Vol. 77 Thursday, 

No. 159 August 16, 2012 

Part II 

Environmental Protection Agency 

40 CFR Parts 60 and 63 

Oil and Natural Gas Sector: New Source Performance Standards and 

National Emission Standards for Hazardous Air Pollutants Reviews; Final 

Rule 

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49490 Federal Register / Vol. 77, No. 159 / Thursday, August 16, 2012 / Rules and Regulations 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Parts 60 and 63 

[EPA–HQ–OAR–2010–0505; FRL–9665–1] 

RIN 2060–AP76 

Oil and Natural Gas Sector: New 

Source Performance Standards and 

National Emission Standards for 

Hazardous Air Pollutants Reviews 

AGENCY: Environmental Protection 

Agency (EPA). 

ACTION: Final rule. 

SUMMARY: This action finalizes the 

review of new source performance 

standards for the listed oil and natural 

gas source category. In this action the 

EPA revised the new source 

performance standards for volatile 

organic compounds from leaking 

components at onshore natural gas 

processing plants and new source 

performance standards for sulfur 

dioxide emissions from natural gas 

processing plants. The EPA also 

established standards for certain oil and 

gas operations not covered by the 

existing standards. In addition to the 

operations covered by the existing 

standards, the newly established 

standards will regulate volatile organic 

compound emissions from gas wells, 

centrifugal compressors, reciprocating 

compressors, pneumatic controllers and 

storage vessels. This action also 

finalizes the residual risk and 

technology review for the Oil and 

Natural Gas Production source category 

and the Natural Gas Transmission and 

Storage source category. This action 

includes revisions to the existing leak 

detection and repair requirements. In 

addition, the EPA has established in this 

action emission limits reflecting 

maximum achievable control 

technology for certain currently 

uncontrolled emission sources in these 

source categories. This action also 

includes modification and addition of 

testing and monitoring and related 

notification, recordkeeping and 

reporting requirements, as well as other 

minor technical revisions to the national 

emission standards for hazardous air 

pollutants. This action finalizes 

revisions to the regulatory provisions 

related to emissions during periods of 

startup, shutdown and malfunction. 

DATES: This final rule is effective on 

October 15, 2012. The incorporation by 

reference of certain publications listed 

in this rule is approved by the Director 

of the Federal Register as of October 15, 

2012. 

ADDRESSES: The EPA has established a 

docket for this action under Docket ID. 

No. EPA–HQ–OAR–2010–0505. All 

documents in the docket are listed on 

the http://www.regulations.gov Web 

site. Although listed in the index, some 

information is not publicly available, 

e.g., confidential business information 

or other information whose disclosure is 

restricted by statute. Certain other 

material, such as copyrighted material, 

is not placed on the Internet and will be 

publicly available only in hard copy 

form. Publicly available docket 

materials are available either 

electronically through http:// 

www.regulations.gov or in hard copy at 

the EPA’s Docket Center, Public Reading 

Room, EPA West Building, Room 

Number 3334, 1301 Constitution 

Avenue NW., Washington, DC 20004. 

This Docket Facility is open from 8:30 

a.m. to 4:30 p.m. Eastern Standard 

Time, Monday through Friday, 

excluding legal holidays. The telephone 

number for the Public Reading Room is 

(202) 566–1744, and the telephone 

number for the Air Docket is (202) 566– 

1742. 

FOR FURTHER INFORMATION CONTACT: For 

further information about this final 

action, contact Mr. Bruce Moore, Sector 

Policies and Programs Division (E143– 

05), Office of Air Quality and Standards, 

Environmental Protection Agency, 

Research Triangle Park, North Carolina 

27711, telephone number: (919) 541– 

5460; facsimile number: (919) 685–3200; 

email address: moore.bruce@epa.gov. 

For additional contact information, see 

the following SUPPLEMENTARY

INFORMATION section. 

SUPPLEMENTARY INFORMATION: For 

specific information regarding risk 

assessment and exposure modeling 

methodology, contact Mr. Mark Morris, 

Health and Environmental Impacts 

Division (C504–06), Office of Air 

Quality Planning and Standards, U.S. 

Environmental Protection Agency, 

Research Triangle Park, NC 27711; 

telephone number (919) 541–5416; fax 

number: (919) 541–0840; and email 

address: morris.mark@epa.gov. 

Organization of This Document. The 

information presented in this preamble 

is organized as follows: 

I. Preamble Acronyms and Abbreviations 

II. General Information 

A. Executive Summary 

B. Does this action apply to me? 

C. What are the emission sources affected 

by this action? 

