

ozone formation. As documented in 

previous analyses (U.S. EPA, 200635 and U.S. EPA, 201036), 

exposure to PM2.5 and ozone is associated with significant public 

distribution of VOC emissions from the oil and gas sector are not consistent

with emissions modeled in Fann, Fulcher, and Hubbell (2009). In addition, the

benefit-per-ton estimates for VOC emission reductions in that study are

derived from total VOC emissions across all sectors. Coupled with the larger

uncertainties about the relationship between VOC emissions and PM2.5 and the 

highly localized nature of air quality responses associated with HAP and VOC

reductions, these factors lead us to conclude that the available VOC benefitper-ton estimates are not appropriate to calculate monetized benefits of

these rules, even as a bounding exercise. 

35 U.S. EPA. RIA. National Ambient Air Quality Standards for Particulate

Matter, Chapter 5. Office of Air Quality Planning and Standards, Research

Triangle Park, NC. October 2006. Available on the Internet at

<http://www.epa.gov/ttn/ecas/regdata/RIAs/Chapter%205--Benefits.pdf>. 

36 U.S. EPA. RIA. National Ambient Air Quality Standards for Ozone. Office of 

Air Quality Planning and Standards, Research Triangle Park, NC. January 2010. 

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health effects. PM2.5 is associated with health effects, 

including premature mortality for adults and infants, 

cardiovascular morbidity such as heart attacks, and respiratory 

morbidity such as asthma attacks, acute and chronic bronchitis, 

hospital admissions and emergency room visits, work loss days, 

restricted activity days and respiratory symptoms, as well as 

visibility impairment.37 Ozone is associated with health effects, 

including hospital and emergency department visits, school loss 

days and premature mortality, as well as injury to vegetation 

and climate effects.38 

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 

Available on the Internet at <http://www.epa.gov/ttn/ecas/regdata/RIAs/s1­

supplemental_analysis_full.pdf>. 

37 U.S. EPA. Integrated Science Assessment for Particulate Matter (Final

Report). EPA-600-R-08-139F. National Center for Environmental Assessment—RTP 

Division. December 2009. Available at 

<http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=216546>. 

38 U.S. EPA. Air Quality Criteria for Ozone and Related Photochemical Oxidants

(Final). EPA/600/R-05/004aF-cF. Washington, DC: U.S. EPA. February 2006.

Available on the Internet at 

http://cfpub.epa.gov/ncea/CFM/recordisplay.cfm?deid=149923. 

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change. Methane reacts in the atmosphere to form ozone and ozone 

also impacts global temperatures. According to the 

Intergovernmental Panel on Climate Change (IPCC) 4th Assessment 

Report (2007), methane is the second leading long-lived climate 

forcer after CO2 globally. Total methane emissions from the oil 

and gas industry represent about 40 percent of the total 

methane emissions from all sources and account for about 5 

percent of all CO2e emissions in the United States, with natural 

gas systems being the single largest contributor to United 

States anthropogenic methane emissions.39 Methane, in addition to 

other GHG emissions, contributes to warming of the atmosphere, 

which, over time, leads to increased air and ocean temperatures, 

changes in precipitation patterns, melting and thawing of global 

glaciers and ice, increasingly severe weather events, such as 

hurricanes of greater intensity and sea level rise, among other 

impacts. 

This rulemaking requires emission control technologies and 

regulatory alternatives that will significantly decrease HAP and 

VOC emissions from the oil and natural gas sector in the United 

States. As a co-benefit, the emission control measures the 

industry will use to reduce HAP and VOC emissions will also 

39 U.S. EPA (2011), 2011 U.S. Greenhouse Gas Inventory Report Executive 

Summary available on the internet at

http://epa.gov/climatechange/emissions/downloads11/US-GHG-Inventory-2011­

Executive-Summary.pdf, accessed 02/13/12. 

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decrease methane emissions. The NESHAP Amendments and the NSPS 

combined are expected to reduce methane emissions annually by 

about 1.0 million short tons or about 19 million metric tons 

CO2e. After considering the secondary impacts of this rule as 

previously discussed, such as increased CO2 emissions from well 

completion combustion and decreased CO2e emissions because of 

fuel-switching by consumers, the methane reductions become about 

18 million metric tons CO2e. The methane reductions represent 

about 7 percent of the baseline methane emissions for this 

sector reported in the EPA’s U.S. Greenhouse Gas Inventory 

Report for 2009 (251.55 million metric tons CO2e when petroleum 

refineries and petroleum transportation are excluded because 

these sources are not examined in this proposal). However, it is 

important to note that the emission reductions are based upon 

predicted activities in 2015; the EPA did not forecast sectorlevel emissions in 2015 for this rulemaking. These emission 

reductions equate to the climate benefits of taking 

approximately 4 million typical passenger cars off the road or 

eliminating electricity use from about 2 million typical homes 

each year.40 

40 U.S. EPA. Greenhouse Gas Equivalency Calculator available at: 

http://www.epa.gov/cleanenergy/energy-resources/calculator.html, accessed 

04/09/12. 

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The EPA recognizes that the methane reductions from this 

rule will provide for significant economic climate benefits to 

society just described. However, the 2009-2010 Interagency 

Social Cost of Carbon Work Group did not produce directly 

modeled estimates of the social cost of methane. In the absence 

of direct model estimates from the interagency analysis, the EPA 

has used a “global warming potential (GWP) approach” to estimate 

the dollar value of this rule’s methane co-benefits. 

Specifically, the EPA converted methane to CO2 equivalents using 

the GWP of methane, then multiplied these CO2 equivalent emission 

reductions by the social cost of carbon developed by the 

Interagency Social Cost of Carbon Work Group. 

The social cost of carbon is an estimate of the net present 

value of the flow of monetized damages from a 1-metric ton 

increase in CO2 emissions in a given year (or from the 

alternative perspective, the benefit to society of reducing CO2 

emissions by 1 ton). For more information about the social cost 

of carbon, see the Support Document: Social Cost of Carbon for 

Regulatory Impact Analysis Under Executive Order 12866.41 

Applying this approach to the methane reductions estimated for 

the NESHAP Amendments and NSPS, the 2015 climate co-benefits 

41 Interagency Working Group on Social Cost of Carbon (IWGSC). 2010.

Technical Support Document: Social Cost of Carbon for Regulatory

Impact Analysis Under Executive Order 12866. Docket ID EPA-HQ-OAR2009-0472-114577. http://www.epa.gov/otaq/climate/regulations/scctsd.pdf, accessed 02/12/12. 

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vary by discount rate and range from about $100 million to 

approximately $1.3 billion; the mean social cost of carbon at 

the 3-percent discount rate results in an estimate of about $440 

million in 2015.42 

These co-benefits equate to a range of approximately $110 

to $1,400 per short ton of methane reduced, depending upon the 

discount rate assumed with a per ton estimate of $480 at the 3­

percent discount rate. These social cost of methane benefit 

estimates are not the same as would be derived from direct 

computations (using the integrated assessment models employed to 

develop the Interagency Social Cost of Carbon estimates) for a 

variety of reasons, including the shorter atmospheric lifetime 

of methane relative to CO2 (about 12 years compared to CO2 whose 

concentrations in the atmosphere decay on timescales of decades 

to millennia). The climate impacts also differ between the 

pollutants for reasons other than the radiative forcing profiles 

and atmospheric lifetimes of these gases. 

Methane is a precursor to ozone and ozone is a short-lived 

climate forcer that contributes to global warming. The use of 

the IPCC Second Assessment Report GWP to approximate co-benefits 

may underestimate the direct radiative forcing benefits of 

42 The ratio of domestic to global benefits of emission reductions

varies with key parameter assumptions. See Interagency Working Group

on Social Cost of Carbon. 2010. Technical Support Document: Social

Cost of Carbon for Regulatory Impact Analysis Under Executive Order

12866. 

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reduced ozone levels and does not capture any secondary climate 

co-benefits involved with ozone-ecosystem interactions. In 

addition, a recent the EPA National Center of Environmental 

Economics working paper suggests that this quick “GWP approach” 

to benefits estimation will likely understate the climate 

benefits of methane reductions in most cases.43 This conclusion 

is reached using the 100-year GWP for methane of 25 as put forth 

in the IPCC Fourth Assessment Report (AR 4), as opposed to the 

lower value of 21 used in this analysis. Using the higher GWP 

estimate of 25 would increase these reported methane climate cobenefit estimates by about 19 percent. Although the IPCC 

Assessment Report (AR4) suggested a GWP of 25 for methane, the 

EPA has used the GWP of 21 from the IPCC Second Assessment 

Report to estimate the methane climate co-benefits for this oil 

and gas rule. The EPA uses the 21 GWP in order to provide 

estimates more consistent with global GHG inventories, which 

currently use GWP from the IPCC Second Assessment Report, and 

with the US GHG Reporting program. See the Regulatory Impact 

Analysis for further details. 

Due to the uncertainties involved with the “GWP approach” 

estimates presented and methane climate co-benefits estimates 

43 Marten and Newbold (2011), Estimating the Social Cost of Non-CO2 GHG

Emissions: Methane and Nitrous Oxide, NCEE Working Paper Series #11­

01. http://yosemite.epa.gov/EE/epa/eed.nsf/WPNumber/2011­

01?OpenDocument. 

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available in the literature, the EPA chooses not to compare 

these co-benefit estimates to the costs of the rule for this 

proposal. Rather, the EPA presents the “GWP approach” climate 

co-benefit estimates as an interim method to produce these 

estimates until the Interagency Social Cost of Carbon Work Group 

develops values for non-CO2 GHG. 

For the final NESHAP amendments, a break-even analysis 

suggests that HAP emissions would need to be valued at $5,200 

per ton for the benefits to exceed the costs if the health, 

ecosystem and climate benefits from the reductions in VOC and 

methane emissions are assumed to be zero. Even though emission 

reductions of VOC and methane are co-benefits for the final 

NESHAP amendments, they are legitimate components of the total 

benefit-cost comparison. If we assume the health benefits from 

HAP emission reductions are zero, the VOC emissions would need 

to be valued at $2,900 per ton or the methane emissions would 

need to be valued at $8,300 per ton for the co-benefits to 

exceed the costs. All estimates are in 2008 dollars. For the 

final NSPS, the revenue from additional product recovery exceeds 

the costs, which renders a break-even analysis unnecessary when 

these revenues are included in the analysis. Based on the 

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methodology from Fann, Fulcher, and Hubbell (2009),44 ranges of 

benefit-per-ton estimates for emissions of VOC indicate that on 

average in the United States, VOC emissions are valued from 

$1,200 to $3,000 per ton as a PM2.5 precursor, but emission 

reductions in specific areas are valued from $280 to $7,000 per 

ton in 2008 dollars. As a result, even if VOC emissions from oil 

and natural gas operations result in monetized benefits that are 

substantially below the national average, there is a reasonable 

chance that the benefits of the rule would exceed the costs, 

especially if we were able to monetize all of the additional 

benefits associated with ozone formation, visibility, HAP and 

methane. 

XII. Statutory and Executive Order Reviews 

A. Executive Order 12866, Regulatory Planning and Review and 

Executive Order 13563, Improving Regulation and Regulatory 

Review 

Under section 3(f)(1) of Executive Order 12866 (58 FR 

51735, October 4, 1993), this action is an “economically 

significant regulatory action” because it is likely to have an 

annual effect on the economy of $100 million or more. 

Accordingly, the EPA submitted this action to the Office of 

44 Fann, N., C.M. Fulcher, B.J. Hubbell. The influence of location, 

source, and emission type in estimates of the human health benefits of

reducing a ton of air pollution. Air Qual Atmos Health (2009) 2:169­

176. 

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Management and Budget (OMB) for review under Executive Order 

12866 and Executive Order 13563 (76 FR 3821, January 21, 2011), 

and any changes made in response to OMB recommendations have 

been documented in the docket for this action. 

In addition, the EPA prepared a Regulatory Impact Analysis 

(RIA) of the potential costs and benefits associated with this 

action. The RIA available in the docket describes in detail the 

empirical basis for the EPA’s assumptions and characterizes the 

various sources of uncertainties affecting the estimates below. 

Table 7 shows the results of the cost and benefits analysis for 

these final rules. 

TABLE 7. SUMMARY OF THE MONETIZED BENEFITS, SOCIAL COSTS AND NET

BENEFITS FOR THE FINAL OIL AND NATURAL GAS NSPS AND NESHAP 

AMENDMENTS IN 2015 (MILLIONS OF 2008$)1 

Final NSPS Final NESHAP 

Amendments 

Final NSPS and 

NESHAP 

Amendments 

Combined 

Total 

Monetized 

Benefits2 

N/A N/A N/A 

Total Costs3 -$15 million $3.5 million -$11 million 

Net Benefits N/A N/A N/A

11,000 tons of 

HAP 

670 tons of HAP 12,000 tons of 

HAP 

Nonmonetized 

Benefits4 

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 

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Health effects of HAP exposure

Health effects of PM2.5 and ozone exposure

Visibility impairment

Vegetation effects

Climate effects 

1 All estimates are for the implementation year (2015).

2 While we expect that these avoided emissions will result in

improvements in air quality and reductions in health effects

associated with HAP, ozone, and particulate matter (PM) as well

as climate effects associated with methane, we have determined

that quantification of those benefits and co-benefits cannot be

accomplished for this rule in a defensible way. This is not to

imply that there are no benefits or co-benefits of the rules;

rather, it is a reflection of the difficulties in modeling the

direct and indirect impacts of the reductions in emissions for

this industrial sector with the data currently available.

3 The engineering compliance costs are annualized using a 7­

percent discount rate. The negative cost for the final NSPS

reflects the inclusion of revenues from additional natural gas

and hydrocarbon condensate recovery that are estimated as a

result of the NSPS. Possible explanations for why there appear

to be negative cost control technologies are discussed in the

engineering costs analysis section in the RIA.

4

 For the NSPS, reduced exposure to HAP and climate effects are

co-benefits. For the NESHAP, reduced VOC emissions, PM2.5 and 

ozone exposure, visibility and vegetation effects and climate

effects are co-benefits. The specific control technologies for

the final NSPS are anticipated to have minor secondary

disbenefits, including an increase of 1.1 million tons of carbon

dioxide (CO2), 550 tons of nitrogen oxides (NOx), 19 tons of PM,

3,000 tons of CO and 1,100 tons of total hydrocarbons (THC), as

well as emission reductions associated with the energy system

impacts. The specific control technologies for the NESHAP are

anticipated to have minor secondary disbenefits, but the EPA was

unable to estimate these secondary disbenefits. The net CO2­

equivalent emission reductions are 18 million metric tons. 

B. Paperwork Reduction Act 

The information collection requirements in this rule have 

been submitted for approval to the Office of Management and 

Budget (OMB) under the Paperwork Reduction Act, 44 U.S.C. 3501, 

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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 

all operators subject to national emission standards. These 

recordkeeping and reporting requirements are specifically 

authorized by CAA section 114 (42 U.S.C. 7414). All information 

submitted to the EPA pursuant to the recordkeeping and reporting 

requirements for which a claim of confidentiality is made is 

safeguarded according to Agency policies set forth in 40 CFR 

part 2, subpart B. This final rule requires maintenance 

inspections of the control devices but would not require any 

notifications or reports beyond those required by the General 

Provisions. The recordkeeping requirements require only the 

specific information needed to determine compliance. 

When a malfunction occurs, sources must report them 

according to the applicable reporting requirements of 40 CFR 

part 63, subpart HH or 40 CFR part 63, subpart HHH. An 

affirmative defense to civil penalties for exceedances of 

emission limits that are caused by malfunctions is available to 

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a source if it can demonstrate that certain criteria and 

requirements are satisfied. The criteria ensure that the 

affirmative defense is available only where the event that 

causes an exceedance of the emission limit meets the narrow 

definition of malfunction in 40 CFR 63.2 (sudden, infrequent, 

not reasonable preventable, and not caused by poor maintenance 

and/or careless operation) and where the source took necessary 

actions to minimize emissions. In addition, the source must meet 

certain notification and reporting requirements. For example, 

the source must prepare a written root cause analysis and submit 

a written report to the Administrator documenting that it has 

met the conditions and requirements for assertion of the 

affirmative defense. 

For this rule, the EPA is adding affirmative defense to the 

estimate of burden in the ICR. To provide the public with an 

estimate of the relative magnitude of the burden associated with 

an assertion of the affirmative defense position adopted by a 

source, the EPA has provided administrative adjustments to this 

ICR that shows what the notification, recordkeeping and 

reporting requirements associated with the assertion of the 

affirmative defense might entail. The EPA’s estimate for the 

required notification, reports, and records, including the root 

cause analysis, associated with a single incident totals 

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approximately totals $3,141 and is based on the time and effort 

required of a source to review relevant data, interview plant 

employees, and document the events surrounding a malfunction 

that has caused an exceedance of an emission limit. The estimate 

also includes time to produce and retain the record and reports 

for submission to the EPA. The EPA provides this illustrative 

estimate of this burden, because these costs are only incurred 

if there has been a violation, and a source chooses to take 

advantage of the affirmative defense. 

The EPA provides this illustrative estimate of this burden 

because these costs are only incurred if there has been a 

violation and a source chooses to take advantage of the 

affirmative defense. Given the variety of circumstances under 

which malfunctions could occur, as well as differences among 

sources’ operation and maintenance practices, we cannot reliably 

predict the severity and frequency of malfunction-related excess 

emissions events for a particular source. It is important to 

note that the 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 

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malfunctions. Of the number of excess emissions events reported 

by source operators, only a small number would be expected to 

result from a malfunction (based on the definition above), and 

only a subset of excess emissions caused by malfunctions would 

result in the source choosing to assert the affirmative defense. 

Thus, we believe the number of instances in which source 

operators might be expected to avail themselves of the 

affirmative defense will be extremely small. 

For this reason, we estimate a total of 39 such occurrences 

for all sources subject to 40 CFR part 63, subpart HH, a total 

of three such occurrences for all sources subject to 40 CFR part 

63, subpart HHH, and a total of 6 such occurrences for all 

sources subject to 40 CFR part 60, subparts KKK and LLL over the 

3-year period covered by this ICR. We expect to gather 

information on such events in the future, and will revise this 

estimate as better information becomes available. 

The annual monitoring, reporting, and recordkeeping burden 

for this collection (averaged over the first 3 years after the 

effective date of the standards) is estimated to be $20.1 

million. This includes 384,866 labor hours per year at a total 

labor cost of $19.5 million per year, and annualized capital 

costs of $0.36 million, and annual operating and maintenance 

costs of $0.20 million. This estimate includes initial and 

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annual performance tests, semiannual excess emission reports, 

developing a monitoring plan, notifications and recordkeeping. 

All burden estimates are in 2008 dollars and represent the most 

cost-effective monitoring approach for affected facilities. 

Burden is defined at 5 CFR 1320.3(b). 

An agency may not conduct or sponsor, and a person is not 

required to respond to, a collection of information unless it 

displays a currently valid OMB control number. The OMB control 

numbers for the EPA's regulations in 40 CFR are listed in 40 CFR 

part 9. When these ICR are approved by OMB, the agency will 

publish a technical amendment to 40 CFR part 9 in the Federal 

Register to display the OMB control numbers for the approved 

information collection requirements contained in the final rule. 

C. Regulatory Flexibility Act 

The Regulatory Flexibility Act generally requires an agency 

to prepare a regulatory flexibility analysis of any rule subject 

to notice and comment rulemaking requirements under the 

Administrative Procedure Act or any other statute, unless the 

agency certifies that the rule will not have a significant 

economic impact on a substantial number of small entities 

(SISNOSE). Small entities include small businesses, small 

organizations, and small governmental jurisdictions. For 

purposes of assessing the impact of this rule on small entities, 

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a small entity is defined as: (1) A small business as defined by 

NAICS codes 211111, 211112, 221210, 486110 and 486210; whose 

parent company has no more than 500 employees (or revenues of 

less than $7 million for firms that transport natural gas via 

pipeline); (2) a small governmental jurisdiction that is a 

government of a city, county, town, school district, or special 

district with a population of less than 50,000; and (3) a small 

organization that is any not-for-profit enterprise which is 

independently owned and operated and is not dominant in its 

field. 

For the final NSPS, the EPA performed an analysis for 

impacts on a sample of expected affected small entities by 

comparing compliance costs to entity revenues. The baseline used 

in this analysis takes into account REC conducted pursuant to 

state regulations covering these operations and estimates of REC 

performed voluntarily. To account for REC performed in regulated 

states, the EPA subsumed emissions reductions and compliance 

costs in states where these completion-related emissions are 

already controlled into the baseline. Additionally, based on 

public comments and reports to the EPA's Natural Gas STAR 

program, the EPA recognizes that some producers conduct well 

completions using REC techniques voluntarily for economic and/or 

environmental objectives as a normal part of business. To 

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account for emissions reductions and costs arising from 

voluntary implementation of pollution controls, the EPA used 

information on total emission reductions reported to the EPA by 

partners of the EPA Natural Gas STAR. This estimate of this 

voluntary REC activity in the absence of regulation is also 

included in the baseline. More detailed discussion on the 

derivation of the baseline is presented in a technical 

memorandum in the docket, as well as in the RIA. 

Based upon the analysis in the RIA, which is in the Docket, 

when revenue from additional natural gas product recovered is 

not included, we estimate that 123 of the 127 small firms 

analyzed (97 percent) are likely to have impacts less than 1 

percent in terms of the ratio of annualized compliance costs to 

revenues. Meanwhile, four firms (3 percent) are likely to have 

impacts greater than 1 percent. Three of these four firms are 

likely to have impacts greater than 3 percent. However, when 

revenue from additional natural gas product recovery is 

included, we estimate that none of the analyzed firms will have 

an impact greater than 1 percent. 

For the final NESHAP amendments, we estimate that 11 of the 

35 firms (31 percent) that own potentially affected facilities 

are small entities. The EPA performed an analysis for impacts on 

all expected affected small entities by comparing compliance 

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costs to entity revenues. Among the small firms, none are likely 

to have impacts greater than 1 percent in terms of the ratio of 

annualized compliance costs to revenues. 

After considering the economic impact of the combined NSPS 

and NESHAP amendments on small entities, I certify this action 

will not have a significant impact on a substantial number of 

small entities (SISNOSE). While both the NSPS and NESHAP 

amendment would individually result in a no SISNOSE finding, the 

EPA performed an additional analysis in order to certify the 

rule in its entirety. This analysis compared compliance costs to 

entity revenues for the total of all the entities affected by 

the NESHAP amendments and the sample of entities analyzed for 

the NSPS. When revenues from additional natural gas product 

sales are not included, 132 of the 136 small firms (97 percent) 

in the sample are likely to have impacts of less than 1 percent 

in terms of the ratio of annualized compliance costs to 

revenues. Meanwhile, four firms (3 percent) are likely to have 

impacts greater than 1 percent. Three of these four firms are 

likely to have impacts greater than 3 percent. When revenues 

from additional natural gas product sales are included, none of 

the 136 small firms (100 percent) are likely to have impacts 

greater than 1 percent. 

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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 wellrelated compliance costs to be significantly mitigated. This 

conclusion is enhanced because the returns to REC activities 

occur without a significant time lag between implementing the 

control and obtaining the recovered product, unlike many control 

options where the emissions reductions accumulate over long 

periods of time; the reduced emission completions occur over a 

short span of time, during which the additional product recovery 

is also accomplished and payments for recovered products are 

settled. 

Although this final rule will not impact a substantial 

number of small entities, the EPA, nonetheless, has tried to 

reduce the impact of this rule on small entities by setting the 

final emissions limits at the MACT floor, the least stringent 

level allowed by law. 

D. Unfunded Mandates Reform Act of 1995 

This final action does not contain a federal mandate under 

the provisions of Title II of the Unfunded Mandates Reform Act 

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of 1995 (UMRA), 2 U.S.C. 1531-1538 for state, local, and tribal 

governments, in the aggregate, or to the private sector. The 

action would not result in expenditures of $100 million or more 

for state, local, and tribal governments, in the aggregate, or 

to the private sector in any 1 year. Thus, this final rule is 

not subject to the requirements of sections 202 or 205 of UMRA. 

This final rule is also not subject to the requirements of 

section 203 of UMRA because it contains no regulatory 

requirements that might significantly or uniquely affect small 

governments because it contains no requirements that apply to 

such governments nor does it impose obligations upon them. 

E. Executive Order 13132: Federalism 

This action does not have federalism implications. It will not 

have substantial direct effects on the states, on the 

relationship between the national government and the states, or 

on the distribution of power and responsibilities among the 

various levels of government, as specified in Executive Order 

13132. These final rules primarily affect private industry, and 

do not impose significant economic costs on state or local 

governments. On the contrary, we believe the modification 

provisions discussed in section IX.A for well completions 

conducted at gas wells constructed on or before August 23, 2011, 

will reduce permitting burden borne by the States. These 

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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 (65 FR 67249, November 

9, 2000) the EPA may not issue a regulation that has tribal 

implications, that imposes substantial direct compliance costs, 

and that is not required by statute, unless the Federal 

government provides the funds necessary to pay the direct 

compliance costs incurred by tribal governments, or the EPA 

consults with tribal officials early in the process of 

developing the proposed regulation and develops a tribal summary 

impact statement. 

The EPA has concluded that this action will not have tribal 

implications because it doesn’t impose a significant cost to the 

tribal government. However, there are significant tribal 

interests because of the growth of the oil and gas production 

industry in Indian country. 

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The EPA initiated a consultation process with tribal 

officials early in the process of developing this regulation to 

permit them to have meaningful and timely input into its 

development. During the consultation process, the EPA conducted 

outreach and information meetings prior to the proposal in 2010. 

The EPA met with the Inter Tribal Environmental Council, which 

include many of the Region VI tribes, The Tribal leadership 

summit in Region X, and Tribal Energy Conference hosted by Ft. 

Belknap, and the National Tribal Forum. 

After the proposal was published, letters were sent to all 

tribal leaders offering to consult on a government-to-government 

basis on the rule. As part of the consultation process and in 

response to these letters, an outreach call was held on October 

12, 2011. Tribes that participated on this call were: Fond du 

Lac Band of Lake Superior Chippewa, Fort Belknap Indian 

Community, Forest County Potawatomi Community, Southern Ute 

Indian Tribe, and Pueblo of Santa Clara. 

In this meeting the tribes were presented the information 

in the proposal. The tribes asked general clarifying questions 

but did not provide specific comments. Comments on the proposal 

were received from an affiliate of the Southern Ute Indian 

Tribe. The commenter expressed concern about the impacts of the 

rule on natural gas and oil production operations on the 

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Southern Ute Indian reservation and requested additional time to 

evaluate the impacts. In response to this and other requests, 

the comment period was extended. More specific comments can be 

found in the docket. 

G. Executive Order 13045: Protection of Children from 

Environmental Health Risks and Safety Risks 

This action is not subject to Executive Order 13045 (62 FR 

19885, April 23, 1997) because the Agency does not believe the 

environmental health risks or safety risks addressed by this 

action present a disproportionate risk to children. This action 

would not relax the control measures on existing regulated 

sources. The EPA’s risk assessments (included in the docket for 

this final rule) demonstrate that the existing regulations are 

associated with an acceptable level of risk and provide an ample 

margin of safety to protect public health. 

H. Executive Order 13211: Actions Concerning Regulations That 

Significantly Affect Energy Supply, Distribution, or Use 

This action is not a “significant energy action” as defined 

in Executive Order 13211 (66 FR 28355, May 22, 2001), because it 

is not likely to have a significant adverse effect on the 

supply, distribution, or use of energy. These final rules will 

result in the addition of control equipment and monitoring 

systems for existing and new sources within the oil and natural 

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gas industry. The final NESHAP amendments are unlikely to have a 

significant adverse effect on the supply, distribution, or use 

of energy. As such, the final NESHAP amendments are not 

“significant energy actions” as defined in Executive Order 

13211, (66 FR 28355, May 22, 2001). The final NSPS is also 

unlikely to have a significant adverse effect on the supply, 

distribution, or use of energy. As such, the final NSPS is not a 

“significant energy action” as defined in Executive Order 13211 

(66 FR 28355, May 22, 2001). 

The basis for these determinations is as follows. Emission 

controls for the NSPS capture VOC emissions that otherwise would 

be vented to the atmosphere. Since methane is co-emitted with 

VOC, a large proportion of the averted methane emissions can be 

directed into natural gas production streams and sold. One 

pollution control requirement of the final NSPS also captures 

saleable condensates. The revenues from additional natural gas 

and condensate recovery are expected to offset the costs of 

implementing the final rules. 

We use the NEMS to estimate the impacts of the combined 

final rules on 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 

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Energy Outlook, a reference publication that provides detailed 

forecasts of the United States energy economy. 

Based on public comments and reports to EPA's Natural Gas 

STAR program, the EPA recognizes that some producers conduct 

well completions using REC techniques, which are required by the 

final NSPS for certain completions of hydraulically fractured 

and refractured natural gas wells, voluntarily based upon 

economic and environmental objectives. The baseline used for the 

energy system impacts analysis takes into account REC conducted 

pursuant to state regulations covering these operations and 

estimates of REC performed voluntarily. To account for REC 

performed in regulated states, the EPA subsumed emissions 

reductions and compliance costs in states where these 

completion-related emissions are already controlled into the 

baseline. Additionally, based on public comments and reports to 

the EPA's Natural Gas STAR program, the EPA recognizes that some 

producers conduct well completions using REC techniques 

voluntarily for economic and/or environmental objectives as a 

normal part of business. To account for emissions reductions and 

costs arising from voluntary implementation of pollution 

controls, the EPA used information on total emission reductions 

reported to the EPA by partners of the EPA Natural Gas STAR. 

This estimate of this voluntary REC activity in the absence of 

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regulation is also included in the baseline. More detailed 

discussion on the derivation of the baseline is presented in a 

technical memorandum in the docket, as well as in the RIA. 

The analysis of energy system impacts for the final NSPS 

under the primary baseline shows that domestic natural gas 

production is not likely to change in 2015, the year used in the 

RIA to analyze impacts. Average natural gas prices are also not 

estimated to change in response to the final rules. Domestic 

crude oil production is not expected to change, while average 

crude oil prices are estimated to decrease slightly (about 

$0.01/barrel or about 0.01 percent at the wellhead for onshore 

production in the lower 48 states). All prices are in 2008 

dollars. The NEMS-based analysis estimates in the year of 

analysis, 2015, that net imports of natural gas and crude oil 

will not change. 

Additionally, the NSPS establishes several performance 

standards that give regulated entities flexibility in 

determining how to best comply with the regulation. In an 

industry that is geographically and economically heterogeneous, 

this flexibility is an important factor in reducing regulatory 

burden. 

For more information on the estimated energy effects, 

please refer to the economic impact analysis for this final 

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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 otherwise 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. 

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 

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appropriate, disproportionately high and adverse human health or 

environmental effects of their programs, policies and activities 

on minority populations and low income populations in the United 

States. 

The EPA has determined that this final rule will not have 

disproportionately high and adverse human health or 

environmental effects on minority or low-income populations 

because it increases the level of environmental protection for 

all affected populations without having any disproportionately 

high and adverse human health or environmental effects on any 

population, including any minority, low-income, or indigenous 

populations. 

To examine the potential for any environmental justice 

issues that might be associated with each source category, we 

evaluated the percentages of various social, demographic, and 

economic groups within the at-risk population living near the 

facilities where these source categories are located and 

compared them to national averages. The development of 

demographic analyses to inform the consideration of 

environmental justice issues in the EPA rulemakings is an 

evolving science. 

The EPA conducted a demographic analysis, focusing on 

populations within 50 km of any facility in each of the source 

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categories that are estimated to have HAP exposures which result 

in cancer risks of 1-in-1 million or greater or non-cancer 

hazard indices of 1 or greater based on estimates of current HAP 

emissions. The results of this analysis are documented in the 

technical report: Risk and Technology Review – Analysis of 

Socio-economic Factors for Populations Living Near Oil & Natural 

Gas Production Facilities, located in the docket for this 

rulemaking. 

As described in the preamble, our risk assessments 

demonstrate that the regulations for the oil and natural gas 

production and natural gas transmission and storage source 

categories, are associated with an acceptable level of risk and 

that the proposed additional requirements will provide an ample 

margin of safety to protect public health. Our analyses also 

show that, for these source categories, there is no potential 

for an adverse environmental effect or human health multipathway effects, and that acute and chronic non-cancer health 

impacts are unlikely. The EPA has determined that, although 

there may be an existing disparity in HAP risks from these 

sources between some demographic groups, no demographic group is 

exposed to an unacceptable level of risk. 

To promote meaningful involvement, the EPA conducted three 

public hearings on the proposal. The hearings were held in 

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Pittsburgh, Pennsylvania, on September 27, 2011, Denver, 

Colorado, on September 28, 2011, and Arlington, Texas, on 

September 29, 2011. A total of 261 people spoke at the three 

hearings and 735 people attended the hearings. The attendees at 

the hearings included private citizens, community-based and 

environmental organizations, industry representatives, 

associations representing industry and local and state 

government officials. 

K. Congressional Review Act 

The Congressional Review Act, 5 U.S.C. 801, et seq., as 

added by the Small Business Regulatory Enforcement Fairness Act 

of 1996, generally provides that before a rule may take effect, 

the agency promulgating the rule must submit a rule report, 

which includes a copy of the rule, to each House of the Congress 

and to the Comptroller General of the United States. The EPA 

will submit a report containing this final rule and other 

required information to the United States Senate, the United 

States House of Representatives, and the Comptroller General of 

the United States prior to publication of the final rule in the 

Federal Register. A major rule cannot take effect until 60 days 

after it is published in the Federal Register. This action is a 

“major rule” as defined by 5 U.S.C. 804(2). The final rules will 

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be effective on [INSERT DATE 60 DAYS AFTER THE DATE OF 

PUBLICATION IN THE FEDERAL REGISTER]. 

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____________________________ 

____________________________ 

Oil and Natural Gas Sector: New Source Performance Standards and 

National Emission Standards for Hazardous Air Pollutants 

Reviews—page Page 275 of 588
 

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. 
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For the reasons set out in the preamble, title 40, chapter

I of the Code of Federal Regulations is amended as follows: 

PART 60—[AMENDED] 

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 

Procedures, 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). 
                                 

                             

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* * * * * 

Subpart KKK—Standards of Performance for Equipment Leaks of

VOC From Onshore Natural Gas Processing Plants for Which

Construction, Reconstruction, or Modification Commenced After

January 20, 1984, and on or Before August 23, 2011 

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 Applicability and designation of affected facility. 

* * * * * 

(b) Any affected facility under paragraph (a) of this 

section that commences construction, reconstruction, or 

modification after January 20, 1984, and on or before August 23, 

2011, is subject to the requirements of this subpart. 

* * * * * 

Subpart LLL—Standards of Performance for SO2 Emissions From 

Onshore Natural Gas Processing for Which Construction,

Reconstruction, or Modification Commenced After January 20,

1984, and on or Before August 23, 2011 

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. 

* * * * * 

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(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—Standards of Performance for Crude Oil and Natural

Gas Production, Transmission and Distribution 

Sec. 

60.5360 

60.5365 

60.5370 

60.5375 

60.5380 

What is the purpose of this subpart?

Am I subject to this subpart?

When must I comply with this subpart?

What standards apply to gas well affected facilities?

What standards apply to centrifugal compressor

affected facilities? 

60.5385 What standards apply to reciprocating compressor

affected facilities? 

60.5390 What standards apply to pneumatic controller affected

facilities? 

60.5395 What standards apply to storage vessel affected

facilities? 

60.5400 

60.5401 

What equipment leak standards apply to affected

facilities at an onshore natural gas processing plant?

What are the exceptions to the equipment leak

standards for affected facilities at onshore natural 

60.5402 

gas processing plants?

What are the alternative emission limitations for 

60.5405 

60.5406 

60.5407 

equipment leaks from onshore natural gas processing

plants?

What standards apply to sweetening units at onshore

natural gas processing plants?

What test methods and procedures must I use for my

sweetening units affected facilities at onshore

natural gas processing plants?

What are the requirements for monitoring of emissions

and operations from my sweetening unit affected

facilities at onshore natural gas processing plants? 

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60.5408 What is an optional procedure for measuring hydrogen

sulfide in acid gas—Tutwiler Procedure?

60.5410 How do I demonstrate initial compliance with the

standards for my gas well affected facility, my

centrifugal compressor affected facility, my

reciprocating compressor affected facility, my

pneumatic controller affected facility, my storage

vessel affected facility, and my equipment leaks and

sweetening unit affected facilities at onshore natural

gas processing plants?

60.5411 What additional requirements must I meet to determine

initial compliance for my closed vent systems routing

emissions from storage vessels or centrifugal

compressor wet seal fluid degassing systems?

60.5412 What additional requirements must I meet for

determining initial compliance with control devices

used to comply with the emission standards for my

storage vessel or centrifugal compressor affected

facility?

60.5413 What are the performance testing procedures for

control devices used to demonstrate compliance at my

storage vessel or centrifugal compressor affected

facility?

60.5415 How do I demonstrate continuous compliance with the

standards for my gas well affected facility, my

centrifugal compressor affected facility, my

stationary reciprocating compressor affected facility,

my pneumatic controller affected facility, my storage

vessel affected facility, and my affected facilities

at onshore natural gas processing plants?

60.5416 What are the initial and continuous cover and closed 

vent system inspection and monitoring requirements for

my storage vessel or centrifugal compressor affected

facility?

60.5417 What are the continuous control device monitoring

requirements for my storage vessel or centrifugal

compressor affected facility?

60.5420 What are my notification, reporting, and recordkeeping

requirements?

60.5421 What are my additional recordkeeping requirements for

my affected facility subject to VOC requirements for

onshore natural gas processing plants?

60.5422 What are my additional reporting requirements for my

affected facility subject to VOC requirements for

onshore natural gas processing plants? 

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60.5423 What additional recordkeeping and reporting

requirements apply to my sweetening unit affected

facilities at onshore natural gas processing plants?

60.5425 What parts of the General Provisions apply to me?

60.5430 What definitions apply to this subpart?

Table 1 to Subpart OOOO of part 60 – Required Minimum Initial SO2
 

Emission Reduction Efficiency (Zi)

Table 2 to Subpart OOOO of part 60 – Required Minimum SO2
 

Emission Reduction Efficiency (Zc)

Table 3 to Subpart OOOO of part 60 – Applicability of General

Provisions to Subpart OOOO 

Subpart OOOO—Standards of Performance for Crude Oil and Natural

Gas Production, Transmission and Distribution 

§60.5360 What is the purpose of this subpart? 

This subpart establishes emission standards and compliance 

schedules for the control of volatile organic compounds (VOC) 

and sulfur dioxide (SO2) emissions from affected facilities that 

commence construction, modification or reconstruction after 

August 23, 2011. 

§60.5365 Am I subject to this subpart? 

You are subject to the applicable provisions of this 

subpart if you are the owner or operator of one or more of the 

onshore affected facilities listed in paragraphs (a) through (g) 

of this section for which you commence construction, 

modification or reconstruction after August 23, 2011. 

(a) Each gas well affected facility, which is a single 

natural gas well. 

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(b) Each centrifugal compressor affected facility, which is 

a single centrifugal compressor using wet seals that is located 

between the wellhead and the point of custody transfer to the 

natural gas transmission and storage segment. 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 

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scfh which commenced construction after August 23, 2011, and is 

located between the wellhead and the point of custody transfer 

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 

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processing plant. Equipment not located at the onshore natural 

gas processing plant site is exempt from the provisions of 

§§60.5400, 60.5401, 60.5402, 60.5421 and 60.5422 of this 

subpart. 

(3) The equipment within a process unit of an affected 

facility located at onshore natural gas processing plants and 

described in paragraph (f) of this section are exempt from this 

subpart if they are subject to and controlled according to 

subparts VVa, GGG or GGGa of this part. 

(g) Sweetening units located at onshore natural gas 

processing plants that process natural gas produced from either 

onshore or offshore wells. 

(1) Each sweetening unit that processes natural gas is an 

affected facility; and 

(2) Each sweetening unit that processes natural gas 

followed by a sulfur recovery unit is an affected facility. 

(3) Facilities that have a design capacity less than 2 long 

tons per day (LT/D) of hydrogen sulfide (H2S) in the acid gas 

(expressed as sulfur) are required to comply with recordkeeping 

and reporting requirements specified in §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. 

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(4) Sweetening facilities producing acid gas that is 

completely reinjected into oil-or-gas-bearing geologic strata or 

that is otherwise not released to the atmosphere are not subject 

to §§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. 

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§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 

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 comply 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 paragraphs (a)(3) and (4) of this section unless 

a more stringent state or local emission control requirement is 

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applicable; optionally, you may comply with the requirements of 

paragraphs (a)(1) through (4) of this section. For each new well 

completion operation with hydraulic fracturing begun on or after 

January 1, 2015, you must comply with the requirements in 

paragraphs (a)(1) through (4) of this section. 

(1) For the duration of flowback, route the recovered 

liquids into one or more storage vessels or re-inject the 

recovered liquids into the well or another well, and route the 

recovered gas into a gas flow line or collection system, reinject the recovered gas into the well or another well, use the 

recovered gas as an on-site fuel source, or use the recovered 

gas for another useful purpose that a purchased fuel or raw 

material would serve, with no direct release to the atmosphere. 

If this is infeasible, follow the requirements in paragraph 

(a)(3) of this section. 

(2) All salable quality gas must be routed to the gas flow 

line as soon as 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 completion 

combustion device may negatively impact tundra, permafrost or 

waterways. Completion combustion devices must be equipped with a 

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reliable continuous ignition source over the duration of 

flowback. 

(4) You have a general duty to safely maximize resource 

recovery and minimize releases to the atmosphere during flowback 

and subsequent recovery. 

(b) You must maintain a log for each well completion 

operation at each gas well affected facility. The log must be 

completed on a daily basis for the duration of the well 

completion operation and must contain the records specified in 

§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. 

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(A) Each well completion operation with hydraulic 

fracturing at a gas well affected facility meeting the criteria 

for a wildcat or delineation well. 

(B) Each well completion operation with hydraulic 

fracturing at a gas well affected facility meeting the criteria 

for a non-wildcat low pressure gas well or non-delineation low 

pressure gas well. 

(2) You must capture and direct flowback emissions to a 

completion combustion device, except in conditions that may 

result in a fire hazard or explosion, or where high heat 

emissions from a completion combustion device may negatively 

impact tundra, permafrost or waterways. Completion combustion 

devices must be equipped with a reliable continuous ignition 

source over the duration of flowback. You must also comply with 

paragraphs (a)(4) and (b) through (e) of this section. 

(3) You must maintain records specified in 

§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. 

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(a)(1) You must reduce VOC emissions from each centrifugal 

compressor wet seal fluid degassing system by 95.0 percent or 

greater. 

(2) If you use a control device to reduce emissions, you 

must equip the wet seal fluid degassing system with a cover that 

meets the requirements of §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. 

(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 compressor 

affected facilities? 

You must comply with the standards in paragraphs (a) 

through (d) of this section for each reciprocating compressor 

affected facility. 

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(a) You must replace the reciprocating compressor rod 

packing according to either paragraph (a)(1) or (a)(2) of this 

section. 

(1) Before the compressor has operated for 26,000 hours. 

The number of hours of operation must be continuously monitored 

beginning upon initial startup of your reciprocating compressor 

affected facility, or [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 

required 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 required by §60.5420. 

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§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. 

(a) The requirements of paragraph (b) or (c) of this 

section are not required if you determine that the use of a 

pneumatic controller affected facility with a bleed rate greater 

than 6 standard cubic feet per hour is required based on 

functional needs, including but not limited to response time, 

safety and positive actuation. 

(b)(1) Each pneumatic controller affected facility at a 

natural gas processing plant must have a bleed rate of zero. 

(2) Each pneumatic controller affected facility at a 

natural gas processing plant must be tagged with the month and 

year of installation, reconstruction or modification, and 

identification information that allows traceability to the 

records for that pneumatic controller as required in 

§60.5420(c)(4)(iv). 

(c)(1) Each pneumatic controller affected facility 

constructed, modified or reconstructed on or after [INSERT DATE 

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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 information 

that allows traceability to the records for that controller 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 you are not required to submit the notifications specified 

in §60.5420(a). 

§60.5395 What standards apply to storage vessel affected 

facilities? 

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Except as provided in paragraph (d) of this section, you 

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 

production, you must determine the VOC emission rate for each 

storage vessel affected facility using any generally accepted 

model or calculation methodology within 30 days after startup, 

and minimize emissions to the extent practicable during the 30­

day period using good engineering practices. For each storage 

vessel affected facility emitting more than 6 tpy VOC, you must 

reduce VOC emissions by 95.0 percent 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 

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model or calculation methodology upon startup. For each storage 

vessel affected facility emitting more than 6 tpy VOC, you must 

reduce VOC emissions by 95.0 percent or greater upon startup. 

(b) Control requirements. (1) If you use a control device 

(such as an enclosed combustion device or vapor recovery device) 

to reduce emissions, you must equip the storage vessel with a 

cover that meets the requirements of §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. 

(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, subpart Kb. 

(c) Compliance, notification, recordkeeping, and reporting. 

(1) You must demonstrate initial compliance with standards that 

apply to storage vessel affected facilities as required by 

§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. 

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(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. 

(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 emission limitation that achieves a 

reduction in emissions of VOC at least equivalent to that 

achieved by the controls required in this subpart according to 

the requirements of §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. 

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(f) You must use the following provision 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 considered 

not in VOC service, it must be determined that the VOC content 

can be reasonably expected never to exceed 10.0 percent by 

weight. For a piece of equipment to be considered in wet gas 

service, it must be determined that it contains or contacts the 

field gas before the extraction step in the process. For 

purposes of determining the percent VOC content of the process 

fluid that is contained in or contacts a piece of equipment, 

procedures that conform to the methods described in ASTM E169­

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 may 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) 

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except as provided in §60.5400(c) and in paragraph (b)(4) of 

this section, 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 

days as specified in paragraph (b)(1) of this section and 

§60.482-4a(b)(1) of subpart VVa. 

(ii) No pressure relief device described in paragraph 

(b)(4)(i) of this section must be allowed to operate for more 

than 30 days after a pressure release without monitoring. 

(c) Sampling connection systems are exempt from the 

requirements of §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 

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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 section. 

(e) Pumps in light liquid service, valves in gas/vapor and 

light liquid service, and pressure relief devices in gas/vapor 

service within a process unit that is located in the Alaskan 

North Slope are exempt from the routine monitoring requirements 

of §§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 §60.485a(e): 

(1) Equipment is in heavy liquid service if the weight 

percent evaporated is 10 percent or less at 150o

C (302oF) as 

determined by ASTM Method D86-78, 82, 90, 95, or 96 

(incorporated by reference as specified in §60.17). 

(2) Equipment is in light liquid service if the weight 

percent evaporated is greater than 10 percent at 150o

C (302oF) 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 provisions 

instead of §60.485a(b)(2): 

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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 the 

leak definition multiplied by (100 minus the percent of negative 

drift/divided by 100) must be re-monitored. If any calibration 

drift assessment shows a positive drift of more than 10 percent 

from the initial calibration value, then, at the 

owner/operator’s discretion, all equipment since the last 

calibration with instrument readings above the appropriate leak 

definition and below the leak definition multiplied by (100 plus 

the percent of positive drift/divided by 100) may be remonitored. 

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§60.5402 What are the alternative emission limitations for 

equipment leaks from onshore natural gas processing plants? 

(a) If, in the Administrator's judgment, an alternative 

means of emission limitation will achieve a reduction in VOC 

emissions at least equivalent to the reduction in VOC emissions 

achieved under any design, equipment, work practice or 

operational standard, the Administrator will publish, in the 

Federal Register, a notice permitting the use of that 

alternative means for the purpose of compliance with that 

standard. The notice may condition permission on requirements 

related to the operation and maintenance of the alternative 

means. 

(b) Any notice under paragraph (a) of this section must be 

published only after notice and an opportunity for a public 

hearing. 

(c) The Administrator will consider applications under this 

section from either owners or operators of affected facilities, 

or manufacturers of control equipment. 

(d) The Administrator will treat applications under this 

section according to the following criteria, except in cases 

where the Administrator concludes that other criteria are 

appropriate: 

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(1) The applicant must collect, verify and submit test data, 

covering a period of at least 12 months, necessary to support 

the finding in paragraph (a) of this section. 

(2) If the applicant is an owner or operator of an affected 

facility, the applicant must commit in writing to operate and 

maintain the alternative means so as to achieve a reduction in 

VOC emissions at least equivalent to the reduction in VOC 

emissions achieved under the design, equipment, work practice or 

operational standard. 

§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 SO2 emission 

reduction efficiency (Zi) to be determined from Table 1 of this 

subpart based on the sulfur feed rate (X) and the sulfur content 

of the acid gas (Y) of the affected facility. 

(b) After demonstrating compliance with the provisions of 

paragraph (a) of this section, you must achieve at a minimum, an 

SO2 emission reduction efficiency (Zc) to be determined from 

Table 2 of this subpart based on the sulfur feed rate (X) and 

the sulfur content of the acid gas (Y) of the affected facility. 

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60.5406 What test methods and procedures must I use for my 

sweetening units affected facilities at onshore natural gas 

processing plants? 

(a) In conducting the performance tests required in §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 SO2 

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).

Qa = average volumetric flow rate of acid gas from sweetening

unit, dscm/day (dscf/day).

Y = average H2S concentration in acid gas feed from sweetening

unit, percent by volume, expressed as a decimal.

K = (32 kg S/kg-mole)/((24.04 dscm/kg-mole)(1000 kg S/Mg))

= 1.331 × 10−3Mg/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. 

(2) You must use the continuous readings from the process 

flowmeter to determine the average volumetric flow rate (Qa) in 

dscm/day (dscf/day) of the acid gas from the sweetening unit for 

each run. 

ܻ௔ ܭܳ ൌ ܺ

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(3) You must use the Tutwiler procedure in §60.5408 or a 

chromatographic procedure following ASTM E–260 (incorporated by 

reference—see §60.17) to determine the H2S concentration in the 

acid gas feed from the sweetening unit (Y). At least one sample 

per hour (at equally spaced intervals) must be taken during each 

4-hour run. The arithmetic mean of all samples must be the 

average H2S concentration (Y) on a dry basis for the run. By 

multiplying the result from the Tutwiler procedure by 1.62 × 

10−3

, the units gr/100 scf are converted to volume percent. 

(4) Using the information from paragraphs (b)(1) and (b)(3) 

of this section, Tables 1 and 2 of this subpart must be used to 

determine the required initial (Zi) and continuous (Zc) reduction 

efficiencies of SO2 emissions. 

(c) You must determine compliance with the SO2 standards in 

§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: 

(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 

ܴ ൌ ሺ100ܵሻ /ሺܵ ൅ ܧሻ

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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.

Ce = concentration of sulfur equivalent (SO2+ reduced sulfur),

g/dscm (lb/dscf).

Qsd = volumetric flow rate of effluent gas, dscm/hr (dscf/hr).

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

(4) The concentration (Ce) of sulfur equivalent must be the 

sum of the SO2 and TRS concentrations, after being converted to 

sulfur equivalents. For each run and each of the test methods 

specified in this paragraph (c) of this section, you must use a 

sampling time of at least 4 hours. You must use Method 1 of 

appendix A to part 60 of this chapter to select the sampling 

site. The sampling point in the duct must be at the centroid of 

the cross-section if the area is less than 5 m2

 (54 ft2 ) or at a 

point no closer to the walls than 1 m (39 in) if the crosssectional area is 5 m2

 or more, and the centroid is more than 1 m 

(39 in.) from the wall. 

(i) You must use Method 6 of appendix A to part 60 of this 

chapter to determine the SO2 concentration. You must take eight 

samples of 20 minutes each at 30-minute intervals. The 

arithmetic average must be the concentration for the run. The 

ଵܭ/௦ௗܳ௘ܥ ൌ ܧ

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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 reductiontype 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 ft3 /min) to insure minimum residence 

time in the sample line. You must take sixteen samples at 15­

minute intervals. The arithmetic average of all the samples must 

be the concentration for the run. The concentration in ppm 

reduced sulfur as sulfur must be multiplied by 1.333 × 10−3 to 

convert the results to sulfur equivalent. 

(iii) You must use Method 16A or Method 15 of appendix A to 

part 60 of this chapter to determine the reduced sulfur 

concentration from oxidation-type devices or where the oxygen 

content of the effluent gas is greater than 1.0 percent by 

volume. You must take eight samples of 20 minutes each at 30­

minute intervals. The arithmetic average must be the 

concentration for the run. The concentration in ppm reduced 

sulfur as sulfur must be multiplied by 1.333 × 10−3

 to convert 

the results to sulfur equivalent. 

(iv) You must use Method 2 of appendix A to part 60 of this 

chapter to determine the volumetric flow rate of the effluent 

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gas. A velocity traverse must be conducted at the beginning and 

end of each run. The arithmetic average of the two measurements 

must be used to calculate the volumetric flow rate (Qsd) for the 

run. For the determination of the effluent gas molecular weight, 

a single integrated sample over the 4-hour period may be taken 

and analyzed or grab samples at 1-hour intervals may be taken, 

analyzed, and averaged. For the moisture content, you must take 

two samples of at least 0.10 dscm (3.5 dscf) and 10 minutes at 

the beginning of the 4-hour run and near the end of the time 

period. The arithmetic average of the two runs must be the 

moisture content for the run. 

60.5407 What are the requirements for monitoring of emissions 

and operations from my sweetening unit affected facilities at 

onshore natural gas processing plants? 

(a) If your sweetening unit affected facility is located at 

an onshore natural gas processing plant and is subject to the 

provisions of §60.5405(a) or (b) you must install, calibrate, 

maintain, and operate monitoring devices or perform measurements 

to determine the following operations information on a daily 

basis: 

(1) The accumulation of sulfur product over each 24-hour 

period. The monitoring method may incorporate the use of an 

instrument to measure and record the liquid sulfur production 

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rate, or may be a procedure for measuring and recording the 

sulfur liquid levels in the storage vessels with a level 

indicator or by manual soundings, with subsequent calculation of 

the sulfur production rate based on the tank geometry, stored 

sulfur density, and elapsed time between readings. The method 

must be designed to be accurate within ±2 percent of the 24-hour 

sulfur accumulation. 

(2) The H2S concentration in the acid gas from the 

sweetening unit for each 24-hour period. At least one sample per 

24-hour period must be collected and analyzed using the equation 

specified in §60.5406(b)(1). The Administrator may require you 

to demonstrate that the H2S concentration obtained from one or 

more samples over a 24-hour period is within ±20 percent of the 

average of 12 samples collected at equally spaced intervals 

during the 24-hour period. In instances where the H2S 

concentration of a single sample is not within ±20 percent of 

the average of the 12 equally spaced samples, the Administrator 

may require a more frequent sampling schedule. 

(3) The average acid gas flow rate from the sweetening 

unit. You must install and operate a monitoring device to 

continuously measure the flow rate of acid gas. The monitoring 

device reading must be recorded at least once per hour during 

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each 24-hour period. The average acid gas flow rate must be 

computed from the individual readings. 

(4) The sulfur feed rate (X). For each 24-hour period, you 

must compute X using the equation specified in §60.5406(b)(1). 

(5) The required sulfur dioxide emission reduction 

efficiency for the 24-hour period. You must use the sulfur feed 

rate and the H2S concentration in the acid gas for the 24-hour 

period, as applicable, to determine the required reduction 

efficiency in accordance with the provisions of §60.5405(b). 

(b) Where compliance is achieved through the use of an 

oxidation control system or a reduction control system followed 

by a continually operated incineration device, you must install, 

calibrate, maintain, and operate monitoring devices and 

continuous emission monitors as follows: 

(1) A continuous monitoring system to measure the total 

sulfur emission rate (E) of SO2 in the gases discharged to the 

atmosphere. The SO2 emission rate must be expressed in terms of 

equivalent sulfur mass flow rates (kg/hr (lb/hr)). The span of 

this monitoring system must be set so that the equivalent 

emission limit of §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 

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leaving the combustion zone 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 manufacturer 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 SO2) in 

the gas leaving the incinerator is equal to or less than 0.98, 

then temperature monitoring may be used to demonstrate that 

sulfur dioxide emission monitoring is sufficient to determine 

total sulfur emissions. At all times during the operation of the 

facility, you must maintain the average temperature of the gas 

leaving the combustion zone of the incinerator at or above the 

appropriate level determined during the most recent performance 

test to ensure the sulfur compound oxidation criteria are met. 

Operation at lower average temperatures may be considered by the 

Administrator to be unacceptable operation and maintenance of 

the affected facility. You may request that the minimum 

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incinerator temperature be reestablished by conducting new 

performance tests under §60.8. 

(4) Upon promulgation of a performance specification of 

continuous monitoring systems for total reduced sulfur compounds 

at sulfur recovery plants, you may, as an alternative to 

paragraph (b)(2) of this section, install, calibrate, maintain, 

and operate a continuous emission monitoring system for total 

reduced sulfur compounds as required in paragraph (d) of this 

section in addition to a sulfur dioxide emission monitoring 

system. The sum of the equivalent sulfur mass emission rates 

from the two monitoring systems must be used to compute the 

total sulfur emission rate (E). 

(c) Where compliance is achieved through the use of a 

reduction control system not followed by a continually operated 

incineration device, you must install, calibrate, maintain, and 

operate a continuous monitoring system to measure the emission 

rate of reduced sulfur compounds as SO2 equivalent in the gases 

discharged to the atmosphere. The SO2 equivalent compound 

emission rate must be expressed in terms of equivalent sulfur 

mass flow rates (kg/hr (lb/hr)). The span of this monitoring 

system must be set so that the equivalent emission limit of 

§60.5405(b) will be between 30 and 70 percent of the measurement 

range of the system. This requirement becomes effective upon 

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promulgation of a performance specification for continuous 

monitoring systems for total reduced sulfur compounds at sulfur 

recovery plants. 

(d) For those sources required to comply with paragraph (b) 

or (c) of this section, you must calculate the average sulfur 

emission reduction efficiency achieved (R) for each 24-hour 

clock internal. The 24-hour interval may begin and end at any 

selected clock time, but must be consistent. You must compute 

the 24-hour average reduction efficiency (R) based on the 24­

hour average sulfur production rate (S) and sulfur emission rate 

(E), using the equation in §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. 

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(e) In lieu of complying with paragraphs (b) or (c) of this 

section, those sources with a design capacity of less than 152 

Mg/D (150 LT/D) of H2S expressed as sulfur may calculate the 

sulfur emission reduction efficiency achieved for each 24-hour 

period by: 

Where: 

R = The sulfur dioxide removal efficiency achieved during the

24-hour period, percent.

K2 = Conversion factor, 0.02400 Mg/D per kg/hr (0.01071 LT/D per

lb/hr).

S = The sulfur production rate during the 24-hour period, kg/hr

(lb/hr).

X = The sulfur feed rate in the acid gas, Mg/D (LT/D). 

(f) The monitoring devices required in paragraphs (b)(1), 

(b)(3) and (c) of this section must be calibrated at least 

annually according to the manufacturer's specifications, as 

required by §60.13(b). 

(g) The continuous emission monitoring systems required in 

paragraphs (b)(1), (b)(3), and (c) of this section must be 

subject to the emission monitoring requirements of §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. 

ܵ

ܺ

ܭଶ ܴ ൌ

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§60.5408 What is an optional procedure for measuring hydrogen 

sulfide in acid gas—Tutwiler Procedure?1 

(a) When an instantaneous sample is desired and H2S 

concentration is ten grains per 1000 cubic foot or more, a 100 

ml Tutwiler burette is used. For concentrations less than ten 

grains, a 500 ml Tutwiler burette and more dilute solutions are 

used. In principle, this method consists of titrating hydrogen 

sulfide in a gas sample directly with a standard solution of 

iodine. 

(b) Apparatus. (See Figure 1 of this subpart) A 100 or 500 

ml capacity Tutwiler burette, with two-way glass stopcock at 

bottom and three-way stopcock at top which connect either with 

inlet tubulature or glass-stoppered cylinder, 10 ml capacity, 

graduated in 0.1 ml subdivision; rubber tubing connecting 

burette with leveling bottle. 