D. Where can I get a copy of this 

document? 

E. Judicial Review 

III. Background Information on the NSPS and 

NESHAP 

A. What are the statutory authorities for the 

NSPS and NESHAP? 

B. What is the litigation history? 

C. What is the sector-based approach? 

D. What are the health effects of pollutants 

emitted from the oil and natural gas 

sector? 

IV. Summary of the Final NSPS Rule 

A. What are the final actions relative to the 

NSPS for the Crude Oil and Natural Gas 

Production source category? 

B. What are the effective and compliance 

dates for the final NSPS? 

V. Summary of the Significant Changes to the 

NSPS Since Proposal 

A. Gas Well Affected Facilities 

B. Centrifugal and Reciprocating 

Compressor Affected Facilities 

C. Pneumatic Controller Affected Facilities 

D. Storage Vessel Affected Facilities 

E. Equipment Leaks Affected Facilities and 

Sweetening Unit Affected Facilities at 

Onshore Natural Gas Processing Plants 

F. Changes to Notification, Recordkeeping 

and Reporting Requirements 

VI. Summary of the Final NESHAP Rules 

A. What are the final rule actions relative 

to the Oil and Natural Gas Production 

(subpart HH) source category? 

B. What are the final rule amendments for 

the Natural Gas Transmission and 

Storage (subpart HHH) source category? 

C. What is the effective date of this final 

rule and compliance dates for the 

standards? 

VII. Summary of the Significant Changes to 

the NESHAP Since Proposal 

A. What are the significant changes since 

proposal for the Oil and Natural Gas 

Production (subpart HH) source 

category? 

B. What are the significant changes since 

proposal for the Natural Gas 

Transmission and Storage (subpart HHH) 

source category? 

VIII. Compliance Related Issues Common to 

the NSPS and NESHAP 

A. How do the rules address startup, 

shutdown and malfunction? 

B. How do the NSPS and NESHAP provide 

for compliance assurance? 

C. What are the requirements for 

submission of performance test data to 

the EPA? 

IX. Summary of Significant NSPS Comments 

and Responses 

A. Major Comments Concerning 

Applicability 

B. Major Comments Concerning Well 

Completions 

C. Major Comments Concerning Pneumatic 

Controllers 

D. Major Comments Concerning 

Compressors 

E. Major Comments Concerning Storage 

Vessels 

F. Major Comments Concerning 

Notification, Recordkeeping and 

Reporting Requirements 

X. Summary of Significant NESHAP 

Comments and Responses 

A. Major Comments Concerning Previously 

Unregulated Sources 

B. Major Comments Concerning the Risk 

Review 

C. Major Comments Concerning the 

Technology Review 

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Federal Register / Vol. 77, No. 159 / Thursday, August 16, 2012 / Rules and Regulations 49491 

D. Major Comments Concerning 

Notification, Recordkeeping and 

Reporting Requirements 

XI. What are the cost, environmental and 

economic impacts of the final NESHAP 

and NSPS amendments? 

A. What are the air impacts? 

B. What are the energy impacts? 

C. What are the cost impacts? 

D. What are the economic impacts? 

E. What are the benefits of this final rule? 

XII. Statutory and Executive Order Reviews 

A. Executive Order 12866: Regulatory 

Planning and Review and Executive 

Order 13563: Improving Regulation and 

Regulatory Review 

B. Paperwork Reduction Act 

C. Regulatory Flexibility Act 

D. Unfunded Mandates Reform Act 

E. Executive Order 13132: Federalism 

F. Executive Order 13175: Consultation 

and Coordination With Indian Tribal 

Governments 

G. Executive Order 13045: Protection of 

Children From Environmental Health 

Risks and Safety Risks 

H. Executive Order 13211: Actions 

Concerning Regulations That 

Significantly Affect Energy Supply, 

Distribution, or Use 

I. National Technology Transfer and 

Advancement Act 

J. Executive Order 12898: Federal Actions 

To Address Environmental Justice in 

Minority Populations and Low-Income 

Populations 

K. Congressional Review Act 

I. Preamble Acronyms and 

Abbreviations 

Several acronyms and terms used to 

describe industrial processes, data 

inventories and risk modeling are 

included in this preamble. While this 

may not be an exhaustive list, to ease 

the reading of this preamble and for 

reference purposes, the following terms 

and acronyms are defined here: 