(c) Reagents. (1) Iodine stock solution, 0.1N. Weight 12.7 

g iodine, and 20 to 25 g cp potassium iodide for each liter of 

solution. Dissolve KI in as little water as necessary; dissolve 

iodine in concentrated KI solution, make up to proper volume, 

and store in glass-stoppered brown glass bottle. 

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). 

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(2) Standard iodine solution, 1 ml=0.001771 g I. Transfer 

33.7 ml of above 0.1N stock solution into a 250 ml volumetric 

flask; add water to mark and mix well. Then, for 100 ml sample 

of gas, 1 ml of standard iodine solution is equivalent to 100 

grains H2S per cubic feet of gas. 

(3) Starch solution. Rub into a thin paste about one 

teaspoonful of wheat starch with a little water; pour into about 

a pint of boiling water; stir; let cool and decant off clear 

solution. Make fresh solution every few days. 

(d) Procedure. Fill leveling bulb with starch solution. 

Raise (L), open cock (G), open (F) to (A), and close (F) when 

solutions starts to run out of gas inlet. Close (G). Purge gas 

sampling line and connect with (A). Lower (L) and open (F) and 

(G). When liquid level is several ml past the 100 ml mark, close 

(G) and (F), and disconnect sampling tube. Open (G) and bring 

starch solution to 100 ml mark by raising (L); then close (G). 

Open (F) momentarily, to bring gas in burette to atmospheric 

pressure, and close (F). Open (G), bring liquid level down to 10 

ml mark by lowering (L). Close (G), clamp rubber tubing near (E) 

and disconnect it from burette. Rinse graduated cylinder with a 

standard iodine solution (0.00171 g I per ml); fill cylinder and 

record reading. Introduce successive small amounts of iodine 

thru (F); shake well after each addition; continue until a faint 

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permanent blue color is obtained. Record reading; subtract from 

previous reading, and call difference D. 

(e) With every fresh stock of starch solution perform a 

blank test as follows: Introduce fresh starch solution into 

burette up to 100 ml mark. Close (F) and (G). Lower (L) and open 

(G). When liquid level reaches the 10 ml mark, close (G). With 

air in burette, titrate as during a test and up to same end 

point. Call ml of iodine used C. Then, 

Grains H2S per 100 cubic foot of gas = 100(D—C) 

(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 starchiodine end point is much less distinct, and a blank 

determination of end point, with H2S-free gas or air, is 

required. 

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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 

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affected facility, my pneumatic controller affected facility, my 

storage vessel affected facility, and my equipment leaks and 

sweetening unit affected facilities at onshore natural gas 

processing plants? 

You must determine initial compliance with the standards 

for each affected facility using the requirements in paragraphs 

(a) through (g) of this section. The initial compliance period 

begins on [INSERT DATE OF PUBLICATION IN THE FEDERAL REGISTER] 

or upon initial startup, whichever is later, and ends no later 

than one year after the initial startup date for your affected 

facility or no later than one year after [INSERT DATE OF 

PUBLICATION IN THE FEDERAL REGISTER]. The initial compliance 

period may be less than one full year. 

(a) To achieve initial compliance with the standards for 

each well completion operation conducted at your gas well 

affected facility you must comply with paragraphs (a)(1) through 

(a)(4) of this section. 

(1) You must submit the notification required in 

§60.5420(a)(2). 

(2) You must submit the initial annual report for your well 

affected facility as required in §60.5420(b). 

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(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. 

(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 the completion combustion 

device (if applicable) connected to and operating at each gas 

well completion operation that occurred during the initial 

compliance period. As an alternative to imbedded latitude and 

longitude within the digital photograph, the digital photograph 

may consist of a photograph of the equipment connected and 

operating at each well completion operation with a photograph of 

a separately operating GIS device within the same digital 

picture, provided the latitude and longitude output of the GIS 

unit can be clearly read in the digital photograph. 

(b)(1) To achieve initial compliance with standards for 

your centrifugal compressor affected facility you must reduce 

VOC emissions from each centrifugal compressor wet seal fluid 

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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 

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 

requirements 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 

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(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. 

(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, you 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 

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bleed rate greater than 6 standard cubic feet of gas per hour is 

required as specified in §60.5390(a). 

(2) You own or operate a pneumatic controller affected 

facility located at a natural gas processing plant and your 

pneumatic controller is driven other than by use of natural gas 

and therefore emits zero natural gas. 

(3) You own or operate a pneumatic controller affected 

facility located between the wellhead and a natural gas 

processing plant and the manufacturer’s design specifications 

indicate that the controller emits less than or equal to 6 

standard cubic feet of gas per hour. 

(4) You must tag each new pneumatic controller affected 

facility according to the requirements of §60.5390(b)(2). 

(5) You must include the information in paragraph (d)(1) of 

this section and a listing of the pneumatic controller affected 

facilities specified in paragraphs (d)(2) and (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. 

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(e) To achieve initial compliance with the emission 

standards for your storage vessel affected facility you must 

comply with paragraphs (e)(1) through (9) of this section. 

(1) You have determined the VOC emission rate within 30 

days after startup for storage vessels constructed, modified or 

reconstructed at well sites with no other wells in production, 

and you must use good engineering practices to minimize 

emissions during the 30-day period. 

(2) You must determine the VOC emission rate upon startup 

for storage vessels constructed, modified or reconstructed at 

well sites with one or more wells already in production. 

(3) For storage vessel affected facilities emitting more 

than 6 tpy VOC, you must reduce VOC emissions by 95.0 percent or 

greater within 60 days after startup for storage vessels 

constructed, modified or reconstructed at well sites with no 

other wells in production, or upon startup for storage vessels 

constructed, modified or reconstructed at well sites with one or 

more wells already in production. 

(4) If you use a control device to reduce emissions, you 

must equip the storage vessel with a cover that meets the 

requirements of §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 

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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. 

(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 

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 requirements 

is demonstrated if you are in compliance with the requirements 

of §60.5400. 

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(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 

this section. 

(1) To determine compliance with the standards for SO2 

specified in §60.5405(a), during the initial performance test as 

required by §60.8, the minimum required sulfur dioxide emission 

reduction efficiency (Zi) is compared to the emission reduction 

efficiency (R) achieved by the sulfur recovery technology as 

specified in paragraphs (g)(1)(i) and (g)(1)(ii) of this 

section. 

(i) If R ≥ Zi, your affected facility is in compliance. 

(ii) If R < Zi, your affected facility is not in compliance. 

(2) The emission reduction efficiency (R) achieved by the 

sulfur reduction technology must be determined using the 

procedures in §60.5406(c)(1). 

(3) You have submitted the results of paragraphs (g)(1) and 

(g)(2) of this section in the initial annual report 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 

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from storage vessels and centrifugal compressor wet seal 

degassing systems? 

You must meet the applicable requirements of this section 

for each cover and closed vent system used to comply with the 

emission standards for your storage vessel or centrifugal 

compressor affected facility. 

(a) Closed vent system requirements. (1) You must design 

the closed vent system to route all gases, vapors, and fumes 

emitted from the material in the storage vessel or wet seal 

fluid degassing system to a control device that meets the 

requirements specified in §60.5412. 

(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) and (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 this 

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 

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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 the control device to the atmosphere. 

(B) You must secure the bypass device valve installed at 

the inlet to the bypass device in the non-diverting position 

using a car-seal or a lock-and-key type configuration. 

(ii) Low leg drains, high point bleeds, analyzer vents, 

open-ended valves or lines, and safety devices are not subject 

to the requirements of paragraph (a)(3)(i) of this section. 

(b) Cover requirements. (1) The cover and all openings on 

the cover (e.g., access hatches, sampling ports, and gauge 

wells) shall form a continuous barrier over the entire surface 

area of the liquid in the storage vessel or wet seal fluid 

degassing system. 

(2) Each cover opening shall be secured in a closed, sealed 

position (e.g., covered by a gasketed lid or cap) whenever 

material is in the unit on which the cover is installed except 

during those times when it is necessary to use an opening as 

follows: 

(i) To add material to, or remove material from the unit 

(this includes openings necessary to equalize or balance the 

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internal pressure of the unit following changes in the level of 

the material in the unit); 

(ii) To inspect or sample the material in the unit; 

(iii) To inspect, maintain, repair, or replace equipment 

located inside the unit; or 

(iv) To vent liquids, gases, or fumes from the unit through 

a closed-vent system to a control device designed and operated 

in accordance with the requirements of paragraph (a) of this 

section. 

§60.5412 What additional requirements must I meet for 

determining initial compliance with control devices used to 

comply with the emission standards for my storage vessel or 

centrifugal compressor affected facility? 

You must meet the applicable requirements of this section 

for each control device used to comply with the emission 

standards for your storage vessel or centrifugal compressor 

affected facility. 

(a) If you use a control device to meet the emission 

reduction standard in §60.5380(a)(1) for your centrifugal 

compressor or §60.5395(a)(1) or (a)(2) for your storage vessel, 

you 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 using 

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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 performance 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 requirements 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 

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 §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. 

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(2) You must design and operate a vapor recovery device 

(e.g., carbon adsorption system or condenser) or other nondestructive control device to reduce the mass content of VOC in 

the gases vented to the device by 95.0 percent by weight or 

greater as determined in accordance with the requirements of 

§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 

vented from the storage vessel affected facility, as required 

under §60.5395, or wet seal fluid degassing system affected 

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 monitored in accordance with 

the requirements of §60.5417, you must demonstrate compliance 

according to the requirements of §60.5415(e)(2), as applicable. 

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(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 with 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 

and 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 

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. 

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(ii) Regenerate or reactivate the spent carbon in a thermal 

treatment unit equipped with and operating air emission controls 

in accordance with this section. 

(iii) Regenerate or reactivate the spent carbon in a 

thermal treatment unit equipped with and operating organic air 

emission controls in accordance with an emissions standard for 

VOC under another subpart in 40 CFR part 60 or this part. 

(iv) Burn the spent carbon in a hazardous waste incinerator 

for which the owner or operator has been issued a final permit 

under 40 CFR part 270 that implements the requirements of 40 CFR 

part 264, subpart O. 

(v) Burn the spent carbon in a hazardous waste incinerator 

which you have designed and operated in accordance with the 

requirements of 40 CFR part 265, subpart O. 

(vi) Burn the spent carbon in a boiler or industrial 

furnace for which you have been issued a final permit under 40 

CFR part 270 that implements the requirements of 40 CFR part 

266, subpart H. 

(vii) Burn the spent carbon in a boiler or industrial 

furnace that you have designed and operated in accordance with 

the interim status requirements of 40 CFR part 266, subpart H. 

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§60.5413 What are the performance testing procedures for control 

devices used to demonstrate compliance at my storage vessel or 

centrifugal compressor affected facility? 

This section applies to the performance testing of control 

devices used to demonstrate compliance with the emissions 

standards for your storage vessel or centrifugal compressor 

affected facility. You must demonstrate that a control device 

achieves the performance requirements of §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. 

(2) A boiler or process heater with a design heat input 

capacity of 44 megawatts or greater. 

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(3) A boiler or process heater into which the vent stream 

is introduced with the primary fuel or is used as the primary 

fuel. 

(4) A boiler or process heater burning hazardous waste for 

which you have either been issued a final permit under 40 CFR 

part 270 and comply with the requirements of 40 CFR part 266, 

subpart H; or you have certified compliance with the interim 

status requirements of 40 CFR part 266, subpart H. 

(5) A hazardous waste incinerator for which you have been 

issued a final permit under 40 CFR part 270 and comply with the 

requirements of 40 CFR part 264, subpart O; or you have 

certified compliance with the interim status requirements of 40 

CFR part 265, subpart O. 

(6) A performance test is waived in accordance with 

§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 

conducted to demonstrate that a control device meets the 

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requirements of §60.5412(a). You must conduct the initial and 

periodic performance tests according to the schedule specified 

in paragraph (b)(5) of this section. 

(1) You must use Method 1 or 1A at 40 CFR part 60, appendix 

A-1, as appropriate, to select the sampling sites specified in 

paragraphs (b)(1)(i) and (b)(1)(ii) of this section. Any 

references to particulate mentioned in Methods 1 and 1A do not 

apply to this section. 

(i) Sampling sites must be located at the inlet of the 

first control device, and at the outlet of the final control 

device, to determine compliance with the control device percent 

reduction requirement specified in §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 use Method 25A at 40 CFR part 60, appendix A-7. 

You must use the procedures in paragraphs (b)(3)(i) through 

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(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 four grab samples per hour. If grab sampling is 

used, then the samples must be taken at approximately equal 

intervals in time, such as 15-minute intervals during the run. 

(ii) You must compute the mass rate of TOC (minus methane 

and ethane) using the equations and procedures specified in 

paragraphs (b)(3)(ii)(A) and (b)(3)(ii)(B) of this section. 

(A) You must use the following equations: 

௡

௝௜ܯ௝௜ܥ ෍ቌ ଶܭ ൌ௜ ܧ

௝ୀଵ

௡

ቍܳ௜

௝௢ܯ௝௢ܥ ෍ቌ ଶܭ ൌ௢ ܧ

௝ୀଵ

Where: 

Ei, Eo

ቍܳ௢

= Mass rate of TOC (minus methane and ethane) at the

inlet and outlet of the control device, respectively, dry basis,

kilogram per hour.

K2 = Constant, 2.494 × 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. 

Cij, Coj = Concentration of sample component j of the gas

stream at the inlet and outlet of the control device,

respectively, dry basis, parts per million by volume. 

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Mij, Moj = Molecular weight of sample component j of the gas

stream at the inlet and outlet of the control device,

respectively, gram/gram-mole.

Qi, Qo = Flowrate of gas stream at the inlet and outlet of

the control device, respectively, dry standard cubic meter per

minute. 

n = Number of components in sample. 

(B) When calculating the TOC mass rate, you must sum all 

organic compounds (minus methane and ethane) measured by Method 

25A at 40 CFR part 60, appendix A-7 using the equations in 

paragraph (b)(3)(ii)(A) of this section. 

(iii) You must calculate the percent reduction in TOC (minus 

methane and ethane) as follows: 

Where: 

Rcd = Control efficiency of control device, percent.

Ei = Mass rate of TOC (minus methane and ethane) at the

inlet to the control device as calculated under paragraph

(b)(3)(ii) of this section, kilograms TOC per hour or kilograms

HAP per hour.

Eo = Mass rate of TOC (minus methane and ethane) at the

outlet of the control device, as calculated under paragraph

(b)(3)(ii) of this section, kilograms TOC per hour per hour. 

(iv) If the vent stream entering a boiler or process heater 

with a design capacity less than 44 megawatts is introduced with 

the combustion air or as a secondary fuel, you must determine 

the weight-percent reduction of total TOC (minus methane and 

ethane) across the device by comparing the TOC (minus methane 

and ethane) in all combusted vent streams and primary and 

௜ܧ 100% כ ൌ ௗ௖ܴ௢ ܧ െ௜ ܧ

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secondary fuels with the TOC (minus methane and ethane) exiting 

the device, respectively. 

(4) You must use Method 25A at 40 CFR part 60, appendix A-7 

to measure TOC (minus methane and ethane) to determine 

compliance with the enclosed combustion device total VOC 

concentration limit specified in §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 during the run. 

(ii) You must calculate the TOC concentration for each run as 

follows: 

൫∑ ܥ௜௝൯ ௝ୀ௜

௡ ௫

ݔ ෍ ൌ஼ ை்ܥ

௜ୀଵ

Where: 

CTOC = Concentration of total organic compounds minus methane

and ethane, dry basis, parts per million by volume.

Cji = Concentration of sample component j of sample i, dry

basis, parts per million by volume.

n = Number of components in the sample.

x = Number of samples in the sample run. 

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(iii) You must correct the TOC concentration to 3 percent 

oxygen as specified in paragraphs (b)(4)(iii)(A) and 

(b)(4)(iii)(B) of this section. 

(A) You must use the emission rate correction factor for 

excess air, integrated sampling and analysis procedures of 

Method 3A or 3B at 40 CFR part 60, appendix A to determine the 

oxygen concentration. The samples must be taken during the same 

time that the samples are taken for determining TOC 

concentration. 

(B) You must correct the TOC concentration for percent 

oxygen as follows: 

17.9 ൰ 20.9 െ %ܱଶௗ

Where: 

Cc = TOC concentration corrected to 3 percent oxygen, dry

basis, parts per million by volume.

Cm = TOC concentration, dry basis, parts per million by

volume. 

%O2d = Concentration of oxygen, dry basis, percent by volume. 

(5) You must conduct performance tests according to the 

schedule specified in paragraphs (b)(5)(i) and (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 

൬௠ ܥ ൌ௖ ܥ

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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 

except as specified in paragraphs (b)(5)(ii)(A) and 

(b)(5)(ii)(B) of this section. You must conduct the first 

periodic performance test no later than 60 months after the 

initial performance test required in paragraph (b)(5)(i) of this 

section. You must conduct subsequent periodic performance tests 

at intervals no longer than 60 months following the previous 

periodic performance test or whenever you desire to establish a 

new operating limit. You must submit the periodic performance 

test results as specified in §60.5420(b)(7). Combustion control 

devices meeting the criteria in either paragraph (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. 

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(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 

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. 

(2) For a regenerable carbon adsorption system, the design 

analysis shall include the vent stream composition, constituent 

concentrations, flowrate, relative humidity, and temperature, 

and shall establish the design exhaust vent stream organic 

compound concentration level, adsorption cycle time, number and 

capacity of carbon beds, type and working capacity of activated 

carbon used for the carbon beds, design total regeneration 

stream flow over the period of each complete carbon bed 

regeneration cycle, design carbon bed temperature after 

regeneration, design carbon bed regeneration time, and design 

service life of the carbon. 

(3) For a nonregenerable carbon adsorption system, such as 

a carbon canister, the design analysis shall include the vent 

stream composition, constituent concentrations, flowrate, 

relative humidity, and temperature, and shall establish the 

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design exhaust vent stream organic compound concentration level, 

capacity of the carbon bed, type and working capacity of 

activated carbon used for the carbon bed, and design carbon 

replacement interval based on the total carbon working capacity 

of the control device and source operating schedule. In 

addition, these systems will incorporate dual carbon canisters 

in case of emission breakthrough occurring in one canister. 

(4) If you and the Administrator do not agree on a 

demonstration of control device performance using a design 

analysis, then you must perform a performance test in accordance 

with the requirements of paragraph (b) of this section to 

resolve the disagreement. The Administrator may choose to have 

an authorized representative observe the performance test. 

(d) Performance testing for combustion control devices ­

manufacturers’ performance test. The manufacturer must 

demonstrate that a specific model of combustion control device 

achieves the performance requirements in paragraph (d)(1) of 

this section by conducting a performance test as specified in 

paragraphs (d)(2) through (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. 

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(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. 

(A) Method 22 at 40 CFR part 60, appendix A-7, results 

under paragraph (d)(6)(iv) of this section with no indication of 

visible emissions. 

(B) Average Method 25A at 40 CFR part 60, appendix A-7, 

results under paragraph (d)(8) of this section equal to or less 

than 10.0 parts per million by volume-wet THC as propane 

corrected to 3.0 percent carbon dioxide, and 

(C) Average carbon monoxide emissions determined under 

paragraph (d)(6)(iii) of this section equal to or less than 10 

parts per million by volume-dry, corrected to 3.0 percent carbon 

dioxide. 

(ii) The manufacturer must determine a maximum inlet gas 

flow rate, which must not be exceeded for each control device 

model to achieve the criteria in paragraph (d)(1)(i) of this 

section. 

(iii) A control device meeting the emission levels in 

paragraph (d)(1)(i)(A) through (d)(1)(i)(C) of this section must 

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demonstrate a minimum destruction efficiency of 95.0 percent for 

VOC regulated under this subpart. 

(2) Performance testing must consist of three one-hour (or 

longer) test runs for each of the four firing rate settings in 

paragraphs (d)(2)(i) through (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 independent 

third-party laboratory (not affiliated with the control device 

manufacturer or fuel supplier) must perform all fuel analyses. 

(i) 90 - 100 percent of maximum design rate (fixed rate). 

(ii) 70 - 100 - 70 percent (ramp up, ramp down). Begin the 

test at 70 percent of the maximum design rate. Within the first 

5 minutes, ramp up the firing rate to 100 percent of the maximum 

design rate. Hold at 100 percent for 5 minutes. In the 10-15 

minute time range, ramp back down to 70 percent of the maximum 

design rate. Repeat three more times for a total of 60 minutes 

of sampling. 

(iii) 30 - 70 - 30 percent (ramp up, ramp down). Begin the 

test at 30 percent of the maximum design rate. Within the first 

5 minutes, ramp up the firing rate to 70 percent of the maximum 

design rate. Hold at 70 percent for 5 minutes. In the 10-15 

minute time range, ramp back down to 30 percent of the maximum 

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design rate. Repeat three more times for a total of 60 minutes 

of sampling. 

(iv) 0 - 30 - 0 percent (ramp up, ramp down). Begin the 

test at 0 percent of the maximum design rate. Within the first 5 

minutes, ramp up the firing rate to 100 percent of the maximum 

design rate. Hold at 30 percent for 5 minutes. In the 10-15 

minute time range, ramp back down to 0 percent of the maximum 

design rate. Repeat three more times for a total of 60 minutes 

of sampling. 

(3) The manufacturer must test all models employing 

multiple enclosures simultaneously and with all burners 

operational. The manufacturer must report results for each 

enclosure individually and for the average of the emissions from 

all interconnected combustion enclosures/chambers. Control 

device operating data must be collected continuously throughout 

the performance test using an electronic Data Acquisition System 

and strip chart. The manufacturer must submit data with the test 

report in accordance with paragraph (d)(9) of this section. 

(4) The manufacturer must conduct inlet testing as 

specified in paragraphs (d)(4)(i) through (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 

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other approved procedure) to measure fuel flow rate at the 

control device inlet location. You must position the fitting for 

filling fuel sample containers a minimum of eight pipe diameters 

upstream of any inlet fuel flow monitoring meter. 

(ii) The manufacturer must determine the inlet flow rate 

using Method 2A at 40 CFR part 60, appendix A-1. Record the 

start and stop reading for each 60-minute THC test. Record the 

gas pressure and temperature at 5-minute intervals throughout 

each 60-minute THC test. 

(iii) The manufacturer must conduct inlet fuel sampling in 

accordance with the criteria in paragraph (d)(5) of this 

section. 

(5) The manufacturer must conduct inlet fuel sampling as 

specified in paragraphs (d)(5)(i) and (d)(5)(ii) of this 

section. 

(i) At the inlet fuel sampling location, the manufacturer 

must securely connect a Silonite-coated stainless steel 

evacuated canister fitted with a flow controller sufficient to 

fill the canister over a 1 hour period. Filling must be 

conducted as specified in paragraphs (d)(5)(i)(A) through 

(d)(5)(i)(C) of this section. 

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(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. 

(B) Hydrogen (H2), carbon monoxide (CO), carbon dioxide 

(CO2), nitrogen (N2), oxygen (O2) 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 criteria 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: 

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(A) The manufacturer must position the outlet sampling 

location a minimum of four equivalent stack diameters downstream 

from the highest peak flame or any other flow disturbance, and a 

minimum of one equivalent stack diameter upstream of the exit or 

any other flow disturbance. A minimum of two sample ports must 

be used. 

(B) The manufacturer must measure flow rate using Method 1 

at 40 CFR part 60, appendix A-1 for determining flow measurement 

traverse point location, and Method 2 at 40 CFR part 60, 

appendix A-1 for measuring duct velocity. If low flow conditions 

are encountered (i.e., velocity pressure differentials less than 

0.05 inches of water) during the performance test, a more 

sensitive manometer must be used to obtain an accurate flow 

profile. 

(ii) The manufacturer must determine molecular weight as 

specified in paragraph (d)(7) of this section. 

(iii) The manufacturer must determine carbon monoxide using 

Method 10 at 40 CFR part 60, appendix A-4. 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. 

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(iv) The manufacturer must determine visible emissions 

using Method 22 at 40 CFR part 60, appendix A-7. The test must 

be performed continuously during each test run. A digital color 

photograph of the exhaust point, taken from the position of the 

observer and annotated with date and time, will be taken once 

per test run and the four photos included in the test report. 

(7) The manufacturer must determine molecular weight as 

specified in paragraphs (d)(7)(i) and (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 gas 

chromatograph-thermal conductivity detector (GC-TCD) analysis 

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 each traverse 

location. 

(B) Purge the sampling line with stack gas before opening 

the valve and beginning to fill the bag. 

(C) Knead or otherwise vigorously mix the bag contents 

prior to the gas chromatograph analysis. 

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(D) Modify the gas chromatograph-thermal conductivity 

detector calibration procedure in Method 3C at 40 CFR part 60, 

appendix A-2 by using EPA Alt-045 as follows: For the initial 

calibration, triplicate injections of any single concentration 

must agree within 5 percent of their mean to be valid. The 

calibration response factor for a single concentration re-check 

must be within 10 percent of the original calibration response 

factor for that concentration. If this criterion is not met, 

repeat the initial calibration using at least three 

concentration levels. 

(ii) The manufacturer must report the molecular weight of 

oxygen, carbon dioxide, methane, and nitrogen and include in the 

test report submitted under §60.5420(b)(7). The manufacturer 

must determine moisture using Method 4 at 40 CFR part 60, 

appendix A-3. Traverse both ports with the Method 4 at 40 CFR 

part 60, appendix A-3, sampling train during each test run. The 

manufacturer must not introduce ambient air into the Method 3C 

at 40 CFR part 60, appendix A-2, integrated bag sample during 

the port change. 

(8) The manufacturer must determine total hydrocarbons as 

specified by the criteria in paragraphs (d)(8)(i) through 

(d)(8)(vii) of this section. 

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(i) Conduct THC sampling using Method 25A at 40 CFR part 

60, appendix A-7, except the option for locating the probe in 

the center 10 percent of the stack is not allowed. The THC probe 

must be traversed to 16.7 percent, 50 percent, and 83.3 percent 

of the stack diameter during the testing. 

(ii) A valid test must consist of three Method 25A at 40 

CFR part 60, appendix A-7, tests, each no less than 60 minutes 

in duration. 

(iii) A 0-10 parts per million by volume-wet (ppmvw) (as 

propane) measurement range is preferred; as an alternative a 0­

30 ppmvw (as carbon) measurement range may be used. 

(iv) Calibration gases will be propane in air and be 

certified through EPA Protocol 1 – “EPA Traceability Protocol 

for Assay and Certification of Gaseous Calibration Standards,” 

September 1997, as amended August 25, 1999, EPA–600/R–97/121. 

(v) THC measurements must be reported in terms of ppmvw as 

propane. 

(vi) THC results must be corrected to 3 percent CO2, as 

measured by Method 3C at 40 CFR part 60, appendix A-2. 

(vii) Subtraction of methane/ethane from the THC data is 

not allowed in determining results. 

(9) For each combustion control device model tested by the 

manufacturer under this section, you must maintain records of 

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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) 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. 

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(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. 

§60.5415 How do I demonstrate continuous compliance with the 

standards for my gas well affected facility, my centrifugal 

compressor affected facility, my stationary reciprocating 

compressor affected facility, my pneumatic controller affected 

facility, my storage vessel affected facility, and my affected 

facilities at onshore natural gas processing plants? 

(a) For each gas well affected facility, you must 

demonstrate continuous compliance by submitting the reports 

required by §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. 

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(1) You must reduce VOC emissions from the wet seal fluid 

degassing system by 95.0 percent or greater. 

(2) If you use a control device to reduce emissions, you 

must demonstrate continuous compliance according to paragraph 

(e)(2) of this section. 

(3) You must submit the annual report required by 

60.5420(b) and maintain the records as specified in 

§60.5420(c)(2). 

(c) For each reciprocating 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 must submit the annual report as required in 

§60.5420(b) and maintain records as required in §60.5420(c)(3). 

(3) You must replace the reciprocating compressor rod 

packing before the total number of hours of operation reaches 

26,000 hours or the number of months since the most recent rod 

packing replacement reaches 36 months. 

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(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 

§60.5420(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 

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) 

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through (e)(2)(vii) of this section and compliance with 

paragraph (e)(2)(viii) of this section only after at least 1 

year of operation in compliance with the selected approach. You 

must provide notification of such a change in the compliance 

method in the next Annual Report, as required in §60.5420(b), 

following the change. 

(i) You must operate below (or above) the site specific 

maximum (or minimum) parameter value established according to 

the requirements of §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 under paragraph (e)(2)(ii) of this section is 

either equal to or greater than the minimum monitoring value or 

equal to or less than the maximum monitoring value established 

under paragraph (e)(2)(i) of this section. When performance 

testing of a combustion control device is conducted by the 

device manufacturer as specified in §60.5413(d), compliance with 

the operating parameter limit is achieved when the inlet gas 

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flow rate is equal to or less than the value established under 

§60.5413(d)(1)(ii). 

(iv) You must 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 quality assurance or quality control 

activities (including, as applicable, system accuracy audits and 

required zero and span adjustments). A monitoring system 

malfunction is any sudden, infrequent, not reasonably 

preventable failure of the monitoring system to provide valid 

data. Monitoring system failures that are caused in part by poor 

maintenance or careless operation are not malfunctions. You are 

required to complete monitoring system repairs in response to 

monitoring system malfunctions and to return the monitoring 

system to operation as expeditiously as practicable. 

(v) You may not use data recorded during monitoring system 

malfunctions, repairs associated with monitoring system 

malfunctions, or required monitoring system quality assurance or 

control activities in calculations used to report emissions or 

operating levels. You must use all the data collected during all 

other required data collection periods to assess the operation 

of the control device and associated control system. 

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(vi) Failure to collect required data is a deviation of the 

monitoring requirements, except for periods of monitoring system 

malfunctions, repairs associated with monitoring system 

malfunctions, and required quality monitoring system quality 

assurance or quality control activities (including, as 

applicable, system accuracy audits and required zero and span 

adjustments). 

(vii) If you use a combustion control device to meet the 

requirements of §60.5412(a), you must demonstrate compliance by 

installing a device tested under the provisions 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, 

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appendix A-7 monthly. The observation period must be 2 hours and 

must follow Method 22. 

(D) Compliance with the operating parameter limit is 

achieved when the criteria in paragraphs (e)(2)(vii)(D)(1) 

through (e)(2)(vii)(D)(5) are met. 

(1) The inlet gas flow rate monitored under paragraph 

(e)(2)(vii)(A) of this section is equal to or below the maximum 

established by the manufacturer. 

(2) The pilot flame is present at all times; and 

(3) During the visible emissions test performed under 

paragraph (e)(2)(vii)(C) of this section, the duration of 

visible emissions does not exceed a total of 5 minutes during 

the observation period. Devices failing the visible emissions 

test must follow the requirements in paragraphs 

(e)(2)(vii)(D)(4) and (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 

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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 

in §60.5412(a)(2), you must demonstrate compliance using the 

procedures in paragraphs (e)(2)(viii)(A) through (e)(2)(viii)(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 condenser efficiency for the 

current operating day using the daily average condenser outlet 

temperature calculated under paragraph (e)(2)(viii)(B) of this 

section and the condenser performance curve established under 

paragraph (e)(2)(viii)(A) of this section. 

(D) Except as provided in paragraphs (e)(2)(viii)(D)(1) and 

(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 less than 120 days of data for determining average TOC 

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emission reduction, you must calculate the average TOC emission 

reduction for the first 120 days of operation after the 

compliance dates. You have demonstrated compliance with the 

overall 95.0 percent reduction requirement if the 120-day 

average TOC emission reduction is equal to or greater than 95.0 

percent. 

(2) After 120 days and no more than 364 days of operation 

after the compliance date specified in §60.5370, you must 

calculate the average TOC emission reduction as the TOC emission 

reduction averaged over the number of days between the current 

day and the applicable compliance date. You have demonstrated 

compliance with the overall 95.0 percent reduction requirement, 

if the average TOC emission reduction is equal to or greater 

than 95.0 percent. 

(E) If you have data for 365 days or more of operation, you 

have demonstrated compliance with the TOC emission reduction if 

the rolling 365-day average TOC emission reduction calculated in 

paragraph (e)(2)(viii)(D) of this section is equal to or greater 

than 95.0 percent. 

(f) For affected facilities at onshore natural gas 

processing plants, continuous compliance with VOC requirements 

is demonstrated if you are in compliance with the requirements 

of §60.5400. 

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(g) For each sweetening unit affected facility at onshore 

natural gas processing plants, you must demonstrate continuous 

compliance with the standards for SO2 specified in §60.5405(b) 

according to paragraphs (g)(1) and (g)(2) of this section. 

(1) The minimum required SO2 emission reduction efficiency 

(Zc) is compared to the emission reduction efficiency (R) 

achieved by the sulfur recovery technology. 

(i) If R ≥ Zc, your affected facility is in compliance. 

(ii) If R < Zc, your affected facility is not in compliance. 

(2) The emission reduction efficiency (R) achieved by the 

sulfur reduction technology must be determined using the 

procedures in §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 malfunction, 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. 

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(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: 

(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 

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prevent loss of life, personal injury, or severe property 

damage; and 

(v) All possible steps were taken to minimize the impact of 

the violation on ambient air quality, the environment and human 

health; and 

(vi) All emissions monitoring and control systems were kept 

in operation if at all possible, consistent with safety and good 

air pollution control practices; and 

(vii) All of the actions in response to the violation were 

documented by properly signed, contemporaneous operating logs; 

and 

(viii) At all times, the affected source was operated in a 

manner consistent with good practices for minimizing emissions; 

and 

(ix) A written root cause analysis has been prepared, the 

purpose of which is to determine, correct, and eliminate the 

primary causes of the malfunction and the violation resulting 

from the malfunction event at issue. The analysis shall also 

specify, using best monitoring methods and engineering judgment, 

the amount of any emissions that were the result of the 

malfunction. 

(2) Report. The owner or operator seeking to assert an 

affirmative defense shall submit a written report to the 

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Administrator with all necessary supporting documentation, that 

it has met the requirements set forth in paragraph (h)(1) of 

this section. This affirmative defense report shall be included 

in the first periodic compliance, deviation report or excess 

emission report otherwise required after the initial occurrence 

of the violation of the relevant standard (which may be the end 

of any applicable averaging period). If such compliance, 

deviation report or excess emission report is due less than 45 

days after the initial occurrence of the violation, the 

affirmative defense report may be included in the second 

compliance, deviation report or excess emission report due after 

the initial occurrence of the violation of the relevant 

standard. 

§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 

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(a)(1) and (a)(2) of this section, inspect each cover according 

to the procedures and schedule specified in paragraph (a)(3) of 

this section, and inspect each bypass device according to the 

procedures of paragraph (a)(4) of this section. 

(1) For each closed vent system joint, seam, or other 

connection that is permanently or semi-permanently sealed (e.g., 

a welded joint between two sections of hard piping or a bolted 

and gasketed ducting flange), you must meet the requirements 

specified in paragraphs (a)(1)(i) and (a)(1)(ii) of this 

section. 

(i) Conduct an initial inspection according to the test 

methods and procedures specified in paragraph (b) of this 

section to demonstrate that the closed vent system operates with 

no detectable emissions. You must maintain records of the 

inspection results as specified in §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 

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connection is unsealed. 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 the 

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 

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 procedures specified in paragraph (b) of this 

section to demonstrate that the components or connections 

operate with no detectable emissions. You must maintain records 

of the inspection results as specified in §60.5420(c)(6). 

(iii) Conduct annual visual inspections for defects that 

could result in air emissions. Defects include, but are not 

limited to, visible cracks, holes, or gaps in ductwork; loose 

connections; or broken or missing caps or other closure devices. 

You must maintain records of the inspection results as specified 

in §60.5420(c)(6). 

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(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 

the cover that extend to or above the ground surface, and those 

connections that are on such portions of the cover (e.g., fill 

ports, access hatches, gauge wells, etc.) and can be opened to 

the atmosphere. 

(ii) You must initially conduct the inspections specified 

in paragraph (a)(3)(i) of this section following the 

installation of the cover. Thereafter, you must perform the 

inspection at least once every calendar year, except as provided 

in paragraphs (e) and (f) of this section. You must maintain 

records of the inspection results as specified in 

§60.5420(c)(7). 

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(4) For each bypass device, except as provided for in 

§60.5411, 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 the atmosphere. 

(ii) If the bypass device valve installed at the inlet to 

the bypass device is secured in the non-diverting position using 

a car-seal or a lock-and-key type configuration, visually 

inspect the seal or closure mechanism at least once every month 

to verify that the valve is maintained in the non-diverting 

position and the vent stream is not diverted through the bypass 

device. You must maintain records of the inspections according 

to §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 requirements 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. 

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(2) The detection instrument must meet the performance 

criteria of Method 21 at 40 CFR part 60, appendix A-7, except 

that the instrument response factor criteria in section 3.1.2(a) 

of Method 21 must be for the average composition of the fluid 

and not for each individual organic compound in the stream. 

(3) You must calibrate the detection instrument before use 

on each day of its use by the procedures specified in Method 21 

at 40 CFR part 60, appendix A-7. 

(4) Calibration gases must be as specified in paragraphs 

(b)(4)(i) and (b)(4)(ii) of this section. 

(i) Zero air (less than 10 parts per million by volume 

hydrocarbon in air). 

(ii) A mixture of methane in air at a concentration less 

than 10,000 parts per million by volume. 

(5) You may choose to adjust or not adjust the detection 

instrument readings to account for the background organic 

concentration level. If you choose to adjust the instrument 

readings for the background level, you must determine the 

background level value according to the procedures in Method 21 

at 40 CFR part 60, appendix A-7. 

(6) Your detection instrument must meet the performance 

criteria specified in paragraphs (b)(6)(i) and (b)(6)(ii) of 

this section. 

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(i) Except as provided in paragraph (b)(6)(ii) of this 

section, the detection instrument must meet the performance 

criteria of Method 21 at 40 CFR part 60, appendix A-7, except 

the instrument response factor criteria in section 3.1.2(a) of 

Method 21 must be for the average composition of the process 

fluid, not each individual volatile organic compound in the 

stream. For process streams that contain nitrogen, air, or other 

inerts that are not organic hazardous air pollutants or volatile 

organic compounds, you must calculate the average stream 

response factor on an inert-free basis. 

(ii) If no instrument is available that will meet the 

performance criteria specified in paragraph (b)(6)(i) of this 

section, you may adjust the instrument readings by multiplying 

by the average response factor of the process fluid, calculated 

on an inert-free basis, as described in paragraph (b)(6)(i) of 

this section. 

(7) You must determine if a potential leak interface 

operates with no detectable emissions using the applicable 

procedure specified in paragraph (b)(7)(i) or (b)(7)(ii) of this 

section. 

(i) If you choose not to adjust the detection instrument 

readings for the background organic concentration level, then 

you must directly compare the maximum organic concentration 

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value measured by the detection instrument to the applicable 

value for the potential leak interface as specified in paragraph 

(b)(8) of this section. 

(ii) If you choose to adjust the detection instrument 

readings for the background organic concentration level, you 

must compare the value of the arithmetic difference between the 

maximum organic concentration value measured by the instrument 

and the background organic concentration value as determined in 

paragraph (b)(5) of this section with the applicable value for 

the potential leak interface as specified in paragraph (b)(8) of 

this section. 

(8) A potential leak interface is determined to operate 

with no detectable organic emissions if the organic 

concentration value determined in paragraph (b)(7) of this 

section is less than 500 parts per million by volume. 

(9) Repairs. In the event that a leak or defect is 

detected, you must repair the leak or defect as soon as 

practicable according to the requirements of paragraphs 

(b)(9)(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. 

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(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 or cover for which leaks or defects have been detected is 

allowed if the repair is technically infeasible without a 

shutdown, or if you determine that emissions resulting from 

immediate repair would be greater than the fugitive emissions 

likely to result from delay of repair. You must complete repair 

of such equipment by the end of the next shutdown. 

(11) Unsafe to inspect requirements. You may designate any 

parts of the closed vent system or cover as unsafe to inspect if 

the requirements in paragraphs (e)(1) and (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. 

(A) You determine that the equipment is unsafe to inspect 

because inspecting personnel would be exposed to an imminent or 

potential danger as a consequence of complying with paragraphs 

(a)(1), (a)(2), or (a)(3) of this section. 

(B) You have a written plan that requires inspection of the 

equipment as frequently as practicable during safe-to-inspect 

times. 

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(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 more 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? 

You must meet the applicable requirements of this section 

to demonstrate continuous compliance for each control device 

used to meet emission standards for your storage vessel or 

centrifugal compressor affected facility. 

(a) You must install and operate a continuous parameter 

monitoring system for each control device as specified in 

paragraphs (c) through (j) of this section, except as provided 

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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 

requirements in paragraphs (c)(1) through (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. 

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(i) Each measured data value. 

(ii) Each block average value for each 1-hour period or 

shorter periods calculated from all measured data values during 

each period. If values are measured more frequently than once 

per minute, a single value for each minute may be used to 

calculate the hourly (or shorter period) block average instead 

of all measured values. 

(2) You must prepare a site-specific monitoring plan that 

addresses the monitoring system design, data collection, and the 

quality assurance and quality control elements outlined in 

paragraphs (c)(2)(i) through (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. 

(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. 

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(iv) Ongoing operation and maintenance procedures in 

accordance with provisions in §60.13(b). 

(v) Ongoing 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 install, calibrate, operate, and maintain a 

device equipped with a continuous recorder to measure the values 

of operating parameters appropriate for the control device as 

specified in either paragraph (d)(1), (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. 

(i) For a thermal vapor incinerator that demonstrates 

during the performance test conducted under §60.5413 that 

combustion zone temperature is an accurate indicator of 

performance, a temperature monitoring device equipped with a 

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continuous recorder. The monitoring device must 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 the 

temperature sensor at a location representative of the 

combustion zone temperature. 

(ii) For a catalytic vapor incinerator, a temperature 

monitoring device equipped with a continuous recorder. The 

device must be capable of monitoring temperature at two 

locations and have a minimum accuracy of ±1 percent of the 

temperature being monitored in °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 indicates the 

continuous ignition of the pilot flame. 

(iv) For a boiler or process heater, a temperature 

monitoring device equipped with a continuous recorder. The 

temperature monitoring device must have a minimum accuracy of ±1 

percent of the temperature being monitored in °C, or ±2.5°C, 

whichever value is greater. You must install the temperature 

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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 the condenser. 

(vi) For a regenerative-type carbon adsorption system, a 

continuous monitoring system that meets the specifications in 

paragraphs (d)(1)(vi)(A) and (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. 

You must check the mechanical connections for leakage at least 

every month, and you must perform a visual inspection at least 

every 3 months of all components of the flow continuous 

parameter monitoring system for physical and operational 

integrity and all electrical connections for oxidation and 

galvanic corrosion if your flow continuous parameter monitoring 

system is not equipped with a redundant flow sensor; and 

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(B) The continuous parameter monitoring system must measure 

and record the average carbon bed temperature for the duration 

of the carbon bed steaming cycle and measure the actual carbon 

bed temperature after regeneration and within 15 minutes of 

completing the cooling cycle. The temperature monitoring device 

must have a minimum accuracy of ±1 percent of the temperature 

being monitored in °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 specified 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 continuous 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 accuracy of ±2 percent or better. 

(B) A heat sensing monitoring device equipped with a 

continuous recorder that indicates the continuous ignition of 

the pilot flame. 

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(2) A continuous monitoring system that measures the 

concentration level of organic compounds in the exhaust vent 

stream from the control device using an organic monitoring 

device equipped with a continuous recorder. The monitor must 

meet the requirements of Performance Specification 8 or 9 of 40 

CFR part 60, appendix B. You must install, calibrate, and 

maintain the monitor according to the manufacturer's 

specifications. 

(3) A continuous monitoring system that measures operating 

parameters other than those specified in paragraph (d)(1) or 

(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 available for 75 percent of the 

operating hours in an operating day to compute the daily 

average. 

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(f) For each operating parameter monitor installed in 

accordance with the requirements of paragraph (d) of this 

section, you must comply with paragraph (f)(1) of this section 

for all control devices. When condensers are installed, you must 

also comply with paragraph (f)(2) of this section. 

(1) You must establish a minimum operating parameter value 

or a maximum operating parameter value, as appropriate for the 

control device, to define the conditions at which the control 

device must be operated to continuously achieve the applicable 

performance requirements of §60.5412(a). You must establish each 

minimum or maximum operating parameter value as specified in 

paragraphs (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 recommendations or a combination of 

both. 

(ii) If you use a condenser design analysis in accordance 

with the requirements of §60.5413(c) to demonstrate that the 

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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 the 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 temperature 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 achieves the applicable performance requirements in 

§60.5412(a), then the condenser performance curve must be based 

on values measured during the performance test and supplemented 

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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 operating 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 day. 

(1) A deviation occurs when the daily average value of a 

monitored operating parameter is less than the minimum operating 

parameter limit (or, if applicable, greater than the maximum 

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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. 

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(ii) For each bypass line subject to §60.5411(a)(3)(i)(B), 

if the seal or closure mechanism has been broken, the bypass 

line valve position has changed, the key for the lock-and-key 

type lock has been checked out, or the car-seal has broken. 

(6) For a combustion control device whose model is tested 

under §60.5413(d), a deviation occurs when the conditions of 

paragraphs (g)(6)(i) or (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 §60.7(a)(1), (a)(3) and 

(a)(4). 

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(2)(i) If you own or operate a gas well affected facility, 

you must submit a notification to the Administrator no later 

than 2 days prior to the commencement of each well completion 

operation listing the anticipated date of the well completion 

operation. The notification shall include contact information 

for the owner or operator; the API well number, the latitude and 

longitude coordinates for each well in decimal degrees to an 

accuracy and precision of five (5) decimals of a degree using 

the North American Datum of 1983; and the planned date of the 

beginning of flowback. You may submit the notification in 

writing or in electronic format. 

(ii) If you are subject to state regulations that require 

advance notification of well completions and you have met those 

notification requirements, then you are considered to have met 

the advance notification requirements of paragraph (a)(2)(i) of 

this section. 

(b) Reporting requirements. You must submit annual reports 

containing the information specified in paragraphs (b)(1) 

through (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 annual reports are due on the same date 

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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 

title V reports as long as all the required elements of the 

annual report are included. You may arrange with the 

Administrator a common schedule on which reports required by 

this part may be submitted as long as the schedule does not 

extend the reporting period. 

(1) The general information specified in paragraphs 

(b)(1)(i) through (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 facility, the information in 

paragraphs (b)(2)(i) through (b)(2)(ii) of this section. 

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(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 affected 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 

during the reporting period and the records required by 

paragraph (c)(1)(v) of this section for each well completion. 

(ii) Records of deviations specified in paragraph 

(c)(1)(ii) of this section that occurred during the reporting 

period. 

(3) For each centrifugal compressor affected facility, the 

information specified in paragraphs (b)(3)(i) and (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. 

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(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. 

(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. 

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(iii) Records of deviations specified in paragraph 

(c)(4)(v) of this section that occurred during the reporting 

period. 

(6) For each storage vessel affected facility, the 

information in paragraphs (b)(6)(i) through (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. 

(ii) Documentation that the VOC emission 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 

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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 claim that some of the 

information being submitted for performance tests is 

confidential business information (CBI) must submit a complete 

ERT file including information claimed to be CBI on a compact 

disk or other commonly used electronic storage media (including, 

but not limited to, flash drives) to EPA. The electronic media 

must be clearly marked as CBI and mailed to U.S. EPA/OAPQS/CORE 

CBI Office, Attention: WebFIRE Administrator, MD C404-02, 4930 

Old Page Rd., Durham, NC 27703. The same ERT file with the CBI 

omitted must be submitted to EPA via CDX as described earlier in 

this paragraph. At the discretion of the delegated authority, 

you must also submit these reports, including the confidential 

business information, to the delegated authority in the format 

specified by the delegated authority. 

(ii) All reports required by this subpart not subject to 

the requirements in paragraphs (1)(i) of this section must be 

sent to the Administrator at the appropriate address listed in 

§63.13 of this part. The Administrator or the delegated 

authority may request a report in any form suitable for the 

specific case (e.g., by commonly used electronic media such as 

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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. 

(i) Records identifying each well completion operation for 

each gas well affected facility; 

(ii) Records of deviations in cases where well completion 

operations with hydraulic fracturing were not performed in 

compliance with the requirements specified in §60.5375. 

(iii) Records required in §60.5375(b) or (f) for each well 

completion operation conducted for each gas well affected 

facility that occurred during the reporting period. You must 

maintain the records specified in paragraphs (c)(1)(iii)(A) and 

(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 

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flowback; duration of recovery to the flow line; duration of 

combustion; duration of venting; and specific reasons for 

venting in lieu of capture or combustion. The duration must be 

specified in hours of time. 

(B) For each gas well affected facility required to comply 

with the requirements of §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 

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. 

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(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 packing, 

whichever is later. 

(ii) Records of the date and time of each reciprocating 

compressor rod packing replacement. 

(iii) Records of deviations in cases where the reciprocating 

compressor was not operated in compliance with the requirements 

specified in §60.5385. 

(4) For each pneumatic controller affected facility, you 

must maintain the records identified in paragraphs (c)(4)(i) 

through (v) of this section. 

(i) Records of the date, location and manufacturer 

specifications for each pneumatic controller constructed, 

modified or reconstructed. 

(ii) Records of the demonstration that the use of pneumatic 

controller affected facilities with a natural gas bleed rate 

greater than 6 standard cubic feet per hour are required and the 

reasons why. 

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(iii) If the pneumatic controller is not located at a 

natural gas processing plant, records of the manufacturer’s 

specifications indicating that the controller is designed such 

that natural gas bleed rate is less than or equal to 6 standard 

cubic feet per hour. 

(iv) If the pneumatic controller is located at a natural 

gas processing plant, records of the documentation that the 

natural gas bleed rate is zero. 

(v) Records of deviations in cases where the pneumatic 

controller was not operated in compliance with the requirements 

specified in §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. 

(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 identification of the model or 

calculation methodology used to calculate the VOC emission rate. 

(iii) Records of deviations in cases where the storage 

vessel was not operated in compliance with the requirements 

specified in §§60.5395, 60.5411, 60.5412 and 60.5413. 

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(iv) For vessels that are skid-mounted or permanently 

attached to something that is mobile (such as trucks, railcars, 

barges or ships), records indicating the number of consecutive 

days that the vessel is located at a site in the oil and natural 

gas production segment, natural gas processing segment or 

natural gas transmission and storage segment. If a vessel is 

removed from a site and, within 30 days, is either returned to 

or replaced by another vessel at the site to serve the same or 

similar function, then the entire period since the original 

vessel was first located at the site, including the days when 

the storage vessel was removed, will be added to the count 

towards the number of consecutive days. 

(6) For each storage vessel or centrifugal compressor 

subject to the closed vent system inspection requirements of 

§60.5416(a)(1) and (2), records of each inspection. 

(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. 

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(9) For each closed vent system used to comply with this 

subpart that must operate with no detectable emissions, a record 

of the monitoring conducted in accordance with §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 §60.5412, records 

of minimum and maximum operating parameter values, continuous 

parameter monitoring system data, calculated averages of 

continuous parameter monitoring system data, results of all 

compliance calculations, and results of all inspections. 

§60.5421 What are my additional recordkeeping requirements for 

my affected facility subject to VOC requirements for onshore 

natural gas processing plants? 

(a) You must comply with the requirements of paragraph (b) 

of this section in addition to the requirements of §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 

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identification, marked with the equipment identification number, 

must be attached to the leaking equipment. The identification on 

the pressure relief device may be removed after it has been 

repaired. 

(2) When each leak is detected as specified in 

§60.5401(b)(2), the following information must be recorded in a 

log and shall be kept for 2 years in a readily accessible 

location: 

(i) The instrument and operator identification numbers and 

the equipment identification number. 

(ii) The date the leak was detected and the dates of each 

attempt to repair the leak. 

(iii) Repair methods applied in each attempt to repair the 

leak. 

(iv) ”Above 500 ppm” if the maximum instrument reading 

measured by the methods specified in paragraph (a) of this 

section after each repair attempt is 500 ppm or greater. 

(v) ”Repair delayed” and the reason for the delay if a leak 

is not repaired within 15 calendar days after discovery of the 

leak. 

(vi) The signature of the owner or operator (or designate) 

whose decision it was that repair could not be effected without 

a process shutdown. 

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(vii) The expected date of successful repair of the leak if 

a leak is not repaired within 15 days. 

(viii) Dates of process unit shutdowns that occur while the 

equipment is unrepaired. 

(ix) The date of successful repair of the leak. 

(x) A list of identification numbers for equipment that are 

designated for no detectable emissions under the provisions of 

§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). 

(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 those pressure relief devices designated 

for no detectable emissions under the provisions of §60.482– 

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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 reports 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 required 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. 

(b) You must submit a report of excess emissions to the 

Administrator in your annual report if you had excess emissions 

during the reporting period. For the purpose of these reports, 

excess emissions are defined as: 

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(1) Any 24-hour period (at consistent intervals) during 

which the average sulfur emission reduction efficiency (R) is 

less than the minimum required efficiency (Z). 

(2) For any affected facility electing to comply with the 

provisions of §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 H2S in the acid gas (expressed as 

sulfur) you must keep, for the life of the facility, an analysis 

demonstrating that the facility's design capacity is less than 2 

LT/D of H2S expressed as sulfur. 

(d) If you elect to comply with §60.5407(e) you must keep, 

for the life of the facility, a record demonstrating that the 

facility's design capacity is less than 150 LT/D of H2S expressed 

as sulfur. 

(e) The requirements of paragraph (b) of this section 

remain in force until and unless the EPA, in delegating 

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enforcement authority to a state under section 111(c) of the 

Act, approves reporting requirements or an alternative means of 

compliance surveillance adopted by such state. In that event, 

affected sources within the state will be relieved of obligation 

to comply with paragraph (b) of this section, provided that they 

comply with the requirements established by the state. 

§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 (H2S) and 

carbon dioxide (CO2) that has been separated from sour natural 

gas by a sweetening unit. 

 Affirmative defense means, in the context of an enforcement 

proceeding, a response or defense put forward by a defendant, 

regarding which the defendant has the burden of proof, and the 

merits of which are independently and objectively evaluated in a 

judicial or administrative proceeding. 

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Alaskan North Slope means the approximately 69,000 squaremile area extending from the Brooks Range to the Arctic Ocean. 

 API Gravity means the weight per unit volume of hydrocarbon 

liquids as measured by a system recommended by the American 

Petroleum Institute (API) and is expressed in degrees. 

 Bleed rate means the rate in standard cubic feet per hour 

at which natural gas is continuously vented (bleeds) from a 

pneumatic controller. 

 Centrifugal compressor means any machine for raising the 

pressure of a natural gas by drawing in low pressure natural gas 

and discharging significantly higher pressure natural gas by 

means of mechanical rotating vanes or impellers. Screw, sliding 

vane, and liquid ring compressors are not centrifugal 

compressors for the purposes of this subpart. 

 City gate means the delivery point at which natural gas is 

transferred from a transmission pipeline to the local gas 

utility. 

Completion combustion device means any ignition device, 

installed horizontally or vertically, used in exploration and 

production operations to combust otherwise vented emissions from 

completions. 

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 Compressor station means any permanent combination of one 

or more compressors that move natural gas at increased pressure 

from fields, in transmission pipelines, or into storage. 

 Continuous bleed means a continuous flow of pneumatic 

supply natural gas to the process control device (e.g., level 

control, temperature control, pressure control) where the supply 

gas pressure is modulated by the process condition, and then 

flows to the valve controller where the signal is compared with 

the process set-point to adjust gas pressure in the valve 

actuator. 

 Custody transfer means the transfer of natural gas after 

processing and/or treatment in the producing operations, or from 

storage vessels or automatic transfer facilities or other such 

equipment, including product loading racks, to pipelines or any 

other forms of transportation. 

Dehydrator means a device in which an absorbent directly 

contacts a natural gas stream and absorbs water in a contact 

tower or absorption column (absorber). 

Deviation means any instance in which an affected source 

subject to this subpart, or an owner or operator of such a 

source: 

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(i) Fails to meet any requirement or obligation established 

by this subpart including, but not limited to, any emission 

limit, operating limit, or work practice standard; 

(ii) Fails to meet any term or condition that is adopted to 

implement an applicable requirement in this subpart and that is 

included in the operating permit for any affected source 

required to obtain such a permit; or 

(iii) Fails to meet any emission limit, operating limit, or 

work practice standard in this subpart during startup, shutdown, 

or malfunction, regardless of whether or not such failure is 

permitted by this subpart. 

 Delineation well means a well drilled in order to determine 

the boundary of a field or producing reservoir. 

Equipment means each pump, pressure relief device, openended valve or line, valve, and flange or other connector that 

is in VOC service or in wet gas service, and any device or 

system required by this subpart. 

 Field gas means feedstock gas entering the natural gas 

processing plant. 

Field gas gathering means the system used transport field 

gas from a field to the main pipeline in the area. 

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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 

cleanup and returning the well to production. The flowback 

period begins when material introduced into the well during the 

treatment returns to the surface immediately following hydraulic 

fracturing or refracturing. The flowback period ends with either 

well shut in or when the well is producing continuously to the 

flow line or to a storage vessel for collection, whichever 

occurs first. 

 Flow line means a pipeline used to transport oil and/or gas 

from the well to a processing facility, a mainline pipeline, reinjection, 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 independently if supplied 

with sufficient feed or raw materials and sufficient storage 

facilities for the products. 

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Gas well or natural gas well means an onshore well drilled 

principally for production of natural gas. 

 Hydraulic fracturing or refracturing means the process of 

directing pressurized fluids containing any combination of 

water, proppant, and any added chemicals to penetrate tight 

formations, such as shale or coal formations, that subsequently 

require high rate, extended flowback to expel fracture fluids 

and solids during completions. 

 Hydraulic refracturing means conducting a subsequent 

hydraulic fracturing operation at a well that has previously 

undergone a hydraulic fracturing operation. 

In light liquid service means that the piece of equipment 

contains a liquid that meets the conditions specified in 

§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 condensed into a liquid 

which is colorless, odorless, non-corrosive and non-toxic. 

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Low pressure gas well means a well with reservoir pressure 

and vertical well depth such that 0.445 times the reservoir 

pressure (in psia) minus 0.038 times the vertical well depth (in 

feet) minus 67.578 psia is less than the flow line pressure at 

the sales meter. 

Natural gas-driven pneumatic controller means a pneumatic 

controller powered by pressurized natural gas. 

Natural gas liquids means the hydrocarbons, such as ethane, 

propane, butane, and pentane that are extracted from field gas. 

Natural gas processing plant (gas plant) means any 

processing site engaged in the extraction of natural gas liquids 

from field gas, fractionation of mixed natural gas liquids to 

natural gas products, or both. A Joule-Thompson valve, a dew 

point depression valve, or an isolated or standalone JouleThompson skid is not a natural gas processing plant. 

Natural gas transmission means the pipelines used for the 

long distance transport of natural gas (excluding processing). 

Specific equipment used in natural gas transmission includes the 

land, mains, valves, meters, boosters, regulators, storage 

vessels, dehydrators, compressors, and their driving units and 

appurtenances, and equipment used for transporting gas from a 

production plant, delivery point of purchased gas, gathering 

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system, storage area, or other wholesale source of gas to one or 

more distribution area(s). 

 Nonfractionating plant means any gas plant that does not 

fractionate mixed natural gas liquids into natural gas products. 

Non natural gas-driven pneumatic controller means an 

instrument that is actuated using other sources of power than 

pressurized natural gas; examples include solar, electric, and 

instrument air. 

Onshore means all facilities except those that are located 

in the territorial seas or on the outer continental shelf. 

 Pneumatic controller means an automated instrument used for 

maintaining a process condition such as liquid level, pressure, 

delta-pressure and temperature. 

 Pressure vessel means a storage vessel that is used to 

store liquids or gases and is designed not to vent to the 

atmosphere as a result of compression of the vapor headspace in 

the pressure vessel during filling of the pressure vessel to its 

design capacity. 

 Process unit means components assembled for the extraction 

of natural gas liquids from field gas, the fractionation of the 

liquids into natural gas products, or other operations 

associated with the processing of natural gas products. A 

process unit can operate independently if supplied with 

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sufficient feed or raw materials and sufficient storage 

facilities for the products. 

 Reciprocating compressor means a piece of equipment that 

increases the pressure of a process gas by positive 

displacement, employing linear movement of the driveshaft. 

Reciprocating compressor rod packing means a series of 

flexible rings in machined metal cups that fit around the 

reciprocating compressor piston rod to create a seal limiting 

the amount of compressed natural gas that escapes to the 

atmosphere. 

Reduced emissions completion means a well completion 

following fracturing or refracturing where gas flowback that is 

otherwise vented is captured, cleaned, and routed to the flow 

line or collection system, re-injected into the well or another 

well, used as an on-site fuel source, or used for other useful 

purpose that a purchased fuel or raw material would serve, with 

no direct release to the atmosphere. 

Reduced sulfur compounds means H2S, carbonyl sulfide (COS), 

and carbon disulfide (CS2). 

 Responsible official means one of the following: 

(1) For a corporation: a president, secretary, treasurer, 

or vice-president of the corporation in charge of a principal 

business function, or any other person who performs similar 

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policy or decision-making functions for the corporation, or a 

duly authorized representative of such person if the 

representative is responsible for the overall operation of one 

or more manufacturing, production, or operating facilities 

applying for or subject to a permit and either: 

(i) The facilities employ more than 250 persons or have 

gross annual sales or expenditures exceeding $25 million (in 

second quarter 1980 dollars); or 

(ii) The delegation of authority to such representatives is 

approved in advance by the permitting authority; 

(2) For a partnership or sole proprietorship: a general 

partner or the proprietor, respectively; 

(3) For a municipality, State, Federal, or other public 

agency: Either a principal executive officer or ranking elected 

official. For the purposes of this part, a principal executive 

officer of a Federal agency includes the chief executive officer 

having responsibility for the overall operations of a principal 

geographic unit of the agency (e.g., a Regional Administrator of 

EPA); or 

(4) For affected facilities: 

(i) The designated representative in so far as actions, 

standards, requirements, or prohibitions under title IV of the 

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Clean Air Act or the regulations promulgated thereunder are 

concerned; or 

(ii) The designated representative for any other purposes 

under part 60. 

Routed to a process or route to a process means the 

emissions are conveyed via a closed vent system to any enclosed 

portion of a process unit where the emissions are predominantly 

recycled and/or consumed in the same manner as a material that 

fulfills the same function in the process and/or transformed by 

chemical reaction into materials that are not regulated 

materials and/or incorporated into a product; and/or recovered. 

Salable quality gas means natural gas that meets the 

composition, moisture, or other limits set by the purchaser of 

the natural gas, regardless of whether such gas is sold. 

 Storage vessel means a unit that is constructed primarily 

of nonearthen materials (such as wood, concrete, steel, 

fiberglass, or plastic) which provides structural support and is 

designed to contain an accumulation of liquids or other 

materials. The following are not considered storage vessels: 

(1) Vessels that are skid-mounted or permanently attached 

to something that is mobile (such as trucks, railcars, barges or 

ships), and are intended to be located at a site for less than 

180 consecutive days. If you do not keep or are not able to 

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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 original vessel was first located 

at the site. 

(2) Process vessels such as surge control vessels, bottoms 

receivers or knockout vessels. 

(3) Pressure vessels designed to operate in excess of 204.9 

kilopascals and without emissions to the atmosphere. 

Sulfur production rate means the rate of liquid sulfur 

accumulation from the sulfur recovery unit. 

Sulfur recovery unit means a process device that recovers 

element sulfur from acid gas. 

 Surface site means any combination of one or more graded 

pad sites, gravel pad sites, foundations, platforms, or the 

immediate physical location upon which equipment is physically 

affixed. 

 Sweetening unit means a process device that removes 

hydrogen sulfide and/or carbon dioxide from the sour natural gas 

stream. 

Total Reduced Sulfur (TRS) means the sum of the sulfur 

compounds hydrogen sulfide, methyl mercaptan, dimethyl sulfide, 

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and dimethyl disulfide as measured by Method 16 of appendix A to 

part 60 of this chapter. 

 Total SO2 equivalents means the sum of volumetric or mass 

concentrations of the sulfur compounds obtained by adding the 

quantity existing as SO2 to the quantity of SO2 that would be 

obtained if all reduced sulfur compounds were converted to SO2 

(ppmv or kg/dscm (lb/dscf)). 

Underground storage vessel means a storage vessel stored 

below ground. 

Well means an oil or gas well, a hole drilled for the 

purpose of producing oil or gas, or a well into which fluids are 

injected. 

 Well completion means the process that allows for the 

flowback of petroleum or natural gas from newly drilled wells to 

expel drilling and reservoir fluids and tests the reservoir flow 

characteristics, which may vent produced hydrocarbons to the 

atmosphere via an open pit or tank. 

Well completion operation means any well completion with 

hydraulic fracturing or refracturing occurring at a gas well 

affected facility. 

Well site means one or more areas that are directly 

disturbed during the drilling and subsequent operation of, or 

affected by, production facilities directly associated with any 

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oil well, gas well, or injection well and its associated well 

pad. 

Wellhead means the piping, casing, tubing and connected 

valves protruding above the earth’s surface for an oil and/or 

natural gas well. The wellhead ends where the flow line connects 

to a wellhead valve. The wellhead does not include other 

equipment at the well site except for any conveyance through 

which gas is vented to the atmosphere. 

 Wildcat well means a well outside known fields or the first 

well drilled in an oil or gas field where no other oil and gas 

production exists. 

Table 1 to Subpart OOOO of part 60 – Required Minimum Initial SO2 

Emission Reduction Efficiency (Zi) 

H2S 

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 88.51X0.0101Y0.0125 or 99.9, whichever is

smaller 

20<Y<50 79.0 88.5X0.0101Y0.0125 or 97.9, whichever

is smaller 

97.9 

10<Y<20 79.0 88.5X0.0101Y0.0125 

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 SO2 

Emission Reduction Efficiency (Zc) 

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H2S 

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 85.35X0.0144Y0.0128 or 99.9, whichever is

smaller 

20<Y<50 74.0 85.35X0.0144Y0.0128 or 97.9, whichever

is smaller 

97.5 

10<Y<20 74.0 85.35X0.0144Y0.0128 

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.

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 H2S 

in the acid gas), expressed as sulfur, Mg/D(LT/D), rounded to

one decimal place.

Y = The sulfur content of the acid gas from the sweetening unit,

expressed as mole percent H2S (dry basis) rounded to one decimal

place.

Z = The minimum required sulfur dioxide (SO2) emission reduction

efficiency, expressed as percent carried to one decimal place. Zi 

refers to the reduction efficiency required at the initial

performance test. Zc refers to the reduction efficiency required

on a continuous basis after compliance with Zi has been 

demonstrated. 

Table 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? Explanation 

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§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).

§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. 

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§60.19 General 

notification and 

reporting

requirement 

Yes 

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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 owner or operator of a 

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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 

hydrocarbon 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 

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other circumstances, the owner or operator shall calculate the 

maximum throughput used to determine whether a facility is a 

major source in accordance with the requirements specified in 

paragraph (a)(1)(i)(B) of this section. 

(A) The maximum natural gas or hydrocarbon liquid 

throughput is the average of the annual natural gas or 

hydrocarbon liquid throughput for the 3 years prior to [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 THE 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 

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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. 

(2) Facilities that process, upgrade, or store hydrocarbon 

liquids. 

* * * * * 

(b) * * * 

(1) * * * 

(i) Each glycol dehydration unit as specified in paragraphs 

(b)(1)(i)(A) through (C) of this section. 

(A) Each large glycol dehydration unit; 

(B) Each small glycol dehydration unit for which 

construction commenced on or before August 23, 2011, is an 

existing small glycol dehydration unit; and 

(C) Each small glycol dehydration unit for which 

construction commenced after August 23, 2011, is a new small 

glycol dehydration unit. 

* * * * * 

(c) Any source that determines it is not a major source but 

has actual emissions of 5 tons per year or more of a single HAP, 

or 12.5 tons per year or more of a combination of HAP (i.e., 50 

percent of the major source thresholds), shall update its major 

source determination within 1 year of the prior determination or 

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[INSERT DATE OF PUBLICATION IN THE FEDERAL REGISTER], whichever 

is later, and each year thereafter, using gas composition data 

measured during the preceding 12 months. 

* * * * * 

(f) The owner or operator of an affected major source shall 

achieve compliance with the provisions of this subpart by the 

dates specified in paragraphs (f)(1), (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 operator of an affected major source, 

the construction or reconstruction of which commenced before 

February 6, 1998, shall achieve compliance with the applicable 

provisions of this subpart no later than June 17, 2002, except 

as provided for in §63.6(i). The owner or operator of an area 

source, the construction or reconstruction of which commenced 

before February 6, 1998, that increases its emissions of (or its 

potential to emit) HAP such that the source becomes a major 

source that is subject to this subpart shall comply with this 

subpart 3 years after becoming a major source. 

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(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 or 

after February 6, 1998, shall achieve compliance with the 

applicable provisions of this subpart immediately upon initial 

startup or June 17, 1999, whichever date is later. Area sources, 

other than production field facilities identified in (f)(9) of 

this section, the construction or reconstruction of which 

commences on or after February 6, 1998, that become major 

sources shall comply with the provisions of this standard 

immediately upon becoming a major source. 

* * * * * 

(7) Each affected existing small glycol dehydration unit, 

as defined in §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 

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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 

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) of the definition for “major 

source” to read as follows: 

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§63.761 Definitions. 

* * * * * 

 Affirmative defense means, in the context of an enforcement 

proceeding, a response or defense put forward by a defendant, 

regarding which the defendant has the burden of proof, and the 

merits of which are independently and objectively evaluated in a 

judicial or administrative proceeding. 

* * * * * 

 Associated equipment, as used in this subpart and as 

referred to in section 112(n)(4) of the Act, means equipment 

associated with an oil or natural gas exploration or production 

well, and includes all equipment from the wellbore to the point 

of custody transfer, except glycol dehydration units and storage 

vessels. 

* * * * * 

BTEX means benzene, toluene, ethyl benzene and xylene. 

* * * * * 

Flare means a thermal oxidation system using an open flame 

(i.e., without enclosure). 

* * * * * 

Glycol dehydration unit baseline operations means 

operations representative of the large glycol dehydration unit 

operations as of June 17, 1999 and the small glycol dehydrator 

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unit operations as of August 23, 2011. For the purposes of this 

subpart, for determining the percentage of overall HAP emission 

reduction attributable to process modifications, baseline 

operations shall be parameter values (including, but not limited 

to, glycol circulation rate or glycol-HAP absorbency) that 

represent actual long-term conditions (i.e., at least 1 year). 

Glycol dehydration units in operation for less than 1 year shall 

document that the parameter values represent expected long-term 

operating conditions had process modifications not been made. 

* * * * * 

Large glycol dehydration unit means a glycol dehydration 

unit with an actual annual average natural gas flowrate equal to 

or greater than 85 thousand standard cubic meters per day and 

actual annual average benzene emissions equal to or greater than 

0.90 Mg/yr, determined according to §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 

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emissions from all HAP emission units shall be aggregated for a 

major source determination. 

* * * * * 

 Responsible official means one of the following: 

(1) For a corporation: a president, secretary, treasurer, 

or vice-president of the corporation in charge of a principal 

business function, or any other person who performs similar 

policy or decision-making functions for the corporation, or a 

duly authorized representative of such person if the 

representative is responsible for the overall operation of one 

or more manufacturing, production, or operating facilities 

applying for or subject to a permit and either: 

(i) The facilities employ more than 250 persons or have 

gross annual sales or expenditures exceeding $25 million (in 

second quarter 1980 dollars); or 

(ii) The delegation of authority to such representatives is 

approved in advance by the permitting authority; 

(2) For a partnership or sole proprietorship: a general 

partner or the proprietor, respectively; 

(3) For a municipality, State, Federal, or other public 

agency: Either a principal executive officer or ranking elected 

official. For the purposes of this part, a principal executive 

officer of a Federal agency includes the chief executive officer 

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having responsibility for the overall operations of a principal 

geographic unit of the agency (e.g., a Regional Administrator of 

EPA); or 

(4) For affected sources: 

(i) The designated representative in so far as actions, 

standards, requirements, or prohibitions under title IV of the 

Act or the regulations promulgated thereunder are concerned; and 

(ii) The designated representative for any other purposes 

under part 70. 

* * * * * 

Small glycol dehydration unit means a glycol dehydration 

unit, located at a major source, with an actual annual average 

natural gas flowrate less than 85 thousand standard cubic meters 

per day or actual annual average benzene emissions less than 

0.90 Mg/yr, determined according to §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. 

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* * * * * 

12. Section 63.762 is revised to read as follows: 

§63.762 Affirmative defense for violations of emission standards 

during malfunction. 

(a) The provisions set forth in this subpart shall apply at 

all times. 

(b) [Reserved] 

(c) [Reserved] 

(d) In response to an action to enforce the standards set 

forth in this subpart, you may assert an affirmative defense to 

a claim for civil penalties for violations of such standards 

that are caused by malfunction, as defined in 40 CFR 63.2. 

Appropriate penalties may be assessed; however, if you fail to 

meet your burden of proving all of the requirements in the 

affirmative defense, the affirmative defense shall not be 

available for claims for injunctive relief. 

(1) To establish the affirmative defense in any action to 

enforce such a standard, you must timely meet the reporting 

requirements in paragraph (d)(2) of this section, and must prove 

by a preponderance of evidence that: 

(i) The violation: 

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(A) Was caused by a sudden, infrequent, and unavoidable 

failure of air pollution control equipment, process equipment, 

or a process to operate in a normal or usual manner; and 

(B) Could not have been prevented through careful planning, 

proper design or better operation and maintenance practices; and 

(C) Did not stem from any activity or event that could have 

been foreseen and avoided, or planned for; and 

(D) Was not part of a recurring pattern indicative of 

inadequate design, operation, or maintenance; and 

(ii) Repairs were made as expeditiously as possible when a 

violation occurred. Off-shift and overtime labor were used, to 

the extent practicable to make these repairs; and 

(iii) The frequency, amount and duration of the violation 

(including any bypass) were minimized to the maximum extent 

practicable; and 

(iv) If the violation resulted from a bypass of control 

equipment or a process, then the bypass was unavoidable to 

prevent loss of life, personal injury, or severe property 

damage; and 

(v) All possible steps were taken to minimize the impact of 

the violation on ambient air quality, the environment, and human 

health; and 

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(vi) All emissions monitoring and control systems were kept 

in operation if at all possible, consistent with safety and good 

air pollution control practices; and 

(vii) All of the actions in response to the violation were 

documented by properly signed, contemporaneous operating logs; 

and 

(viii) At all times, the affected source was operated in a 

manner consistent with good practices for minimizing emissions; 

and 

(ix) A written root cause analysis has been prepared, the 

purpose of which is to determine, correct, and eliminate the 

primary causes of the malfunction and the violation resulting 

from the malfunction event at issue. The analysis shall also 

specify, using best monitoring methods and engineering judgment, 

the amount of any emissions that were the result of the 

malfunction. 

(2) Report. The owner or operator seeking to assert an 

affirmative defense shall submit a written report to the 

Administrator with all necessary supporting documentation, that 

it has met the requirements set forth in paragraph (d)(1) of 

this section. This affirmative defense report shall be included 

in the first periodic compliance, deviation report or excess 

emission report otherwise required after the initial occurrence 

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of the violation of the relevant standard (which may be the end 

of any applicable averaging period). If such compliance, 

deviation report or excess emission report is due less than 45 

days after the initial occurrence of the violation, the 

affirmative defense report may be included in the second 

compliance, deviation report or excess emission report due after 

the initial occurrence of the violation of the relevant 

standard. 

13. Section 63.764 is amended by: 

a. Revising paragraph (e)(1) introductory text; 

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 detected, it is a violation of this standard 

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to fail to take action to repair the leak(s) within the 

specified time. If action is taken to repair the leak(s) within 

the specified time, failure of that action to successfully 

repair the leak(s) is not a violation of this standard. However, 

if the repairs are unsuccessful, and a leak is detected, the 

owner or operator shall take further action as required by the 

applicable provisions of this subpart. 

(j) At all times the owner or operator must operate and 

maintain any affected source, including associated air pollution 

control equipment and monitoring equipment, in a manner 

consistent with safety and good air pollution control practices 

for minimizing emissions. Determination of whether such 

operation and maintenance procedures are being used will be 

based on information available to the Administrator which may 

include, but is not limited to, monitoring results, review of 

operation and maintenance procedures, review of operation and 

maintenance records, and inspection of the source. 

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. 

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(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 process vent, the 

owner or operator shall control air emissions by either 

paragraph (b)(1)(i), (ii), or (iii) of this section. 

(i) The owner or operator of a large glycol dehydration 

unit, as defined in §63.761, shall connect the process vent to a 

control device or a combination of control devices through a 

closed-vent system. The closed-vent system shall be designed and 

operated in accordance with the requirements of §63.771(c). The 

control device(s) shall be designed and operated in accordance 

with the requirements 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 requirements of 

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§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 in 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. 

ଵ ெ௚ כ Equation 1 ௗ௔௬௦ כ 365 כ ݄ܶݑ݋ݎ݄݃ݐݑ݌ כ ܥ௜,஻்ா௑ ൌ 3.28ݔ10ିସ ܮܧ஻்ா௑ ௬௥ ଵ௫ଵ଴ల ௚௥௔௠௦

Where: 

ELBTEX = 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 

Ci,BTEX = average annual BTEX concentration of the natural gas at 

the inlet to the glycol dehydration unit, ppmv. 

ଵ ெ௚ כ Equation 2 ௗ௔௬௦ כ 365 כ ݄ܶݑ݋ݎ݄݃ݐݑ݌ כ ܥ௜,஻்ா௑ ൌ 4.66ݔ10ି ଺ܮܧ஻்ா௑ ௬௥ ଵ௫ଵ଴ల ௚௥௔௠௦

Where: 

ELBTEX = Unit-specific BTEX emission limit, megagrams per year; 

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4.66x10-6 = BTEX emission limit, grams BTEX/standard cubic meter 

-ppmv; 

Throughput = Annual average daily natural gas throughput, 

standard cubic meters per day 

Ci,BTEX = average annual BTEX concentration of the natural gas at 

the inlet to the glycol dehydration unit, ppmv. 

(A) Connect the process vent to a control device or 

combination of control devices through a closed-vent system. The 

closed vent system shall be designed and operated in accordance 

with the requirements of §63.771(c). The control device(s) shall 

be designed and operated 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 combination of process modifications 

and one or more control devices through the requirements 

specified in paragraphs (b)(1)(iii)(A) and (B) of this section. 

(D) Demonstrate that the emissions limit is met through 

actual uncontrolled operation of the small glycol dehydration 

unit. Document operational parameters in accordance with the 

requirements specified in §63.771(e) and emissions in accordance 

with the requirements specified in §63.772(b)(2). 

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* * * * * 

(c) * * * 

(2) The owner or operator shall demonstrate, to the 

Administrator's satisfaction, that the total HAP emissions to 

the atmosphere from the large glycol dehydration unit process 

vent are reduced by 95.0 percent through process modifications, 

or a combination of process modifications and one or more 

control devices, in accordance with the requirements specified 

in §63.771(e). 

(3) Control of HAP emissions from a GCG separator (flash 

tank) vent is not required if the owner or operator 

demonstrates, to the Administrator's satisfaction, that total 

emissions to the atmosphere from the glycol dehydration unit 

process vent are reduced by one of the levels specified in 

paragraph (c)(3)(i) through (iv) of this section, through the 

installation and operation of controls as specified in paragraph 

(b)(1) of this section. 

(i) For any large glycol dehydration unit, HAP emissions 

are reduced by 95.0 percent or more. 

(ii) For any large glycol dehydration unit, benzene 

emissions are reduced to a level less than 0.90 megagrams per 

year. 

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(iii) For each existing small glycol dehydration unit, BTEX 

emissions are reduced to a level less than the limit calculated 

by Equation 1 of paragraph (b)(1)(iii) of this section. 

(iv) For each new small glycol dehydration unit, BTEX 

emissions are reduced to a level less than the limit calculated 

by Equation 2 of paragraph (b)(1)(iii) of this section. 

15. Section 63.766 is amended by: 

a. Adding paragraph (b)(3); and 

b. Revising paragraph (d) to read as follows: 

§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 

which the owner or operator is subject to and controlled under 

the requirements specified in 40 CFR part 60, subparts Kb or 

OOOO; or is subject to and controlled under the requirements 

specified under 40 CFR part 63 subparts G or CC. Storage vessels 

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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 subpart H of this 

part; or is subject to and controlled under the requirements 

specified in 40 CFR part 60, subpart OOOO. Ancillary equipment 

and compressors subject to and controlled under 40 CFR part 60, 

subpart OOOO shall submit the periodic reports specified in 

§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 

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or greater is measured. A leak detected from a valve at a source 

constructed on or before August 23, 2011 shall be repaired in 

accordance with the schedule in §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). 

17. Section 63.771 is amended by: 

a. Revising paragraph (c)(1) introductory text; 

b. Revising the heading of paragraph (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; 

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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 dehydration units. Owners and operators of small glycol 

dehydration units, shall comply with the control device 

requirements in paragraph (f) of this section. 

(1) * * * 

(i) * * * 

(C) Operates at a minimum temperature of 760 degrees C, 

provided the control device has demonstrated, under §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 

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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 §63.761, 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 emissions 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. 

* * * * * 

(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 §63.774(b)(7)(ix). The schedule for 

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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 modifications and one or more control devices. If a 

combination of process modifications and one or more control 

devices are used, the owner or operator shall also establish the 

emission reduction to be achieved by the control device to 

achieve an overall HAP emission reduction of 95.0 percent for 

the glycol dehydration unit process vent or, if applicable, the 

BTEX limit determined in §63.765(b)(1)(iii) for the small glycol 

dehydration unit process vent. Only modifications in glycol 

dehydration unit operations directly related to process changes, 

including but not limited to changes in glycol circulation rate 

or glycol-HAP absorbency, shall be allowed. Changes in the inlet 

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gas characteristics or natural gas throughput rate shall not be 

considered in determining the overall emission reduction due to 

process modifications. 

(3) The owner or operator that achieves a 95.0 percent HAP 

emission reduction or meets the BTEX limit determined in 

§63.765(b)(1)(iii), as applicable, using process modifications 

alone shall comply with paragraph (e)(3)(i) of this section. The 

owner or operator that achieves a 95.0 percent HAP emission 

reduction or meets the BTEX limit determined in 

§63.765(b)(1)(iii), as applicable, using a combination of 

process modifications and one or more control devices shall 

comply with paragraphs (e)(3)(i) and (e)(3)(ii) of this section. 

* * * * * 

(ii) The owner or operator shall comply with the control 

device requirements specified in paragraph (d) or (f) of this 

section, as applicable, except that the emission reduction or 

limit achieved shall be the emission reduction or limit 

specified for the control device(s) in paragraph (e)(2) of this 

section. 

(f) Control device requirements for small glycol 

dehydration units. (1) The control device used to meet BTEX the 

emission limit calculated in §63.765(b)(1)(iii) shall be one of 

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the control devices specified in paragraphs (f)(1)(i) through 

(iii) of this section. 

(i) An enclosed combustion device (e.g., thermal vapor 

incinerator, catalytic vapor incinerator, boiler, or process 

heater) that is designed and operated to meet the levels 

specified in paragraphs (f)(1)(i)(A) or (B) of this section. If 

a boiler or process heater is used as the control device, then 

the vent stream shall be introduced into the flame zone of the 

boiler or process heater. 

(A) The mass content of BTEX in the gases vented to the 

device is reduced as determined in accordance with the 

requirements of §63.772(e). 

(B) The concentration of either TOC or total HAP in the 

exhaust gases at the outlet of the device is reduced to a level 

equal to or less than 20 parts per million by volume on a dry 

basis corrected to 3 percent oxygen as determined in accordance 

with the requirements of §63.772(e). 

(ii) A vapor recovery device (e.g., carbon adsorption 

system or condenser) or other non-destructive control device 

that is designed and operated to reduce the mass content of BTEX 

in the gases vented to the device as determined in accordance 

with the requirements of §63.772(e). 

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(iii) A flare, as defined in §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) Each control device used to comply with this subpart 

shall be operating at all times. An owner or operator may vent 

more than one unit to a control device used to comply with this 

subpart. 

(ii) For each control device monitored in accordance with 

the requirements of §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 

section, 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; 

b. Revising paragraph (b)(1)(ii); 

c. Revising paragraph (b)(2); 

d. Revising paragraph (c)(6)(i); 

e. Adding paragraph (d); 

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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. Revising paragraph (g)(3); 

w. Adding paragraph (h); and 

x. Adding paragraph (i) to read as follows: 

§63.772 Test methods, compliance procedures, and compliance 

demonstrations. 

* * * * * 

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(b) Determination of glycol dehydration unit flowrate, 

benzene emissions, or BTEX emissions. The procedures of this 

paragraph shall be used by an owner or operator to determine 

glycol dehydration unit natural gas flowrate, benzene emissions, 

or BTEX emissions. 

(1) * * * 

(ii) The owner or operator shall document, to the 

Administrator's satisfaction, the actual annual average natural 

gas flowrate to the glycol dehydration unit. 

(2) The determination of actual average benzene or BTEX 

emissions from a glycol dehydration unit shall be made using the 

procedures of either paragraph (b)(2)(i) or (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-GLYCalcTM , Version 

3.0 or higher, and the procedures presented in the associated 

GRI-GLYCalcTM Technical Reference Manual. Inputs to the model 

shall be representative of actual operating conditions of the 

glycol dehydration unit and may be determined using the 

procedures documented in the Gas Research Institute (GRI) report 

entitled “Atmospheric Rich/Lean Method for Determining Glycol 

Dehydrator Emissions” (GRI–95/0368.1); or 

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(ii) The owner or operator shall determine an average mass 

rate of benzene or BTEX emissions in kilograms per hour through 

direct measurement using the methods in §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 Method 21 of 40 CFR part 60, appendix A, except the 

instrument response factor criteria in section 3.1.2(a) of 

Method 21 shall be for the average composition of the process 

fluid, not each individual volatile organic compound in the 

stream. For process streams that contain nitrogen, air, or other 

inert gases that are not organic hazardous air pollutants or 

volatile organic compounds, the average stream response factor 

shall be calculated on an inert-free basis. 

* * * * * 

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(d) Test procedures and compliance demonstrations for 

small glycol dehydration units. This paragraph applies to the 

test procedures for small dehydration units. 

(1) If the owner or operator is using a control device to 

comply with the emission limit in §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 the glycol dehydration unit BTEX emissions as 

specified in paragraphs (d)(2)(i) through (iii) of this section. 

Compliance is demonstrated if the BTEX emissions determined as 

specified in paragraphs (d)(2)(i) through (iii) are less than 

the emission limit calculated using the equation in 

§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. 

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(ii) The gas volumetric flowrate shall be determined using 

Method 2, 2A, 2C, or 2D, 40 CFR part 60, appendix A, as 

appropriate. 

(iii) The BTEX emissions from the outlet of the glycol 

dehydration unit process vent shall be determined using the 

procedures specified in paragraph (e)(3)(v) of this section. As 

an alternative, the mass rate of BTEX at the outlet of the 

glycol dehydration unit process vent may be calculated using the 

model GRI-GLYCalcTM , Version 3.0 or higher, and the procedures 

presented in the associated GRI-GLYCalcTM Technical Reference 

Manual. Inputs to the model shall be representative of actual 

operating conditions of the glycol dehydration unit and shall be 

determined using the procedures documented in the Gas Research 

Institute (GRI) report entitled “Atmospheric Rich/Lean Method 

for Determining Glycol Dehydrator Emissions” (GRI–95/0368.1). 

When the BTEX mass rate is calculated for glycol dehydration 

units using the model GRI-GLYCalcTM , all BTEX measured by Method 

18, 40 CFR part 60, appendix A, shall be summed. 

(e) Control device performance test procedures. This 

paragraph applies to the performance testing of control devices. 

The owners or operators shall demonstrate that a control device 

achieves the performance requirements of §63.771(d)(1), 

(e)(3)(ii) or (f)(1) using a performance test as specified in 

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paragraph (e)(3) of this section. Owners or operators using a 

condenser have the option to use a design analysis as specified 

in paragraph (e)(4) of this section. The owner or operator may 

elect to use the alternative procedures in paragraph (e)(5) of 

this section for performance testing of a condenser used to 

control emissions from a glycol dehydration unit process vent. 

Flares shall meet the provisions in paragraph (e)(2) of this 

section. As an alternative to conducting a performance test 

under this section for combustion control devices, a control 

device that can be 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, as specified in 

paragraph (h) of this section, can be used. 

(1) * * * 

(i) Except as specified in paragraph (e)(2) of this 

section, a flare, as defined in §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 

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vent stream is introduced with the primary fuel or is used as 

the primary fuel; 

(iv) Except for control devices used for small glycol 

dehydration units, a boiler or process heater burning hazardous 

waste for which the owner or operator has either been issued a 

final permit under 40 CFR part 270 and complies with the 

requirements of 40 CFR part 266, subpart H; or has certified 

compliance with the interim status requirements of 40 CFR part 

266, subpart H; 

(v) Except for control devices used for small glycol 

dehydration units, a hazardous waste incinerator for which the 

owner or operator has been issued a final permit under 40 CFR 

part 270 and complies with the requirements of 40 CFR part 264, 

subpart O; or has certified compliance with the interim status 

requirements of 40 CFR part 265, subpart O. 

* * * * * 

(2) An owner or operator shall design and operate each 

flare, as defined in §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), 

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(e)(3)(ii) or (f)(1), the owner or operator shall use the test 

methods and procedures specified in paragraphs (e)(3)(i) through 

(v) of this section. The initial and periodic performance tests 

shall be conducted according to the schedule specified in 

paragraph (e)(3)(vi) of this section. 

(i) * * * 

(B) To determine compliance with the enclosed combustion 

device total HAP concentration limit specified in 

§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 

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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 Method 301, 

40 CFR part 63, appendix A. The following procedures shall be 

used to calculate BTEX emissions: 

(A) The minimum sampling time for each run shall be 1 hour 

in which either an integrated sample or a minimum of four grab 

samples shall be taken. If grab sampling is used, then the 

samples shall be taken at approximately equal intervals in time, 

such as 15-minute intervals during the run. 

(B) The mass rate of BTEX (Eo) shall be computed using the 

equations and procedures specified in paragraphs (e)(3)(v)(B)(1) 

and (2) of this section. 

(1) The following equation shall be used: 

Where:
 

Eo= Mass rate of BTEX at the outlet of the control device, dry
 

basis, kilogram per hour. 

Coj= Concentration of sample component j of the gas stream at the 

outlet of the control device, dry basis, parts per million by 

volume. 

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Moj= Molecular weight of sample component j of the gas stream at 

the outlet of the control device, gram/gram-mole. 

Qo= Flowrate of gas stream at the outlet of the control device, 

dry standard cubic meter per minute. 

K2= Constant, 2.494×10−6 (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 (e)(3)(v)(B)(1) of this 

section. 

(vi) The owner or operator shall conduct performance tests 

according to the schedule specified in paragraphs (e)(3)(vi)(A) 

and (B) of this section. 

(A) An initial performance test shall be conducted within 

180 days after the compliance date that is specified for each 

affected source in §63.760(f)(7) through (8), except that the 

initial performance test for existing combustion control devices 

(i.e., control devices installed on or before August 23, 2011) 

at major sources shall be conducted no later than [INSERT DATE 3 

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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 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 §63.775(d)(1)(ii). 

(B) Periodic performance tests shall be conducted for all 

control devices required to conduct initial performance tests 

except as specified in paragraphs (e)(3)(vi)(B)(1) and (2) of 

this section. The first periodic performance test shall be 

conducted no later than 60 months after the initial performance 

test required in paragraph (e)(3)(vi)(A) of this section. 

Subsequent periodic performance tests shall be conducted at 

intervals no longer than 60 months following the previous 

periodic performance test or whenever a source desires to 

establish a new operating limit. The periodic performance test 

results must be submitted in the next Periodic Report as 

specified in §63.775(e)(2)(xi). Combustion control devices 

meeting the criteria in either paragraph (e)(3)(vi)(B)(1) or (2) 

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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. 

(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. 

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* * * * * 

(5) As an alternative to the procedures in paragraph 

(e)(4)(i) of this section, an owner or operator may elect to use 

the procedures documented in the GRI report entitled, 

“Atmospheric Rich/Lean Method for Determining Glycol Dehydrator 

Emissions” (GRI–95/0368.1) as inputs for the model GRI-GLYCalcTM, 

Version 3.0 or higher, to generate a condenser performance 

curve. 

(f) Compliance demonstration for control device performance 

requirements. This paragraph applies to the demonstration of 

compliance with the control device performance requirements 

specified in §63.771(d)(1)(i), (e)(3) and (f)(1). Compliance 

shall be demonstrated using the requirements in paragraphs 

(f)(1) through (3) of this section. As an alternative, an owner 

or operator that installs a condenser as the control device to 

achieve the requirements specified in §63.771(d)(1)(ii), (e)(3) 

or (f)(1) may demonstrate compliance according to paragraph (g) 

of this section. An owner or operator may switch between 

compliance with paragraph (f) of this section and compliance 

with paragraph (g) of this section only after at least 1 year of 

operation in compliance with the selected approach. Notification 

of such a change in the compliance method shall be reported in 

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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 flowrate to the control 

device shall not be averaged. 

(3) Compliance with the operating parameter limit is 

achieved when the daily average of the monitoring parameter 

value calculated under paragraph (f)(2) of this section is 

either equal to or greater than the minimum or equal to or less 

than the maximum monitoring value established under paragraph 

(f)(1) of this section. For inlet gas flowrate, compliance with 

the operating parameter limit is achieved when the value is 

equal to or less than the value established under §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 assurance 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 

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operating. A monitoring system malfunction is any sudden, 

infrequent, not reasonably preventable failure of the monitoring 

system to provide valid data. Monitoring system failures that 

are caused in part by poor maintenance or careless operation are 

not malfunctions. Monitoring system repairs are required to be 

completed in response to monitoring system malfunctions and to 

return the monitoring system to operation as expeditiously as 

practicable. 

(5) Data recorded during monitoring system malfunctions, 

repairs associated with monitoring system malfunctions, or 

required monitoring system quality assurance or control 

activities may not be used in calculations used to report 

emissions or operating levels. All the data collected during all 

other required data collection periods must be used in assessing 

the operation of the control device and associated control 

system. 

(6) Except for periods of monitoring system malfunctions, 

repairs associated with monitoring system malfunctions, and 

required quality monitoring system quality assurance or quality 

control activities (including, as applicable, system accuracy 

audits and required zero and span adjustments), failure to 

collect required data is a deviation of the monitoring 

requirements. 

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(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 paragraphs (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. 

(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 

section. 

* * * * * 

(iii) Except as provided in paragraphs (g)(2)(iii)(A) and 

(B) of this section, at the end of each operating day, the owner 

or operator shall calculate the 365-day average HAP, or BTEX, 

emission reduction, as appropriate, from the condenser 

efficiencies as determined in paragraph (g)(2)(ii) of this 

section for the preceding 365 operating days. If the owner or 

operator uses a combination of process modifications and a 

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condenser in accordance with the requirements of §63.771(e), the 

365-day average HAP, or BTEX, emission reduction shall be 

calculated using the emission reduction achieved through process 

modifications and the condenser efficiency as determined in 

paragraph (g)(2)(ii) of this section, both for the previous 365 

operating days. 

(A) After the compliance dates specified in §63.760(f), an 

owner or operator with less than 120 days of data for 

determining average HAP, or BTEX, emission reduction, as 

appropriate, shall calculate the average HAP, or BTEX emission 

reduction, as appropriate, for the first 120 days of operation 

after the compliance dates. For sources required to meet the 

overall 95.0 percent reduction requirement, compliance is 

achieved if the 120-day average HAP emission reduction is equal 

to or greater than 90.0 percent. For sources required to meet 

the BTEX limit under §63.765(b)(1)(iii), compliance is achieved 

if the average BTEX emission reduction is at least 95.0 percent 

of the required 365-day value identified under paragraph (g)(1) 

of this section (i.e., at least 76.0 percent if the 365-day 

design value is 80.0 percent). 

(B) After 120 days and no more than 364 days of operation 

after the compliance dates specified in §63.760(f), the owner or 

operator shall calculate the average HAP emission reduction as 

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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 identified under paragraph (g)(1) of this 

section (i.e., at least 76.0 percent if the 365-day design value 

is 80.0 percent). 

(3) If the owner or operator has data for 365 days or more 

of operation, compliance is achieved based on the applicable 

criteria in paragraphs (g)(3)(i) or (ii) of this section. 

(i) For sources meeting the HAP emission reduction 

specified in §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 

reduction identified in paragraph (g)(1) of this section. 

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* * * * * 

(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. Propene 

(propylene) gas shall be used for the testing fuel. All fuel 

analyses shall be performed by an independent third-party 

laboratory (not affiliated with the control device manufacturer 

or fuel supplier). 

(i) 90 - 100 percent of maximum design rate (fixed rate). 

(ii) 70 - 100 - 70 percent (ramp up, ramp down). Begin the 

test at 70 percent of the maximum design rate. During the first 

5 minutes, incrementally ramp the firing rate to 100 percent of 

the maximum design rate. Hold at 100 percent for 5 minutes. In 

the 10-15 minute time range, incrementally ramp back down to 70 

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percent of the maximum design rate. Repeat three more times for 

a total of 60 minutes of sampling. 

(iii) 30 - 70 - 30 percent (ramp up, ramp down). Begin the 

test at 30 percent of the maximum design rate. During the first 

5 minutes, incrementally ramp the firing rate to 70 percent of 

the maximum design rate. Hold at 70 percent for 5 minutes. In 

the 10-15 minute time range, incrementally ramp back down to 30 

percent of the maximum design rate. Repeat three more times for 

a total of 60 minutes of sampling. 

(iv) 0 - 30 - 0 percent (ramp up, ramp down). Begin the 

test at 0 percent of the maximum design rate. During the first 5 

minutes, incrementally ramp the firing rate to 30 percent of the 

maximum design rate. Hold at 30 percent for 5 minutes. In the 

10-15 minute time range, incrementally ramp back down to 0 

percent of the maximum design rate. Repeat three more times for 

a total of 60 minutes of sampling. 

(3) All models employing multiple enclosures shall be 

tested simultaneously and with all burners operational. Results 

shall be reported for the each enclosure individually and for 

the average of the emissions from all interconnected combustion 

enclosures/chambers. Control device operating data shall be 

collected continuously throughout the performance test using an 

electronic Data Acquisition System and strip chart. Data shall 

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be submitted with the test report in accordance with paragraph 

(h)(8)(iii) of this section. 

(4) Inlet gas testing shall be conducted as specified in 

paragraphs (h)(4)(i) through (iii) of this section. 

(i) The inlet gas flow metering system shall be located in 

accordance with Method 2A, 40 CFR part 60, appendix A-1, (or 

other approved procedure) to measure inlet gas flowrate at the 

control device inlet location. The fitting for filling inlet gas 

sample containers shall be located a minimum of 8 pipe diameters 

upstream of any inlet gas flow monitoring meter. 

(ii) Inlet gas flowrate shall be determined using Method 

2A, 40 CFR part 60, appendix A-1. Record the start and stop 

reading for each 60-minute THC test. Record the inlet gas 

pressure and temperature at 5-minute intervals throughout each 

60-minute THC test. 

(iii) Inlet gas fuel sampling shall be conducted in 

accordance with the criteria in paragraphs (h)(4)(iii)(A) and 

(B) of this section. 

(A) At the inlet gas sampling location, securely connect a 

Silonite-coated stainless steel evacuated canister fitted with a 

flow controller sufficient to fill the canister over a 3 hour 

period. Filling shall be conducted as specified in the 

following: 

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(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 (H2), carbon monoxide (CO), carbon dioxide 

(CO2), nitrogen (N2), oxygen (O2) 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 (h)(5)(i) through (v) of this 

section. 

(i) Sampling and flowrate measured in accordance with the 

following: 

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(A) The outlet sampling location shall be a minimum of 4 

equivalent stack diameters downstream from the highest peak 

flame or any other flow disturbance, and a minimum of one 

equivalent stack diameter upstream of the exit or any other flow 

disturbance. A minimum of two sample ports shall be used. 

(B) Flowrate shall be measured using Method 1, 40 CFR part 

60, Appendix 1, for determining flow measurement traverse point 

location; and Method 2, 40 CFR part 60, Appendix 1, shall be 

used to measure duct velocity. If low flow conditions are 

encountered (i.e., velocity pressure differentials less than 

0.05 inches of water) during the performance test, a more 

sensitive manometer or other pressure measurement device shall 

be used to obtain an accurate flow profile. 

(ii) Molecular weight shall be determined as specified in 

paragraphs (h)(4)(iii)(B), (h)(5)(ii)(A), and (h)(5)(ii)(B) of 

this section. 

(A) An integrated bag sample shall be collected during the 

Method 4, 40 CFR part 60, Appendix A, moisture test. Analyze the 

bag sample using a gas chromatograph-thermal conductivity 

detector (GC-TCD) analysis meeting the following criteria: 

(1) Collect the integrated sample throughout the entire 

test, and collect representative volumes from each traverse 

location. 

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(2) The sampling line shall be purged with stack gas before 

opening the valve and beginning to fill the bag. 

(3) The bag contents shall be vigorously mixed prior to the 

GC analysis. 

(4) The GC-TCD calibration procedure in Method 3C, 40 CFR 

part 60, Appendix A, shall be modified by using EPAAlt-045 as 

follows: For the initial calibration, triplicate injections of 

any single concentration must agree within 5 percent of their 

mean to be valid. The calibration response factor for a single 

concentration re-check must be within 10 percent of the original 

calibration response factor for that concentration. If this 

criterion is not met, the initial calibration using at least 

three concentration levels shall be repeated. 

(B) Report the molecular weight of: O2, CO2, methane (CH4), 

and N2 and include in the test report submitted under 

§63.775(d)(iii). Moisture shall be determined using Method 4, 40 

CFR part 60, Appendix A. Traverse both ports with the Method 4, 

40 CFR part 60, Appendix A, sampling train during each test run. 

Ambient air shall not be introduced into the Method 3C, 40 CFR 

part 60, Appendix A, integrated bag sample during the port 

change. 

(iii) Carbon monoxide shall be determined using Method 10, 

40 CFR part 60, Appendix A. The test shall be run at the same 

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time and with the sample points used for the EPA Method 25A, 40 

CFR part 60, Appendix A, testing. An instrument range of 0-10 

per million by volume-dry (ppmvd) shall be used. 

(iv) Visible emissions shall be determined using Method 22, 

40 CFR part 60, Appendix A. The test shall be performed 

continuously during each test run. A digital color photograph of 

the exhaust point, taken from the position of the observer and 

annotated with date and time, will be taken once per test run 

and the four photos included in the test report. 

(v) Excess air shall be determined using resultant data 

from the EPA Method 3C tests and EPA Method 3B, 40 CFR part 60, 

Appendix A, equation 3B-1. 

(6) Total hydrocarbons (THC) shall be determined as 

specified by the following criteria: 

(i) Conduct THC sampling using Method 25A, 40 CFR part 60, 

Appendix A, except the option for locating the probe in the 

center 10 percent of the stack shall not be allowed. The THC 

probe must be traversed to 16.7 percent, 50 percent, and 83.3 

percent of the stack diameter during each test. 

(ii) A valid test shall consist of three Method 25A, 40 CFR 

part 60, Appendix A, tests, each no less than 60 minutes in 

duration. 

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(iii) A 0-10 parts per million by volume-wet (ppmvw) (as 

propane) measurement range is preferred; as an alternative a 0­

30 ppmvw (as carbon) measurement range may be used. 

(iv) Calibration gases will be propane in air and be 

certified through EPA Protocol 1 – “EPA Traceability Protocol 

for Assay and Certification of Gaseous Calibration Standards,” 

September 1997, as amended August 25, 1999, EPA–600/R–97/121 (or 

more recent if updated since 1999). 

(v) THC measurements shall be reported in terms of ppmvw as 

propane. 

(vi) THC results shall be corrected to 3 percent CO2, as measured 

by Method 3C, 40 CFR part 60, Appendix A. 

(vii) Subtraction of methane/ethane from the THC data is 

not allowed in determining results. 

(7) Performance test criteria: 

(i) The control device model tested must meet the criteria 

in paragraphs (h)(7)(i)(A) through (C) of this section: 

(A) Method 22, 40 CFR part 60, Appendix A, results under 

paragraph (h)(5)(v) of this section with no indication of 

visible emissions, and 

(B) Average Method 25A, 40 CFR part 60, Appendix A, 

results under paragraph (h)(6) of this section equal to or less 

than 10.0 ppmvw THC as propane corrected to 3.0 percent CO2, and 

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(C) Average CO emissions determined under paragraph 

(h)(5)(iv) of this section equal to or less than 10 parts ppmvd, 

corrected to 3.0 percent CO2. 

(D) Excess combustion air shall be equal to or greater than 

150 percent. 

(ii) The manufacturer shall determine a maximum inlet gas 

flowrate which shall not be exceeded for each control device 

model to achieve the criteria in paragraph (h)(7)(i) of this 

section. 

(iii) A control device meeting the criteria in paragraphs 

(h)(7)(i)(A) through (C) of this section will have demonstrated 

a destruction efficiency of 95.0 percent for HAP regulated under 

this subpart. 

(8) The owner or operator of a combustion control device 

model tested under this section shall submit the information 

listed in paragraphs (h)(8)(i) through (iii) of this section in 

the test report required under §63.775(d)(1)(iii). 

(i) Full schematic of the control device and dimensions of 

the device components. 

(ii) Design net heating value (minimum and maximum) of the 

device. 

(iii) Test fuel gas flow range (in both mass and volume). 

Include the minimum and maximum allowable inlet gas flowrate. 

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(iv) Air/stream injection/assist ranges, if used. 

(v) The test parameter ranges listed in paragraphs (h)(8)(v)(A) 

through (O) of this section, as applicable for the tested model. 

(A) Fuel gas delivery pressure and temperature. 

(B) Fuel gas moisture range. 

(C) Purge gas usage range. 

(D) Condensate (liquid fuel) separation range. 

(E) Combustion zone temperature range. This is required for 

all devices that measure this parameter. 

(F) Excess combustion air range. 

(G) Flame arrestor(s). 

(H) Burner manifold pressure. 

(I) Pilot flame sensor. 

(J) Pilot flame design fuel and fuel usage. 

(K) Tip velocity range. 

(L) Momentum flux ratio. 

(M) Exit temperature range. 

(N) Exit flowrate. 

(O) Wind velocity and direction. 

(vi) The test report shall include all calibration quality 

assurance/quality control data, calibration gas values, gas 

cylinder certification, and strip charts annotated with test 

times and calibration values. 

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(i) Compliance demonstration for combustion control devices 

- manufacturers’ performance test. This paragraph applies to the 

demonstration of compliance for a combustion control device 

tested under the provisions in paragraph (h) of this section. 

Owners or operators shall demonstrate that a control device 

achieves the performance requirements of §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. 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: 

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(i) The inlet gas flowrate monitored under paragraph (i)(1) 

of this section is equal to or below the maximum established by 

the manufacturer; and 

(ii) The pilot flame is present at all times; and 

(iii) During the visible emissions test performed under 

paragraph (i)(3) of this section the duration of visible 

emissions does not exceed a total of 2 minutes during the 

observation period. Devices failing the visible emissions test 

shall follow manufacturers repair instructions, if available, or 

best combustion engineering practice as outlined in the unit 

inspection and maintenance plan, to return the unit to compliant 

operation. All repairs and maintenance activities for each unit 

shall be recorded in a maintenance and repair log and shall be 

available on site for inspection. 

(iv) Following return to operation from maintenance or 

repair activity, each device must pass a Method 22 visual 

observation as described in paragraph (i)(3) of this section. 

19. Section 63.773 is amended by: 

a. Adding paragraph (b); 

b. Revising paragraph (d)(1) introductory text; 

c. Revising paragraph (d)(1)(ii) and adding paragraphs 

(d)(1)(iii) and (iv); 

d. Revising paragraph (d)(2); 

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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 each control device with 

maintenance and replacement of control device components made in 

accordance with the plan. 

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* * * * * 

(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 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 

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request approval of monitoring system quality assurance and 

quality control procedures alternative to those specified in 

paragraphs (d)(1)(ii)(A) through (E) of this section in your 

site-specific monitoring plan. 

(A) The performance criteria and design specifications for 

the monitoring system equipment, including the sample interface, 

detector signal analyzer, and data acquisition and calculations; 

(B) Sampling interface (e.g., thermocouple) location such 

that the monitoring system will provide representative 

measurements; 

(C) Equipment performance checks, system accuracy audits, 

or other audit procedures; 

(D) Ongoing operation and maintenance procedures in 

accordance with provisions in §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 

performance checks, system accuracy audits, or other audit 

procedures specified in the site-specific monitoring plan at 

least once every 12 months. 

(iv) The owner or operator must conduct a performance 

evaluation of each CPMS in accordance with the site-specific 

monitoring plan. 

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(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 temperature monitoring device equipped with a 

continuous recorder. The monitoring device shall have a minimum 

accuracy of ±2 percent of the temperature being monitored in °C, 

or ±2.5°C, whichever value is greater. The temperature sensor 

shall be installed at a location representative of the 

combustion zone temperature. 

* * * * * 

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(D) For a boiler or process heater, a temperature 

monitoring device equipped with a continuous recorder. The 

temperature monitoring device shall have a minimum accuracy of 

±2 percent of the temperature being monitored in °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 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 §63.772(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-GLYCalcTM , Version 

3.0 or higher, ProMax, or AspenTech HYSYS. Inputs to the models 

shall be representative of actual operating conditions of the 

controlled unit. The determination shall be performed to 

coincide with the visible emissions test under §63.772(i)(3); 

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(2) A heat sensing monitoring device equipped with a 

continuous recorder that indicates the continuous ignition of 

the pilot flame. 

* * * * * 

(4) Using the data recorded by the monitoring system, 

except for inlet gas flowrate, the owner or operator must 

calculate the daily average value for each monitored operating 

parameter for each operating day. If the emissions unit 

operation is continuous, the operating day is a 24-hour period. 

If the emissions unit operation is not continuous, the operating 

day is the total number of hours of control device operation per 

24-hour period. Valid data points must be available for 75 

percent of the operating hours in an operating day to compute 

the daily average. 

(5) * * * 

(i) The owner or operator shall establish a minimum 

operating parameter value or a maximum operating parameter 

value, as appropriate for the control device, to define the 

conditions at which the control device must be operated to 

continuously achieve the applicable performance requirements of 

§63.771(d)(1), (e)(3)(ii) or (f)(1). Each minimum or maximum 

operating parameter value shall be established as follows: 

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(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 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 values 

measured during the performance test and supplemented, as 

necessary, by a condenser design analysis or control device 

manufacturer recommendations or a combination of both. 

(B) If the owner or operator uses a condenser design 

analysis in accordance with the requirements of §63.772(e)(4) to 

demonstrate that 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 analysis and may be supplemented by the 

condenser manufacturer's recommendations. 

(C) If the owner or operator operates a control device 

where the performance test requirement was met under §63.772(h) 

to demonstrate that the control device achieves the applicable 

performance requirements specified in §63.771(d)(1), (e)(3)(ii) 

or (f)(1), then the maximum inlet gas flowrate shall be 

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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 performance curve shall be based on values measured 

during the performance test and supplemented as necessary by 

control device design analysis, or control device manufacturer's 

recommendations, or a combination or both. 

(B) If the owner or operator uses a control device design 

analysis in accordance with the requirements of §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– 

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95/0368.1) as inputs for the model GRI-GLYCalcTM , 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 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)(vi) of this 

section, then a single excursion is determined to have occurred 

for the control device for that operating day. 

* * * * * 

(ii) For sources meeting §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-day required percent reduction. 

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(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 required 

percent reduction. 

* * * * * 

(vi) For control device whose model is tested under 

§63.772(h) an excursion occurs when: 

(A) The inlet gas flowrate exceeds the maximum established 

during the test conducted under §63.772(h). 

(B) Failure of the quarterly 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: 

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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 of 

§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] 

* * * * * 

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(4) * * * 

(ii) Records of the daily average value of each 

continuously monitored parameter for each operating day 

determined according to the procedures 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. 

* * * * * 

(7) * * * 

(ix) Records identifying the carbon replacement schedule 

under §63.771(d)(5) and records of each carbon replacement. 

* * * * * 

(g) The owner or operator of an affected source subject to 

this subpart shall maintain records of the occurrence and 

duration of each malfunction of operation (i.e., process 

equipment) or the air pollution control equipment and monitoring 

equipment. The owner or operator shall maintain records of 

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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 emission 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 under §63.773(b) is performed. Include a list of any 

modifications or repairs made to the control device during the 

inspection and other maintenance performed such as cleaning of 

the fuel nozzles. 

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); 

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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) * * * 

(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 (ii), the 

initial notifications shall be submitted by 1 year after an 

affected source becomes subject to the provisions of this 

subpart or by June 17, 2000, whichever is later. Affected 

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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. 

* * * * * 

(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 

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malfunction of an affected source to minimize emissions in 

accordance with §63.764(j), including actions taken to correct 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 also 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. 

* * * * * 

(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 

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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 correct a 

malfunction. 

(7) * * * 

(i) Documentation of the source's location relative to the 

nearest UA plus offset and UC boundaries. This information shall 

include the latitude and longitude of the affected source; 

whether the source is located in an urban cluster with 10,000 

people or more; the distance in miles to the nearest urbanized 

area boundary if the source is not located in an urban cluster 

with 10,000 people or more; and the name of the nearest urban 

cluster with 10,000 people or more and nearest urbanized area. 

* * * * * 

(d) * * * 

(1) * * * 

(i) The condenser design analysis documentation specified 

in §63.772(e)(4) of this subpart, if the owner or operator 

elects to prepare a design analysis. 

(ii) If the owner or operator is required to conduct a 

performance test, the performance test results including the 

information specified in paragraphs (d)(1)(ii)(A) and (B) of 

this section. Results of a performance test conducted prior to 

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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 conditions 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@EPA.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 

device is operating in accordance with the applicable 

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). 

* * * * * 

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(11) The owner or operator shall submit the analysis 

prepared under §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 and 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. 

(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. 

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(e) * * * 

(2) The owner or operator shall include the information 

specified in paragraphs (e)(2)(i) through (ix) of this section, 

as applicable. 

* * * * * 

(ii) * * * 

* * * * * 

(B) For each excursion caused when the 365-day average 

condenser control efficiency is less than the value specified in 

§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. 

* * * * * 

(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. 

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(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 inspections 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 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 

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performance tests required by this subpart to EPA’s WebFIRE 

database by using the Compliance and Emissions Data Reporting 

Interface (CEDRI) that is accessed through EPA’s Central Data 

Exchange (CDX)(www.epa.gov/cdx). Performance test data must be 

submitted in the file format generated through use of EPA’s 

Electronic Reporting Tool (ERT) (see 

http://www.epa.gov/ttn/chief/ert/index.html). Only data 

collected using test methods on the ERT 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 submit a complete 

ERT file including information claimed to be CBI on a compact 

disk or other commonly used electronic storage media (including, 

but not limited to, flash drives) to EPA. The electronic media 

must be clearly marked as CBI and mailed to U.S. EPA/OAPQS/CORE 

CBI Office, Attention: WebFIRE Administrator, MD C404-02, 4930 

Old Page Rd., Durham, NC 27703. The same ERT file with the CBI 

omitted must be submitted to EPA via CDX as described earlier in 

this paragraph. At the discretion of the delegated authority, 

you must also submit these reports, including the confidential 

business information, to the delegated authority in the format 

specified by the delegated authority. 

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(2) All reports required by this subpart not subject to the 

requirements in paragraph (g)(1) of this section must be sent to 

the Administrator at the appropriate address listed in §63.13. 

The Administrator or the delegated authority may request a 

report in any form suitable for the specific case (e.g., by 

commonly used electronic media such as Excel spreadsheet, on CD 

or hard copy). The Administrator retains the right to require 

submittal of reports subject to paragraph (g)(1) of this section 

in paper format. 

22. Appendix to subpart HH of part 63 is amended by 

revising Table 2 to read as follows: 

Appendix to Subpart HH of Part 63—Tables 

* * * * * 

Table 2 to Subpart HH of Part 63—Applicability of 40 CFR Part 63

General Provisions to Subpart HH 

General provisions Applicable Explanation

reference to 

subpart HH

§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 No Section reserved. 

(a)(9)

§63.1(a)(10) Yes. 

§63.1(a)(11) Yes. 

§63.1(a)(12) Yes. 

§63.1(b)(1) No Subpart HH specifies

applicability.

§63.1(b)(2) No Section reserved. 

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§63.1(b)(3) Yes. 

§63.1(c)(1) No 

§63.1(c)(2) Yes. 

§63.1(c)(3) and (c)(4) No 

§63.1(c)(5) Yes. 

§63.1(d) No 

§63.1(e) Yes. 

§63.2 Yes 

§63.3(a) through (c) Yes. 

§63.4(a)(1) through Yes. 

(a)(2)

§63.4(a)(3) through No 

(a)(5)

§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 

§63.5(b)(3) Yes. 

§63.5(b)(4) Yes. 

§63.5(b)(5) No 

§63.5(b)(6) Yes. 

§63.5(c) No 

§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. 

Subpart HH specifies

applicability.

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).

Section reserved. 

Section reserved. 

Except definition of major

source is unique for this

source category and there are

additional definitions in 

subpart HH. 

Section reserved. 

Section reserved. 

Section Reserved. 

Section reserved. 

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§63.6(b)(4) Yes. 

§63.6(b)(5) Yes. 

§63.6(b)(6) No 

§63.6(b)(7) Yes. 

§63.6(c)(1) Yes. 

§63.6(c)(2) Yes. 

§63.6(c)(3) through No 

(c)(4)

§63.6(c)(5) Yes. 

§63.6(d) No 

§63.6(e) Yes. 

§63.6(e)(1)(i) No 

§63.6(e)(1)(ii) No. 

§63.6(e)(1)(iii) Yes. 

§63.6(e)(2) No 

§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 Yes. 

(h)(9)

§63.6(i)(1) through Yes. 

(i)(14)

§63.6(i)(15) No 

§63.6(i)(16) Yes. 

§63.6(j) Yes. 

§63.7(a)(1) Yes. 

§63.7(a)(2) Yes 

§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. 

Section reserved. 

Section reserved. 

Section reserved. 

See §63.764(j) for general duty

requirement. 

Section reserved. 

Section reserved. 

But the performance test

results must be submitted 

within 180 days after the

compliance date. 

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§63.8(a)(2) Yes. 

§63.8(a)(3) No 

§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) No. 

§63.8(c)(1)(ii) Yes. 

§63.8(c)(1)(iii) No. 

§63.8(c)(2) Yes. 

§63.8(c)(3) Yes. 

§63.8(c)(4) Yes. 

§63.8(c)(4)(i) No 

§63.8(c)(4)(ii) Yes. 

§63.8(c)(5) through Yes. 

(c)(8)

§63.8(d) Yes. 

§63.8(d)(3) Yes. 

§63.8(e) Yes 

§63.8(f)(1) through Yes. 

(f)(5)

§63.8(f)(6) Yes. 

§63.8(g) No 

§63.9(a) Yes. 

§63.9(b)(1) Yes. 

§63.9(b)(2) Yes 

§63.9(b)(3) No 

§63.9(b)(4) Yes. 

§63.9(b)(5) Yes. 

§63.9(c) Yes. 

Section reserved. 

Subpart HH does not require

continuous opacity monitors. 

Except for last sentence, which

refers to an SSM plan. SSM

plans are not required.

Subpart HH does not

specifically require continuous

emissions monitor performance

evaluation, however, the

Administrator can request that

one be conducted. 

Subpart HH specifies continuous

monitoring system data

reduction requirements. 

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. 

Section reserved. 

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§63.9(d) Yes. 

§63.9(e) Yes. 

§63.9(f) Yes. 

§63.9(g) Yes. 

§63.9(h)(1) through Yes 

(h)(3) 

§63.9(h)(4) No 

§63.9(h)(5) through Yes. 

(h)(6)

§63.9(i) Yes. 

§63.9(j) Yes. 

§63.10(a) Yes. 

§63.10(b)(1) Yes 

§63.10(b)(2) Yes. 

§63.10(b)(2)(i) No. 

§63.10(b)(2)(ii) No 

§63.10(b)(2)(iii) Yes. 

§63.10(b)(2)(iv) No. 

through (b)(2)(v)

§63.10(b)(2)(vi) Yes. 

through (b)(2)(xiv)

§63.10(b)(3) Yes 

§63.10(c)(1) Yes. 

§63.10(c)(2) through No 

(c)(4)

§63.10(c)(5) through Yes. 

(8) (c)(8)

§63.10(c)(9) No 

§63.10(c)(10) through No 

(11)

§63.10(c)(12) through Yes. 

Area sources located outside UA 

plus offset and UC boundaries

are not required to submit

notifications of compliance

status. 

Section reserved. 

§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. 

See §63.774(g) for

recordkeeping of (1) occurrence

and duration and (2) actions

taken during malfunctions. 

§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. 

Sections reserved. 

Section reserved. 

See §63.774(g) for

recordkeeping of malfunctions. 

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(14)

§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 

§63.10(e)(1) Yes 

§63.10(e)(2) Yes 

§63.10(e)(3)(i) Yes 

§63.10(e)(3)(i)(A) Yes. 

§63.10(e)(3)(i)(B) Yes. 

§63.10(e)(3)(i)(C) No 

§63.10(e)(3)(ii) Yes. 

through (viii)

§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. 

Area sources located outside UA 

plus offset and UC boundaries

do not have to submit 

performance test reports. 

See §63.775(b)(6) or (c)(6) for

reporting of malfunctions.

Area sources located outside UA 

plus offset and UC boundaries

are not required to submit

reports.

Area sources located outside UA 

plus offset and UC boundaries

are not required to submit

reports.

Subpart HH requires major

sources to submit Periodic 

Reports semi-annually. Area

sources are required to submit

Periodic Reports annually. Area

sources located outside UA plus

offset and UC boundaries are 

not required to submit reports. 

Section reserved. 

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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 subpart applies to owners and operators of natural 

gas transmission and storage facilities that transport or store 

natural gas prior to entering the pipeline to a local 

distribution company or to a final end user (if there is no 

local distribution company), and that are major sources of 

hazardous air pollutants (HAP) emissions as defined in §63.1271. 

Emissions for major source determination purposes can be 

estimated using the maximum natural gas throughput calculated in 

either paragraph (a)(1) or (2) of this section and paragraphs 

(a)(3) and (4) of this section. As an alternative to calculating 

the maximum natural gas throughput, the owner or operator of a 

new or existing source may use the facility design maximum 

natural gas throughput to estimate the maximum potential 

emissions. Other means to determine the facility's major source 

status are allowed, provided the information is documented and 

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recorded to the Administrator's satisfaction in accordance with 

§63.10(b)(3). A compressor station that transports natural gas 

prior to the point of custody transfer or to a natural gas 

processing plant (if present) is not considered a part of the 

natural gas transmission and storage source category. A facility 

that is determined to be an area source, but subsequently 

increases its emissions or its potential to emit above the major 

source levels (without obtaining and complying with other 

limitations that keep its potential to emit HAP below major 

source levels), and becomes a major source, must comply 

thereafter with all applicable provisions of this subpart 

starting on the applicable compliance date specified in 

paragraph (d) of this section. Nothing in this paragraph is 

intended to preclude a source from limiting its potential to 

emit through other appropriate mechanisms that may be available 

through the permitting authority. 

* * * * * 

(4) The owner or operator shall determine the maximum 

values for other parameters used to calculate potential 

emissions as the maximum over the same period for which maximum 

throughput is determined as specified in paragraph (a)(1) or 

(a)(2) of this section. These parameters shall be based on an 

annual average or the highest single measured value. For 

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estimating maximum potential emissions from glycol dehydration 

units, the glycol circulation rate used in the calculation shall 

be the unit’s maximum rate under its physical and operational 

design consistent with the definition of potential to emit in 

§63.2. 

(b) The affected source is each new and existing glycol 

dehydration unit specified in paragraphs (b)(1) through (3) of 

this section. 

(1) Each large glycol dehydration unit; 

(2) Each small glycol dehydration unit for which 

construction commenced on or before August 23, 2011, is an 

existing small glycol dehydration unit. 

(3) Each small glycol dehydration unit for which 

construction commenced after August 23, 2011, is a new small 

glycol dehydration unit. 

* * * * * 

(d) * * * 

(1) Except as specified in paragraphs (d)(3) through (4) of 

this section, the owner or operator of an affected source, the 

construction or reconstruction of which commenced before 

February 6, 1998, shall achieve compliance with this provisions 

of the subpart no later than June 17, 2002 except as provided 

for in §63.6(i). The owner or operator of an area source, the 

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construction or reconstruction of which commenced before 

February 6, 1998, that increases its emissions of (or its 

potential to emit) HAP such that the source becomes a major 

source that is subject to this subpart shall comply with this 

subpart 3 years after becoming a major source. 

(2) Except as specified in paragraphs (d)(3) through (4) of 

this section, the owner or operator of an affected source, the 

construction or reconstruction of which commences on or after 

February 6, 1998, shall achieve compliance with the provisions 

of this subpart immediately upon initial startup or June 17, 

1999, whichever date is later. Area sources, the construction or 

reconstruction of which commences on or after February 6, 1998, 

that become major sources shall comply with the provisions of 

this standard immediately upon becoming a major source. 

(3) Each affected small glycol dehydration unit, as 

defined in §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 

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compliance immediately upon initial startup or [INSERT DATE 60 

DAYS AFTER DATE OF PUBLICATION IN THE FEDERAL REGISTER], 

whichever is later. 

* * * * * 

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, 

regarding which the defendant has the burden of proof, and the 

merits of which are independently and objectively evaluated in a 

judicial or administrative proceeding. 

* * * * * 

BTEX means benzene, toluene, ethyl benzene and xylene. 

* * * * * 

Flare means a thermal oxidation system using an open flame 

(i.e., without enclosure). 

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* * * * * 

Glycol dehydration unit baseline operations means 

operations representative of the large glycol dehydration unit 

operations as of June 17, 1999 and the small glycol dehydration 

unit operations as of August 23, 2011,. For the purposes of this 

subpart, for determining the percentage of overall HAP emission 

reduction attributable to process modifications, glycol 

dehydration unit baseline operations shall be parameter values 

(including, but not limited to, glycol circulation rate or 

glycol-HAP absorbency) that represent actual long-term 

conditions (i.e., at least 1 year). Glycol dehydration units in 

operation for less than 1 year shall document that the parameter 

values represent expected long-term operating conditions had 

process modifications not been made. 

* * * * * 

Large glycol dehydration unit means a glycol dehydration 

unit with an actual annual average natural gas flowrate equal to 

or greater than 283.0 thousand standard cubic meters per day and 

actual annual average benzene emissions equal to or greater than 

0.90 Mg/yr, determined according to §63.1282(a). A glycol 

dehydration unit complying with the 0.9 Mg/yr control option 

under 63.1275(b)(1)(ii) is considered to be a large dehydrator. 

* * * * * 

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 Responsible official means one of the following: 

(1) For a corporation: a president, secretary, treasurer, 

or vice-president of the corporation in charge of a principal 

business function, or any other person who performs similar 

policy or decision-making functions for the corporation, or a 

duly authorized representative of such person if the 

representative is responsible for the overall operation of one 

or more manufacturing, production, or operating facilities 

applying for or subject to a permit and either: 

(i) The facilities employ more than 250 persons or have 

gross annual sales or expenditures exceeding $25 million (in 

second quarter 1980 dollars); or 

(ii) The delegation of authority to such representatives is 

approved in advance by the permitting authority; 

(2) For a partnership or sole proprietorship: a general 

partner or the proprietor, respectively; 

(3) For a municipality, State, Federal, or other public 

agency: Either a principal executive officer or ranking elected 

official. For the purposes of this part, a principal executive 

officer of a Federal agency includes the chief executive officer 

having responsibility for the overall operations of a principal 

geographic unit of the agency (e.g., a Regional Administrator of 

EPA); or 

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(4) For affected sources: 

(i) The designated representative in so far as actions, 

standards, requirements, or prohibitions under title IV of the 

Act or the regulations promulgated thereunder are concerned; and 

(ii) The designated representative for any other purposes 

under part 70. 

* * * * * 

Small glycol dehydration unit means a glycol dehydration 

unit, located at a major source, with an actual annual average 

natural gas flowrate less than 283.0 thousand standard cubic 

meters per day or actual annual average benzene emissions less 

than 0.90 Mg/yr, determined according to §63.1282(a). 

* * * * * 

25. Section 63.1272 is revised to read as follows: 

§63.1272 Affirmative defense for violations of emission 

standards during malfunction. 

(a) The provisions set forth in this subpart shall apply at 

all times. 

(b) [Reserved] 

(c) [Reserved] 

(d) In response to an action to enforce the standards set 

forth in this subpart, you may assert an affirmative defense to 

a claim for civil penalties for violations of such standards 

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that are caused by malfunction, as defined at §63.2. Appropriate 

penalties may be assessed; however, if you fail to meet your 

burden of proving all of the requirements in the affirmative 

defense, the affirmative defense shall not be available for 

claims for injunctive relief. 

(1) To establish the affirmative defense in any action to 

enforce such a standard, you must timely meet the reporting 

requirements in paragraph (d)(2) of this section, and must prove 

by a preponderance of evidence that: 

(i) The violation: 

(A) Was caused by a sudden, infrequent, and unavoidable 

failure of air pollution control equipment, process equipment, 

or a process to operate in a normal or usual manner; and 

(B) Could not have been prevented through careful planning, 

proper design or better operation and maintenance practices; and 

(C) Did not stem from any activity or event that could have 

been foreseen and avoided, or planned for; and 

(D) Was not part of a recurring pattern indicative of 

inadequate design, operation, or maintenance; and 

(ii) Repairs were made as expeditiously as possible when a 

violation occurred. Off-shift and overtime labor were used, to 

the extent practicable to make these repairs; and 

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(iii) The frequency, amount and duration of the violation 

(including any bypass) were minimized to the maximum extent 

practicable; and 

(iv) If the violation resulted from a bypass of control 

equipment or a process, then the bypass was unavoidable to 

prevent loss of life, personal injury, or severe property 

damage; and 

(v) All possible steps were taken to minimize the impact of 

the violation on ambient air quality, the environment, and human 

health; and 

(vi) All emissions monitoring and control systems were kept 

in operation if at all possible, consistent with safety and good 

air pollution control practices; and 

(vii) All of the actions in response to the violation were 

documented by properly signed, contemporaneous operating logs; 

and 

(viii) At all times, the affected source was operated in a 

manner consistent with good practices for minimizing emissions; 

and 

(ix) A written root cause analysis has been prepared, the 

purpose of which is to determine, correct, and eliminate the 

primary causes of the malfunction and the violation resulting 

from the malfunction event at issue. The analysis shall also 

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specify, using best monitoring methods and engineering judgment, 

the amount of any emissions that were the result of the 

malfunction. 

(2) Report. The owner or operator seeking to assert an 

affirmative defense shall submit a written report to the 

Administrator with all necessary supporting documentation, that 

it has met the requirements set forth in paragraph (d)(1) of 

this section. This affirmative defense report shall be included 

in the first periodic compliance, deviation report or excess 

emission report otherwise required after the initial occurrence 

of the violation of the relevant standard (which may be the end 

of any applicable averaging period). If such compliance, 

deviation report or excess emission report is due less than 45 

days after the initial occurrence of the violation, the 

affirmative defense report may be included in the second 

compliance, deviation report or excess emission report due after 

the initial occurrence of the violation of the relevant 

standard. 

26. Section 63.1274 is amended by: 

a. Revising paragraph (c) introductory text; 

b. Removing and reserving paragraph (d); 

c. Revising paragraph (g); and 

d. Adding paragraph (h) to read as follows: 

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§63.1274 General standards. 

* * * * * 

(c) The owner or operator of an affected source (i.e., 

glycol dehydration unit) located at an existing or new major 

source of HAP emissions shall comply with the requirements in 

this subpart as follows: 

* * * * * 

(d) [Reserved] 

* * * * * 

(g) In all cases where the provisions of this subpart 

require an owner or operator to repair leaks by a specified time 

after the leak is detected, it is a violation of this standard 

to fail to take action to repair the leak(s) within the 

specified time. If action is taken to repair the leak(s) within 

the specified time, failure of that action to successfully 

repair the leak(s) is not a violation of this standard. However, 

if the repairs are unsuccessful, and a leak is detected, the 

owner or operator shall take further action as required by the 

applicable provisions of this subpart. 

(h) At all times the owner or operator must operate and 

maintain any affected source, including associated air pollution 

control equipment and monitoring equipment, in a manner 

consistent with safety and good air pollution control practices 

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for minimizing emissions. Determination of whether such 

operation and maintenance procedures are being used will be 

based on information available to the Administrator which may 

include, but is not limited to, monitoring results, review of 

operation and maintenance procedures, review of operation and 

maintenance records, and inspection of the source. 

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 shall 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 devices through a 

closed-vent system. The closed-vent system shall be designed and 

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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 a 

combination of control devices through a closed-vent system and 

the outlet benzene emissions from the control device(s) shall be 

less than 0.90 megagrams per year. The closed-vent system shall 

be designed and operated in accordance with the requirements of 

§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 emissions 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 the alternatives specified in paragraphs (b)(1)(iii)(A) 

through (D) of this section. 

௥௬௑ ா்஻ܮܧ ସ10ିݔ3.10 ൌ௑ ா்஻,௜ܥ כ ݐݑ݌݄݃ݑ݋ݎ݄ܶ כ 365 כ ௬௦௔ௗ כ

ଵ ெ௚ Equation 1 ଵ௫ଵ଴ల ௚௥௔௠௦

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Where: 

ELBTEX = Unit-specific BTEX emission limit, megagrams per year; 

3.10x10-4 = BTEX emission limit, grams BTEX/standard cubic meter 

-ppmv; 

Throughput = Annual average daily natural gas throughput, 

standard cubic meters per day 

Ci,BTEX = Annual average BTEX concentration of the natural gas at 

the inlet to the glycol dehydration unit, ppmv. 

௥௬௑ ா்஻ܮܧ ହ10ିݔ5.44 ൌ௑ ா்஻,௜ܥ כ ݐݑ݌݄݃ݑ݋ݎ݄ܶ כ 365 כ ௬௦௔ௗ כ

ଵ ெ௚ Equation 2 ଵ௫ଵ଴ల ௚௥௔௠௦

Where: 

ELBTEX = Unit-specific BTEX emission limit, megagrams per year; 

5.44x10-5 = BTEX emission limit, grams BTEX/standard cubic meter 

-ppmv; 

Throughput = Annual average daily natural gas throughput, 

standard cubic meters per day 

Ci,BTEX = Annual average BTEX concentration of the natural gas at 

the inlet to the glycol dehydration unit, ppmv. 

(A) Connect the process vent to a control device or 

combination of control devices through a closed-vent system. The 

closed vent system shall be designed and operated in accordance 

with the requirements of §63.1281(c). The control device(s) 

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shall be designed and operated in accordance with the 

requirements of §63.1281(f). 

(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 control devices through the requirements 

specified in paragraphs (b)(1)(iii)(A) and (B) of this section. 

(D) Demonstrate that the emissions limit is met through 

actual uncontrolled operation of the small glycol dehydration 

unit. Document operational parameters in accordance with the 

requirements specified in §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 requirements specified 

in §63.1281(e). 

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(3) Control of HAP emissions from a GCG separator (flash 

tank) vent is not required if the owner or operator 

demonstrates, to the Administrator's satisfaction, that total 

emissions to the atmosphere from the glycol dehydration unit 

process vent are reduced by one of the levels specified in 

paragraph (c)(3)(i) through (iv) through the installation and 

operation of controls as specified in paragraph (b)(1) of this 

section. 

(i) For any large glycol dehydration unit, HAP emissions 

are reduced by 95.0 percent or more. 

(ii) For any large glycol dehydration unit, benzene 

emissions are reduced to a level less than 0.90 megagrams per 

year. 

(iii) For each existing small glycol dehydration unit, BTEX 

emissions are reduced to a level less than the limit calculated 

in Equation 1 of paragraph (b)(1)(iii) of this section. 

(iv) For each new small glycol dehydration unit, BTEX 

emissions are reduced to a level less than the limit calculated 

in Equation 2 of paragraph (b)(1)(iii) of this section. 

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; 

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d. Revising paragraph (d)(1)(i)(C); 

e. Revising paragraphs (d)(1)(ii) and (iii); 

f. Revising paragraph (d)(4)(i); 

g. Revising paragraph (d)(5)(i); 

h. Revising paragraph (e)(2); 

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) * * * 

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(C) Operates at a minimum 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 

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 §63.1282(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 when gases, vapors, and fumes 

are vented from the emissions unit or units through the closed 

vent system to the control device as required under §63.1275. An 

owner or operator may vent more than one unit to a control 

device used to comply with this subpart. 

* * * * * 

(5) * * * 

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(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 of 

Compliance Status 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 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 §63.1275(b)(1)(iii), as applicable, either 

through process modifications or through a combination of 

process modifications and one or more control devices. If a 

combination of process modifications and one or more control 

devices are used, the owner or operator shall also establish the 

emission reduction to be achieved by the control device to 

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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 dehydration unit operations directly related to process 

changes, including but not limited to changes in glycol 

circulation rate or glycol-HAP absorbency, shall be allowed. 

Changes in the inlet gas characteristics or natural gas 

throughput rate shall not be considered in determining the 

overall emission reduction due to process modifications. 

(3) The owner or operator that achieves a 95.0 percent HAP 

emission reduction or meets the BTEX limit determined in 

§63.1275(b)(1)(iii), as applicable, using process modifications 

alone shall comply with paragraph (e)(3)(i) of this section. The 

owner or operator that achieves a 95.0 percent HAP emission 

reduction or meets the BTEX limit determined in 

§63.1275(b)(1)(iii), as applicable, using a combination of 

process modifications and one or more control devices shall 

comply with paragraphs (e)(3)(i) and (e)(3)(ii) of this section. 

* * * * * 

(ii) The owner or operator shall comply with the control 

device requirements specified in paragraph (d) or (f) of this 

section, as applicable, except that the emission reduction or 

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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. 

(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). 

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(ii) A vapor recovery device (e.g., carbon adsorption 

system or condenser) or other non-destructive control device 

that is designed and operated to reduce the mass content of BTEX 

in the gases vented to the device as determined in accordance 

with the requirements of §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). 

(2) The owner or operator shall operate each control device 

in accordance with the requirements specified in paragraphs 

(f)(2)(i) and (ii) of this section. 

(i) Each control device used to comply with this subpart 

shall be operating at all times. An owner or operator may vent 

more than one unit to a control device used to comply with this 

subpart. 

(ii) For each control device monitored in accordance with 

the requirements of §63.1283(d), the owner or operator shall 

demonstrate compliance according to the requirements 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: 

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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); 

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; 

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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 

glycol dehydration unit natural gas flowrate, benzene emissions, 

or BTEX emissions. 

(1) * * * 

(ii) The owner or operator shall document, to the 

Administrator's satisfaction, the actual annual average natural 

gas flowrate to the glycol dehydration unit. 

(2) The determination of actual average benzene or BTEX 

emissions from a glycol dehydration unit shall be made using the 

procedures of either paragraph (a)(2)(i) or (a)(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-GLYCalcTM, Version 

3.0 or higher, and the procedures presented in the associated 

GRI-GLYCalcTM Technical Reference Manual. Inputs to the model 

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shall be representative of actual operating conditions of the 

glycol dehydration unit and may be determined using the 

procedures documented in the Gas Research Institute (GRI) report 

entitled “Atmospheric Rich/Lean Method for Determining Glycol 

Dehydrator Emissions” (GRI–95/0368.1); or 

(ii) The owner or operator shall determine an average mass 

rate of benzene or BTEX emissions in kilograms per hour through 

direct measurement by performing three runs of Method 18 in 40 

CFR part 60, appendix A; or ASTM D6420-99(2004), as specified in 

§63.772(a)(1)(ii); or an equivalent method; and averaging the 

results of the three runs. Annual emissions in kilograms per 

year shall be determined by multiplying the mass rate by the 

number of hours the unit is operated per year. This result shall 

be converted to megagrams per year. 

* * * * * 

(b) * * * 

(6) * * * 

(i) Except as provided in paragraph (b)(6)(ii) of this 

section, the detection instrument shall meet the performance 

criteria of Method 21 of 40 CFR part 60, appendix A, except the 

instrument response factor criteria in section 3.1.2(a) of 

Method 21 shall be for the average composition of the process 

fluid not each individual volatile organic compound in the 

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stream. For process streams that contain nitrogen, air, or other 

inert gases that are not organic HAP or VOC, the average stream 

response factor shall be calculated on an inert-free basis. 

* * * * * 

(c) Test procedures and compliance demonstrations for 

small glycol dehydration units. This paragraph 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 section apply. Compliance 

is demonstrated using the methods specified in paragraph (e) of 

this section. 

(2) If no control device is used to comply with the 

emission limit in §63.1275(b)(1)(iii), the owner or operator 

must determine the glycol dehydration unit BTEX emissions as 

specified in paragraphs (c)(2)(i) through (iii) of this section. 

Compliance is demonstrated if the BTEX emissions determined as 

specified in paragraphs (c)(2)(i) through (iii) are less than 

the emission limit calculated using the equation in 

§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 

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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-GLYCalcTM , Version 3.0 or higher, and the procedures 

presented in the associated GRI-GLYCalcTM Technical Reference 

Manual. Inputs to the model shall be representative of actual 

operating conditions of the glycol dehydration unit and shall be 

determined using the procedures documented in the Gas Research 

Institute (GRI) report entitled “Atmospheric Rich/Lean Method 

for Determining Glycol Dehydrator Emissions” (GRI–95/0368.1). 

When the BTEX mass rate is calculated for glycol dehydration 

units using the model GRI-GLYCalcTM, all BTEX measured by Method 

18, 40 CFR part 60, appendix A, shall be summed. 

(d) Control device performance test procedures. This 

paragraph applies to the performance testing of control devices. 

The owners or operators shall demonstrate that a control device 

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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 performance 

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, 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; 

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(iii) Except for control devices used for small glycol 

dehydration units, a boiler or process heater into which the 

vent stream is introduced with the primary fuel or is used as 

the primary fuel; 

(iv) Except for control devices used for small glycol 

dehydration units, a boiler or process heater burning hazardous 

waste for which the owner or operator has either been issued a 

final permit under 40 CFR part 270 and complies with the 

requirements of 40 CFR part 266, subpart H, or has certified 

compliance with the interim status requirements of 40 CFR part 

266, subpart H; 

(v) Except for control devices used for small glycol 

dehydration units, a hazardous waste incinerator for which the 

owner or operator has been issued a final permit under 40 CFR 

part 270 and complies with the requirements of 40 CFR part 264, 

subpart O, or has certified compliance with the interim status 

requirements of 40 CFR part 265, subpart O. 

* * * * * 

(2) An owner or operator shall design and operate each 

flare, as defined in §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. 

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(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 specified in 

paragraph (d)(3)(vi) of this section. 

(i) * * * 

(B) To determine compliance with the enclosed combustion 

device total HAP concentration limit specified in 

§63.1281(d)(1)(i)(B), or the BTEX emission limit specified in 

§63.1275(b)(1)(iii), the sampling site shall be located at the 

outlet of the combustion device. 

* * * * * 

(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 

according to the applicable procedures in Method 301 of appendix 

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A of this part may be used. The following procedures shall be 

used to calculate the percentage of reduction: 

* * * * * 

(iv) To determine compliance with the enclosed combustion 

device total HAP concentration limit specified in 

§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 concentration, 

corrected to 3 percent oxygen: 

* * * * * 

(C) * * * 

(1) The emission rate correction factor for excess air, 

integrated sampling and analysis procedures of Method 3A or 3B, 

40 CFR part 60, appendix A, shall be used to determine the 

oxygen concentration (%O2d). The samples shall be taken during 

the same time that the samples are taken for determining TOC 

concentration or total HAP concentration. 

* * * * * 

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(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 Method 301, 

40 CFR part 63, appendix A. The following procedures shall be 

used to calculate BTEX emissions: 

(A) The minimum sampling time for each run shall be 1 hour 

in which either an integrated sample or a minimum of four grab 

samples shall be taken. If grab sampling is used, then the 

samples shall be taken at approximately equal intervals in time, 

such as 15-minute intervals during the run. 

(B) The mass rate of BTEX (Eo) shall be computed using the 

equations and procedures specified in paragraphs (d)(3)(v)(B)(1) 

and (2) of this section. 

(1) The following equation shall be used: 

Where:
 

Eo= Mass rate of BTEX at the outlet of the control device, dry
 

basis, kilogram per hour. 

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Coj= Concentration of sample component j of the gas stream at the 

outlet of the control device, dry basis, parts per million by 

volume. 

Moj= Molecular weight of sample component j of the gas stream at 

the outlet of the control device, gram/gram-mole. 

Qo= Flowrate of gas stream at the outlet of the control device, 

dry standard cubic meter per minute. 

K2= Constant, 2.494×10−6 (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. 

(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 

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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 §63.1282(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. 

Subsequent periodic performance tests shall be conducted at 

intervals no longer than 60 months following the previous 

periodic performance test or whenever a source desires to 

establish a new operating limit. The periodic performance test 

results must be submitted in the next Periodic Report as 

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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, 

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 

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at the condenser inlet and outlet. As an alternative to the 

condenser design analysis, an owner or operator may elect to use 

the procedures specified in paragraph (d)(5) of this section. 

* * * * * 

(5) As an alternative to the procedures in paragraph 

(d)(4)(i) of this section, an owner or operator may elect to use 

the procedures documented in the GRI report entitled, 

“Atmospheric Rich/Lean Method for Determining Glycol Dehydrator 

Emissions,” (GRI–95/0368.1) as inputs for the model GRIGLYCalcTM, Version 3.0 or higher, to generate a condenser 

performance curve. 

(e) Compliance demonstration for control devices 

performance requirements. This paragraph applies to the 

demonstration of compliance with the control device performance 

requirements specified in §63.1281(d)(1), (e)(3)(ii), and 

(f)(1). Compliance shall be demonstrated using the requirements 

in paragraphs (e)(1) through (3) of this section. As an 

alternative, an owner or operator that installs a condenser as 

the control device to achieve the requirements specified in 

§63.1281(d)(1)(ii), (e)(3)(ii), or (f)(1) may demonstrate 

compliance according to paragraph (f) of this section. An owner 

or operator may switch between compliance with paragraph (e) of 

this section and compliance with paragraph (f) of this section 

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only after at least 1 year of operation in compliance with the 

selected approach. Notification of such a change in the 

compliance method shall be reported in the next Periodic Report, 

as required in §63.1285(e), following the change. 

* * * * * 

(2) The owner or operator shall calculate the daily average 

of the applicable 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) of 

this section is either equal to or greater than the minimum or 

equal to or less than the maximum monitoring value established 

under paragraph (e)(1) of this section. For inlet gas flowrate, 

compliance with the operating parameter limit is achieved when 

the value is equal to or less than the value established under 

§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 malfunctions, and 

required monitoring system quality assurance or quality control 

activities (including, as applicable, system accuracy audits and 

required zero and span adjustments), the CMS required in 

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§63.1283(d) must be operated at all times the affected source is 

operating. A monitoring system malfunction is any sudden, 

infrequent, not reasonably preventable failure of the monitoring 

system to provide valid data. Monitoring system failures that 

are caused in part by poor maintenance or careless operation are 

not malfunctions. Monitoring system repairs are required to be 

completed in response to monitoring system malfunctions and to 

return the monitoring system to operation as expeditiously as 

practicable. 

(5) Data recorded during monitoring system malfunctions, 

repairs associated with monitoring system malfunctions, or 

required monitoring system quality assurance or control 

activities may not be used in calculations used to report 

emissions or operating levels. All the data collected during all 

other required data collection periods must be used in assessing 

the operation of the control device and associated control 

system. 

(6) Except for periods of monitoring system malfunctions, 

repairs associated with monitoring system malfunctions, and 

required quality monitoring system quality assurance or quality 

control activities (including, as applicable, system accuracy 

audits and required zero and span adjustments), failure to 

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collect required data is a deviation of the monitoring 

requirements. 

(f) Compliance demonstration with percent reduction or 

emission limit performance requirements—condensers. This 

paragraph applies to the demonstration of compliance with the 

performance requirements specified in §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 section, at the end of each operating day the 

owner or operator shall calculate the 30-day average HAP, or 

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BTEX, emission reduction, as appropriate, from the condenser 

efficiencies as determined in paragraph (f)(2)(ii) of this 

section for the preceding 30 operating days. If the owner or 

operator uses a combination of process modifications and a 

condenser in accordance with the requirements of §63.1281(e), 

the 30-day average HAP emission, or BTEX, emission reduction, 

shall be calculated using the emission reduction achieved 

through process modifications and the condenser efficiency as 

determined in paragraph (f)(2)(ii) of this section, both for the 

preceding 30 operating days. 

(A) After the compliance date specified in §63.1270(d), an 

owner or operator of a facility that stores natural gas that has 

less than 30 days of data for determining the average HAP, or 

BTEX, emission reduction, as appropriate, shall calculate the 

cumulative average at the end of the withdrawal season, each 

season, until 30 days of condenser operating data are 

accumulated. For a facility that does not store natural gas, the 

owner or operator that has less than 30 days of data for 

determining average HAP, or BTEX, emission reduction, as 

appropriate, shall calculate the cumulative average at the end 

of the calendar year, each year, until 30 days of condenser 

operating data are accumulated. 

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(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 BTEX, emission reduction, as 

appropriate, compliance is achieved if the average HAP, or BTEX, 

emission reduction, as appropriate, calculated in paragraph 

(f)(2)(iii)(A) of this section is equal to or greater than 95.0 

percent or is equal to or greater than the minimum percent 

reduction necessary to meet the BTEX emission limit as 

determined in paragraph (f)(1) of this section. 

* * * * * 

(3) Compliance is achieved based on the applicable criteria 

in paragraphs (f)(3)(i) or (ii) of this section. 

(i) For sources meeting the HAP emission reduction 

specified in §63.1281(d)(1)(ii) or (e)(3) if the average HAP 

emission reduction calculated in paragraph (f)(2)(iii) of this 

section is equal to or greater than 95.0 percent. 

(ii) For sources required to meet the BTEX limit under 

§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. 

* * * * * 

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(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 demonstrate 

that a specific model of control device achieves the performance 

requirements in (g)(7) of this section by conducting a 

performance test as specified in paragraphs (g)(2) through (6) 

of this section. 

(2) Performance testing shall consist of three one-hour (or 

longer) test runs for each of the four following firing rate 

settings making a total of 12 test runs per test. Propene 

(propylene) gas shall be used for the testing fuel. All fuel 

analyses shall be performed by an independent third-party 

laboratory (not affiliated with the control device manufacturer 

or fuel supplier). 

(i) 90 - 100 percent of maximum design rate (fixed rate). 

(ii) 70 - 100 - 70 percent (ramp up, ramp down). Begin the 

test at 70 percent of the maximum design rate. During the first 

5 minutes, incrementally ramp the firing rate to 100 percent of 

the maximum design rate. Hold at 100 percent for 5 minutes. In 

the 10-15 minute time range, incrementally ramp back down to 70 

percent of the maximum design rate. Repeat three more times for 

a total of 60 minutes of sampling. 

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(iii) 30 - 70 - 30 percent (ramp up, ramp down). Begin the 

test at 30 percent of the maximum design rate. During the first 

5 minutes, incrementally ramp the firing rate to 70 percent of 

the maximum design rate. Hold at 70 percent for 5 minutes. In 

the 10-15 minute time range, incrementally ramp back down to 30 

percent of the maximum design rate. Repeat three more times for 

a total of 60 minutes of sampling. 

(iv) 0 - 30 - 0 percent (ramp up, ramp down). Begin the 

test at 0 percent of the maximum design rate. During the first 5 

minutes, incrementally ramp the firing rate to 30 percent of the 

maximum design rate. Hold at 30 percent for 5 minutes. In the 

10-15 minute time range, incrementally ramp back down to 0 

percent of the maximum design rate. Repeat three more times for 

a total of 60 minutes of sampling. 

(3) All models employing multiple enclosures shall be 

tested simultaneously and with all burners operational. Results 

shall be reported for the each enclosure individually and for 

the average of the emissions from all interconnected combustion 

enclosures/chambers. Control device operating data shall be 

collected continuously throughout the performance test using an 

electronic Data Acquisition System and strip chart. Data shall 

be submitted with the test report in accordance with paragraph 

(g)(8)(iii) of this section. 

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(4) Inlet testing shall be conducted as specified in 

paragraphs (g)(4)(i) through (iii) of this section. 

(i) The inlet gas flow metering system shall be located in 

accordance with Method 2A, 40 CFR part 60, appendix A-1, (or 

other approved procedure) to measure inlet gas flowrate at the 

control device inlet location. The fitting for filling fuel 

sample containers shall be located a minimum of 8 pipe diameters 

upstream of any inlet gas flow monitoring meter. 

(ii) Inlet gas flowrate shall be determined using Method 

2A, 40 CFR part 60, appendix A-1. Record the start and stop 

reading for each 60-minute THC test. Record the inlet gas 

pressure and temperature at 5-minute intervals throughout each 

60-minute THC test. 

(iii) Inlet gas sampling shall be conducted in accordance 

with the criteria in paragraphs (g)(4)(iii)(A) and (B) of this 

section. 

(A) At the inlet gas sampling location, securely connect a 

Silonite-coated stainless steel evacuated canister fitted with a 

flow controller sufficient to fill the canister over a 3 hour 

period. Filling shall be conducted as specified in the 

following: 

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(1) Open the canister sampling valve at the beginning of 

the total hydrocarbon (THC) test, and close the canister at the 

end of each THC test run. 

(2) Fill one canister across the three test runs for each 

THC test such that one composite fuel sample exists for each 

test condition. 

(3) Label the canisters individually and record on a chain 

of custody form. 

(B) Each inlet gas sample shall be analyzed using the 

following methods. The results shall be included in the test 

report. 

(1) Hydrocarbon compounds containing between one and five 

atoms of carbon plus benzene using ASTM D1945-03. 

(2) Hydrogen (H2), carbon monoxide (CO), carbon dioxide 

(CO2), nitrogen (N2), oxygen (O2) 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: 

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(A) The outlet sampling location shall be a minimum of 4 

equivalent stack diameters downstream from the highest peak 

flame or any other flow disturbance, and a minimum of one 

equivalent stack diameter upstream of the exit or any other flow 

disturbance. A minimum of two sample ports shall be used. 

(B) Flowrate shall be measured using Method 1, 40 CFR part 

60, Appendix 1, for determining flow measurement traverse point 

location; and Method 2, 40 CFR part 60, Appendix 1, shall be 

used to measure duct velocity. If low flow conditions are 

encountered (i.e., velocity pressure differentials less than 

0.05 inches of water) during the performance test, a more 

sensitive manometer or other pressure measurement device shall 

be used to obtain an accurate flow profile. 

(ii) Molecular weight shall be determined as specified in 

paragraphs (g)(4)(iii)(B), and (g)(5)(ii)(A) and (B) of this 

section. 

(A) An integrated bag sample shall be collected during the 

Method 4, 40 CFR part 60, Appendix A, moisture test. Analyze the 

bag sample using a gas chromatograph-thermal conductivity 

detector (GC-TCD) analysis meeting the following criteria: 

(1) Collect the integrated sample throughout the entire 

test, and collect representative volumes from each traverse 

location. 

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(2) The sampling line shall be purged with stack gas before 

opening the valve and beginning to fill the bag. 

(3) The bag contents shall be vigorously mixed prior to the 

GC analysis. 

(4) The GC-TCD calibration procedure in Method 3C, 40 CFR 

part 60, Appendix A, shall be modified by using EPAAlt-045 as 

follows: For the initial calibration, triplicate injections of 

any single concentration must agree within 5 percent of their 

mean to be valid. The calibration response factor for a single 

concentration re-check must be within 10 percent of the original 

calibration response factor for that concentration. If this 

criterion is not met, the initial calibration using at least 

three concentration levels shall be repeated. 

(B) Report the molecular weight of: O2, CO2, methane (CH4), 

and N2 and include in the test report submitted under 

§63.775(d)(iii). Moisture shall be determined using Method 4, 40 

CFR part 60, Appendix A. Traverse both ports with the Method 4, 

40 CFR part 60, Appendix A, sampling train during each test run. 

Ambient air shall not be introduced into the Method 3C, 40 CFR 

part 60, Appendix A, integrated bag sample during the port 

change. 

(iii) Carbon monoxide shall be determined using Method 10, 

40 CFR part 60, Appendix A. The test shall be run at the same 

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time and with the sample points used for the EPA Method 25A, 40 

CFR part 60, Appendix A, testing. An instrument range of 0-10 

per million by volume-dry (ppmvd) shall be used. 

(iv) Visible emissions shall be determined using Method 22, 

40 CFR part 60, Appendix A. The test shall be performed 

continuously during each test run. A digital color photograph of 

the exhaust point, taken from the position of the observer and 

annotated with date and time, will be taken once per test run 

and the four photos included in the test report. 

(v) Excess air shall be determined using resultant data 

from the EPA Method 3C tests and EPA Method 3B, 40 CFR part 60, 

Appendix A, equation 3B-1. 

(6) Total hydrocarbons (THC) shall be determined as 

specified by the following criteria: 

(i) Conduct THC sampling using Method 25A, 40 CFR part 60, 

Appendix A, except the option for locating the probe in the 

center 10 percent of the stack shall not be allowed. The THC 

probe must be traversed to 16.7 percent, 50 percent, and 83.3 

percent of the stack diameter during the test run. 

(ii) A valid test shall consist of three Method 25A, 40 CFR 

part 60, Appendix A, tests, each no less than 60 minutes in 

duration. 

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(iii) A 0-10 parts per million by volume-wet (ppmvw) (as 

propane) measurement range is preferred; as an alternative a 0­

30 ppmvw (as carbon) measurement range may be used. 

(iv) Calibration gases will be propane in air and be 

certified through EPA Protocol 1 – “EPA Traceability Protocol 

for Assay and Certification of Gaseous Calibration Standards,” 

September 1997, as amended August 25, 1999, EPA–600/R–97/121 (or 

more recent if updated since 1999). 

(v) THC measurements shall be reported in terms of ppmvw as 

propane. 

(vi) THC results shall be corrected to 3 percent CO2, as 

measured by Method 3C, 40 CFR part 60, Appendix A. 

(vii) Subtraction of methane/ethane from the THC data is 

not allowed in determining results. 

(7) Performance test criteria: 

(i) The control device model tested must meet the criteria 

in paragraphs (g)(7)(i)(A) through (C) of this section: 

(A) Method 22, 40 CFR part 60, Appendix A, results under 

paragraph (g)(5)(v) of this section with no indication of 

visible emissions, and 

(B) Average Method 25A, 40 CFR part 60, Appendix A, 

results under paragraph (g)(6) of this section equal to or less 

than 10.0 ppmvw THC as propane corrected to 3.0 percent CO2, and 

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(C) Average CO emissions determined under paragraph 

(g)(5)(iv) of this section equal to or less than 10 parts ppmvd, 

corrected to 3.0 percent CO2. 

(D) Excess combustion air shall be equal to or greater than 

150 percent. 

(ii) The manufacturer shall determine a maximum inlet gas 

flowrate which shall not be exceeded for each control device 

model to achieve the criteria in paragraph (g)(7)(i) of this 

section. 

(iii) A control device meeting the criteria in paragraph 

(g)(7)(i)(A) through (C) of this section will have demonstrated 

a destruction efficiency of 95.0 percent for HAP regulated under 

this subpart. 

(8) The owner or operator of a combustion control device 

model tested under this section shall submit the information 

listed in paragraphs (g)(8)(i) through (iii) in the test report 

required under §63.775(d)(1)(iii). 

(i) Full schematic of the control device and dimensions of 

the device components. 

(ii) Design net heating value (minimum and maximum) of the 

device. 

(iii) Test fuel gas flow range (in both mass and volume). 

Include the minimum and maximum allowable inlet gas flowrate. 

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(iv) Air/stream injection/assist ranges, if used. 

(v) The test parameter ranges listed in paragraphs 

(g)(8)(v)(A) through (O) of this section, as applicable for the 

tested model. 

(A) Fuel gas delivery pressure and temperature. 

(B) Fuel gas moisture range. 

(C) Purge gas usage range. 

(D) Condensate (liquid fuel) separation range. 

(E) Combustion zone temperature range. This is required for 

all devices that measure this parameter. 

(F) Excess combustion air range. 

(G) Flame arrestor(s). 

(H) Burner manifold pressure. 

(I) Pilot flame sensor. 

(J) Pilot flame design fuel and fuel usage. 

(K) Tip velocity range. 

(L) Momentum flux ratio. 

(M) Exit temperature range. 

(N) Exit flowrate. 

(O) Wind velocity and direction. 

(vi) The test report shall include all calibration quality 

assurance/quality control data, calibration gas values, gas 

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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 

by 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). 

(3) Devices shall be operated with no visible emissions, 

except for periods not to exceed a total of 2 minutes during any 

hour. A visible emissions test using Method 22, 40 CFR part 60, 

Appendix A, shall be performed each calendar quarter. The 

observation period shall be 1 hour and shall be conducted 

according to EPA Method 22, 40 CFR part 60, Appendix A. 

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(4) Compliance with the operating parameter limit is 

achieved when the following criteria are met: 

(i) The inlet gas flowrate monitored under paragraph (h)(1) 

of this section is equal to or below the maximum established by 

the manufacturer; and 

(ii) The pilot flame is present at all times; and 

(iii) During the visible emissions test performed under 

paragraph (h)(3) of this section the duration of visible 

emissions does not exceed a total of 2 minutes during the 

observation period. Devices failing the visible emissions test 

shall follow manufacturers repair instructions, if available, or 

best combustion engineering practice as outlined in the unit 

inspection and maintenance plan, to return the unit to compliant 

operation. All repairs and maintenance activities for each unit 

shall be recorded in a maintenance and repair log and shall be 

available on site for inspection. 

(iv) Following return to operation from maintenance or 

repair activity, each device must pass a Method 22 visual 

observation as described in paragraph (h)(3) of this section. 

30. Section 63.1283 is amended by: 

a. Adding paragraph (b); 

b. Revising paragraph (d)(1) introductory text; 

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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); 

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. 

* * * * * 

(b) The owner or operator of a control device whose model 

was tested under 63.1282(g) shall develop an inspection and 

maintenance plan for each control device. At a minimum, the plan 

shall contain the control device manufacturer’s recommendations 

for ensuring proper operation of the device. Semi-annual 

inspections shall be conducted for each control device with 

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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 determination 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: 

* * * * * 

(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 

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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 procedures alternative to those specified in 

paragraphs (d)(1)(ii)(A) through (E) of this section in your 

site-specific monitoring plan. 

(A) The performance criteria and design specifications for 

the monitoring system equipment, including the sample interface, 

detector signal analyzer, and data acquisition and calculations; 

(B) Sampling interface (e.g., thermocouple) location such 

that the monitoring system will provide representative 

measurements; 

(C) Equipment performance checks, system accuracy audits, 

or other audit procedures; 

(D) Ongoing operation and maintenance procedures in 

accordance with provisions in §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 

performance checks, system accuracy audits, or other audit 

procedures specified in the site-specific monitoring plan at 

least once every 12 months. 

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(iv) The owner or operator must conduct a performance 

evaluation of each CPMS in accordance with the site-specific 

monitoring plan. 

(2) An owner or operator is exempted from the monitoring 

requirements specified in paragraphs (d)(3) through (7) of this 

section for the following types of control devices: 

(i) Except for control devices for small glycol dehydration 

units, a boiler or process heater in which all vent streams are 

introduced with the primary fuel or are used as the primary 

fuel; 

(ii) Except for control devices for small glycol 

dehydration units, a boiler or process heater with a design heat 

input capacity equal to or greater than 44 megawatts. 

(3) * * * 

(i) * * * 

(A) For a thermal vapor incinerator that demonstrates 

during the performance test conducted under §63.1282(d) that 

combustion zone temperature is an accurate indicator of 

performance, a temperature monitoring device equipped with a 

continuous recorder. The monitoring device shall have a minimum 

accuracy of ±2 percent of the temperature being monitored in °C, 

or ±2.5°C, whichever value is greater. The temperature sensor 

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shall be installed at a location representative of the 

combustion zone temperature. 

* * * * * 

(D) For a boiler or process heater, a temperature 

monitoring device equipped with a continuous recorder. The 

temperature monitoring device shall have a minimum accuracy of 

±2 percent of the temperature being monitored in °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 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-GLYCalcTM , Version 

3.0 or higher, ProMax, or AspenTech HYSYS. Inputs to the models 

shall be representative of actual operating conditions of the 

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controlled unit. The determination shall be performed to 

coincide with the visible 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 inlet gas flowrate, the owner or operator must 

calculate the daily average value for each monitored operating 

parameter for each operating day. If the emissions unit 

operation is continuous, the operating day is a 24-hour period. 

If the emissions unit operation is not continuous, the operating 

day is the total number of hours of control device operation per 

24-hour period. Valid data points must be available for 75 

percent of the operating hours in an operating day to compute 

the daily average. 

(5) * * * 

(i) The owner or operator shall establish a minimum 

operating parameter value or a maximum operating parameter 

value, as appropriate for the control device, to define the 

conditions at which the control device must be operated to 

continuously achieve the applicable performance requirements of 

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§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 

established based on values measured during the performance test 

and supplemented, as necessary, by a condenser design analysis 

or control device manufacturer's recommendations or a 

combination of both. 

(B) If the owner or operator uses a condenser design 

analysis in accordance with the requirements of §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 operating parameter value shall be 

established based on the condenser design analysis and may be 

supplemented by the condenser manufacturer's recommendations. 

(C) If the owner or operator operates a control device 

where the performance test requirement was met under §63.1282(g) 

to demonstrate that the control device achieves the applicable 

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performance requirements specified in §63.1281(d)(1), (e)(3)(ii) 

or (f)(1), then the maximum inlet gas flowrate shall be 

established based on the performance test and supplemented, as 

necessary, by the manufacturer recommendations. 

(ii) * * * 

(A) If the owner or operator conducts a performance test in 

accordance with the requirements of §63.1282(d)(3) to 

demonstrate that the condenser achieves the applicable 

performance requirements 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 recommendations, 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 in §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 

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documented in the GRI report entitled, “Atmospheric Rich/Lean 

Method for Determining Glycol Dehydrator Emissions” (GRI– 

95/0368.1) as inputs for the model GRI-GLYCalcTM, Version 3.0 or 

higher, to generate a condenser performance curve. 

(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 calculated 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 

requirements of §63.1282(f)(2)(iii) is less than the identified 

30-day required percent reduction. 

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* * * * * 

(v) For control device whose model is tested under 

§63.1282(g) an excursion occurs when: 

(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) * * * 

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(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 in 

paragraphs (b)(3)(i) through (iv) of this section shall not be 

included in any average or percent leak rate computed under this 

subpart. Records shall be kept of the times and durations of all 

such periods and any other periods during process or control 

device operation when monitors are not operating or failed to 

collect required data. 

* * * * * 

(ii) [Reserved] 

* * * * * 

(4) * * * 

(ii) Records of the daily average value of each 

continuously monitored parameter for each operating day 

determined according to the procedures specified in 

§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 

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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. 

(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 pollution control equipment and monitoring 

equipment. The owner or operator shall maintain records of 

actions taken during periods of malfunction to minimize 

emissions in accordance with §63.1274(h), including corrective 

actions to restore malfunctioning process and air pollution 

control and monitoring equipment to its normal or usual manner 

of operation. 

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(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 visible emission readings and flowrate calculations 

made during the compliance determination required by 

§63.1282(h); and 

(2) All hourly records and other recorded periods when the 

pilot flame is absent. 

(h) The date the semi-annual maintenance inspection 

required under §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; 

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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. Revising paragraph (e)(2) introductory text; 

o. Revising paragraphs (e)(2)(ii)(B); 

p. Adding paragraphs (e)(2)(ii)(D) and (E); 

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 

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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 

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 

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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 Compliance 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 specified in paragraphs 

(d)(1) through (12) of this section. This information may be 

submitted in an operating permit application, in an amendment to 

an operating permit application, in a separate submittal, or in 

any combination of the three. If all of the information required 

under this paragraph have been submitted at any time prior to 

180 days after the applicable compliance dates specified in 

§63.1270(d), a separate Notification of Compliance Status Report 

is not required. If an owner or operator submits the information 

specified in paragraphs (d)(1) through (12) of this section at 

different times, and/or different submittals, subsequent 

submittals may refer to previous submittals instead of 

duplicating and resubmitting the previously submitted 

information. 

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(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 this 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 performance test results including the 

information specified in paragraphs (d)(1)(ii)(A) and (B) of 

this section. Results of a performance test conducted prior to 

the compliance date of this subpart can be used provided that 

the test was conducted using the methods specified in 

§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/. 

* * * * * 

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(2) If a closed-vent system and a flare are used to comply 

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 be 

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 

shall include any data and calculations used to develop the 

value, and a description of why the chosen value indicates that 

the control device is operating in accordance with the 

applicable requirements of §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). 

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* * * * * 

(10) The owner or operator shall submit the analysis 

prepared under §63.1281(e)(2) to demonstrate that the conditions 

by which the facility will be operated to achieve the HAP 

emission reduction of 95.0 percent, or the BTEX limit in 

§63.1275(b)(1)(iii) through process modifications or a 

combination of process modifications and one or more control 

devices. 

(11) If the owner or operator installs a combustion 

control device model tested under the procedures in §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. 

(ii) Control device model number. 

(iii) Control device serial number. 

(iv) Date the model of control device was tested by the 

manufacturer. 

(v) Manufacturer’s HAP destruction efficiency rating. 

(vi) Control device operating parameters, maximum allowable 

inlet gas flowrate. 

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* * * * * 

(e) * * * 

(2) The owner or operator shall include the information 

specified in paragraphs (e)(2)(i) through (xiii) of this 

section, as applicable. 

* * * * * 

(ii) * * * 

(B) For each excursion caused when the 30-day average 

condenser control efficiency is less than the value, as 

specified in §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 identified and the date 

and duration of the period that the excursion occurred. 

(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 

period that the excursion occurred, repairs affected to the 

unit, and date the unit was returned to service. 

* * * * * 

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(x) The results of any periodic test as required in 

§63.1282(d)(3) conducted during the reporting period. 

(xi) For each carbon adsorber used 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 

§63.1284(h). 

(xiii) Certification by a responsible official of truth, 

accuracy, and completeness. This certification shall state that, 

based on information and belief formed after reasonable inquiry, 

the statements and information in the document are true, 

accurate, and complete. 

* * * * * 

(g) Electronic reporting. (1) Within 60 days after the date 

of completing each performance test (defined in §63.2) as 

required by this subpart you must submit the results of the 

performance tests required by this subpart to EPA’s WebFIRE 

database by using the Compliance and Emissions Data Reporting 

Interface (CEDRI) that is accessed through EPA’s Central Data 

Exchange (CDX)(www.epa.gov/cdx). Performance test data must be 

submitted in the file format generated through use of EPA’s 

Electronic Reporting Tool (ERT) (see 

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Page 581 of 588 

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 claim that some of the 

information being submitted for performance tests is 

confidential business information (CBI) must submit a complete 

ERT file including information claimed to be CBI on a compact 

disk or other commonly used electronic storage media (including, 

but not limited to, flash drives) to EPA. The electronic media 

must be clearly marked as CBI and mailed to U.S. EPA/OAPQS/CORE 

CBI Office, Attention: WebFIRE Administrator, MD C404-02, 4930 

Old Page Rd., Durham, NC 27703. The same ERT file with the CBI 

omitted must be submitted to EPA via CDX as described earlier in 

this paragraph. At the discretion of the delegated authority, 

you must also submit these reports, including the confidential 

business information, to the delegated authority in the format 

specified by the delegated authority. 

(2) All reports required by this subpart not subject to the 

requirements in paragraph (g)(1) of this section must be sent to 

the Administrator at the appropriate address listed in §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 

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or hard copy). The Administrator retains the right to require 

submittal of reports subject to paragraph (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 emission limitation will achieve a 

reduction in HAP emissions at least equivalent to the reduction 

in HAP emissions from that source achieved under the applicable 

requirements in §§63.1274 through 63.1281, the Administrator 

will publish a notice in the Federal Register permitting the use 

of the alternative means for purposes of compliance with that 

requirement. The notice may condition the permission on 

requirements related to the operation and maintenance of the 

alternative means. 

* * * * * 

34. Appendix to Subpart HHH of Part 63 – Table is amended by 

revising Table 2 to read as follows: 

Appendix to Subpart HHH of Part 63—Tables 

* * * * * 

Table 2 to Subpart HHH of Part 63—Applicability of 40 CFR Part

63 General Provisions to Subpart HHH

General provisions Applicable Explanation

reference to 

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§63.1(a)(1)

§63.1(a)(2)

§63.1(a)(3)

§63.1(a)(4)

§63.1(a)(5)

§63.1(a)(6)

through (a)(8)

§63.1(a)(9)

§63.1(a)(10)

§63.1(a)(11)

§63.1(a)(12)

through (a)(14)

§63.1(b)(1) 

§63.1(b)(2)

§63.1(b)(3)

§63.1(c)(1) 

§63.1(c)(2)

§63.1(c)(3)

§63.1(c)(4)

§63.1(c)(5)

§63.1(d)

§63.1(e)

§63.2 

§63.3(a) through

(c)

§63.4(a)(1)

through (a)(3)

§63.4(a)(4)

§63.4(a)(5)

§63.4(b)

§63.4(c)

§63.5(a)(1)

§63.5(a)(2) 

§63.5(b)(1)

§63.5(b)(2)

§63.5(b)(3) 

subpart HHH

Yes. 

Yes. 

Yes. 

Yes. 

No 

Yes. 

No 

Yes. 

Yes. 

Yes. 

No 

Yes. 

No. 

No 

No. 

No 

Yes. 

Yes. 

No 

Yes. 

Yes 

Yes. 

Yes. 

No 

Yes. 

Yes. 

Yes. 

Yes. 

No 

Yes. 

No 

Yes. 

Section reserved. 

Section reserved. 

Subpart HHH specifies

applicability. 

Subpart HHH specifies

applicability. 

Section reserved. 

Section reserved. 

Except definition of major

source is unique for this source

category and there are

additional definitions in 

subpart HHH. 

Section reserved. 

Preconstruction review required

only for major sources that

commence construction after 

promulgation of the standard. 

Section reserved. 

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§63.5(b)(4)

§63.5(b)(5)

§63.5(b)(6)

§63.5(c)

§63.5(d)(1)

§63.5(d)(2)

§63.5(d)(3)

§63.5(d)(4)

§63.5(e)

§63.5(f)(1)

§63.5(f)(2)

§63.6(a)

§63.6(b)(1)

§63.6(b)(2)

§63.6(b)(3)

§63.6(b)(4)

§63.6(b)(5)

§63.6(b)(6)

§63.6(b)(7)

§63.6(c)(1)

§63.6(c)(2)

§63.6(c)(3) and

(c)(4)

§63.6(c)(5)

§63.6(d)

§63.6(e)

§63.6(e)

§63.6(e)(1)(i) 

§63.6(e)(1)(ii)

§63.6(e)(1)(iii) 

§63.6(e)(2)

§63.6(e)(3)

§63.6(f)(1)

§63.6(f)(2)

§63.6(f)(3)

§63.6(g)

§63.6(h)(1)

§63.6(h)(2)

through (h)(9)

§63.6(i)(1)

through (i)(14)

§63.6(i)(15)

§63.6(i)(16)

§63.6(j) 

Yes. 

Yes. 

Yes. 

No 

Yes. 

Yes. 

Yes. 

Yes. 

Yes. 

Yes. 

Yes. 

Yes. 

Yes. 

Yes. 

Yes. 

Yes. 

Yes. 

No 

Yes. 

Yes. 

Yes. 

No 

Yes. 

No 

Yes. 

Yes 

No 

No. 

Yes. 

Yes. 

No. 

No. 

Yes. 

Yes. 

Yes. 

No. 

Yes. 

Yes. 

No 

Yes. 

Yes. 

Section reserved. 

Section reserved. 

Section reserved. 

Section reserved. 

Except as otherwise specified.

See §63.1274(h) for general duty

requirement. 

Section reserved. 

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Page 585 of 588 

§63.7(a)(1) Yes. 

§63.7(a)(2) Yes 

§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 

§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). No. 

§63.8(c)(1)(ii). Yes. 

§63.8(c)(1)(iii) No. 

§63.8(c)(2) Yes. 

§63.8(c)(3) Yes. 

§63.8(c)(4) No. 

§63.8(c)(5) Yes. 

through (c)(8)

§63.8(d) Yes. 

§63.8(d)(3) Yes 

§63.8(e) Yes 

§63.8(f)(1) Yes 

through (f)(5)

§63.8(f)(6) No 

§63.8(g) No 

But the performance test results

must be submitted within 180 

days after the compliance date. 

Section reserved. 

Except for last sentence, which

refers to an SSM plan. SSM plans

are not required.

Subpart HHH does not

specifically require continuous

emissions monitor performance

evaluations, however, the

Administrator can request that

one be conducted. 

Subpart HHH does not require

continuous emissions monitoring.

Subpart HHH specifies continuous 

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Page 586 of 588 

§63.9(a) Yes. 

§63.9(b)(1) Yes. 

§63.9(b)(2) Yes 

§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) Yes. 

through (h)(3)

§63.9(h)(4) No 

§63.9(h)(5) and Yes. 

(h)(6)

§63.9(i) Yes. 

§63.9(j) Yes. 

§63.10(a) Yes. 

§63.10(b)(1) Yes 

§63.10(b)(2) Yes. 

§63.10(b)(2)(i) No. 

§63.10(b)(2)(ii) No 

§63.10(b)(2)(iii) Yes. 

§63.10(b)(2)(iv) No. 

through

(b)(2)(v)

§63.10(b)(2)(vi) Yes. 

through

(b)(2)(xiv)

§63.10(b)(3) No. 

§63.10(c)(1) Yes. 

§63.10(c)(2) No 

monitoring system data reduction

requirements. 

Existing sources are given 1

year (rather than 120 days) to

submit this notification. 

Section reserved. 

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. 

See §63.1284(f) for

recordkeeping of (1) occurrence

and duration and (2) actions

taken during malfunction. 

Sections reserved. 

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Page 587 of 588 

through (c)(4)

§63.10(c)(5) Yes. 

through (c)(8)

§63.10(c)(9) No 

§63.10(c)(10) No 

through (c)(11)

§63.10(c)(12) Yes. 

through (c)(14)

§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 

§63.10(e)(1) Yes. 

§63.10(e)(2) Yes. 

§63.10(e)(3)(i) Yes 

§63.10(e)(3)(i)(A) Yes.

§63.10(e)(3)(i)(B) Yes.

§63.10(e)(3)(i)(C) No 

§63.10(e)(3)(ii) Yes. 

through

(e)(3)(viii)

§63.10(f) Yes. 

§63.11(a) and (b) Yes. 

§63.11(c), (d), Yes. 

and (e)

§63.12(a) through Yes. 

(c)

§63.13(a) through Yes. 

(c)

§63.14(a) and (b) Yes. 

§63.15(a) and (b) Yes. 

Section reserved. 

See §63.1284(f) for

recordkeeping of malfunctions. 

See §63.1285(b)(6) for reporting

of malfunctions. 

Subpart HHH requires major

sources to submit Periodic 

Reports semi-annually. 

Subpart HHH does not require

quarterly reporting for excess

emissions. 

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Page 588 of 588 

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