API American Petroleum Institute 

BACT Best Available Control Technology 

BDT Best Demonstrated Technology 

bpd Barrels Per Day 

BMP Best Management Practice 

BSER Best System of Emission Reduction 

BTEX Benzene, Ethylbenzene, Toluene and 

Xylene 

CAA Clean Air Act 

CBM Coal Bed Methane 

CDX Central Data Exchange 

CEDRI Compliance and Emissions Data 

Reporting Interface 

CFR Code of Federal Regulations 

CO Carbon Monoxide 

CO2 Carbon Dioxide 

CO2e Carbon Dioxide Equivalent 

DOE United States Department of Energy 

e-GGRT Electronic Greenhouse Gas 

Reporting Tool 

EPA Environmental Protection Agency 

ERPG Emergency Response Planning 

Guidelines 

ERT Electronic Reporting Tool 

GCG Gas Condensate Glycol 

GHG Greenhouse Gas 

GOR Gas to Oil Ratio 

GWP Global Warming Potential 

HAP Hazardous Air Pollutants 

HEM–3 Human Exposure Model, version 3 

HI Hazard Index 

HP Horsepower 

HQ Hazard Quotient 

H2S Hydrogen Sulfide 

ICR Information Collection Request 

IPCC Intergovernmental Panel on Climate 

Change 

IRIS Integrated Risk Information System 

km Kilometer 

kW Kilowatts 

LAER Lowest Achievable Emission Rate 

lb Pounds 

LDAR Leak Detection and Repair 

MACT Maximum Achievable Control 

Technology 

MACT Code NEI code used to identify 

processes included in a source category 

Mcf Thousand Cubic Feet 

Mg/yr Megagrams per year 

MIR Maximum Individual Risk 

MIRR Monitoring, Inspection, 

Recordkeeping and Reporting 

MMtCO2e Million Metric Tons of Carbon 

Dioxide Equivalents 

NAAQS National Ambient Air Quality 

Standards 

NAC/AEGL National Advisory Committee 

for Acute Exposure Guideline Levels for 

Hazardous Substances 

NAICS North American Industry 

Classification System 

NAS National Academy of Sciences 

NATA National Air Toxics Assessment 

NEI National Emissions Inventory 

NEMS National Energy Modeling System 

NESHAP National Emissions Standards for 

Hazardous Air Pollutants 

NGL Natural Gas Liquids 

NIOSH National Institutes for Occupational 

Safety and Health 

NOX Oxides of Nitrogen 

NRC National Research Council 

NSPS New Source Performance Standards 

NSR New Source Review 

NTTAA National Technology Transfer and 

Advancement Act 

OAQPS Office of Air Quality Planning and 

Standards 

OMB Office of Management and Budget 

PB–HAP Hazardous air pollutants known to 

be persistent and bio-accumulative in the 

environment 

PFE Potential for Flash Emissions 

PM Particulate Matter 

PM2.5 Particulate Matter (2.5 microns and 

less) 

POM Polycyclic Organic Matter 

ppm Parts per Million 

ppmv Parts per Million by Volume 

PSIG Pounds per Square Inch Gauge 

PSIA Pounds per Square Inch Absolute 

PTE Potential to Emit 

QA Quality Assurance 

RACT Reasonably Available Control 

Technology 

RBLC RACT/BACT/LAER Clearinghouse 

REC Reduced Emissions Completions 

REL California EPA Reference Exposure 

Level 

RFA Regulatory Flexibility Act 

RfC Reference Concentration 

RfD Reference Dose 

RIA Regulatory Impact Analysis 

RICE Reciprocating Internal Combustion 

Engines 

RTR Residual Risk and Technology Review 

SAB Science Advisory Board 

SBREFA Small Business Regulatory 

Enforcement Fairness Act 

SCC Source Classification Codes 

scfh Standard Cubic Feet Per Hour 

scfm Standard Cubic Feet Per Minute 

scm Standard Cubic Meters 

scmd Standard Cubic Meters per Day 

SCOT Shell Claus Offgas Treatment 

SIP State Implementation Plan 

SISNOSE Significant Economic Impact on a 

Substantial Number of Small Entities 

S/L/T State and Local and Tribal Agencies 

SO2 Sulfur Dioxide 

SSM Startup, Shutdown and Malfunction 

STEL Short-term Exposure Limit 

TLV Threshold Limit Value 

TOSHI Target Organ-Specific Hazard Index 

tpy Tons per Year 

TRIM Total Risk Integrated Modeling 

System 

TRIM.FaTE A spatially explicit, 

compartmental mass balance model that 

describes the movement and 

transformation of pollutants over time, 

through a user-defined, bounded system 

that includes both biotic and abiotic 

compartments 

TSD Technical Support Document 

UF Uncertainty Factor 

UMRA Unfunded Mandates Reform Act 

URE Unit Risk Estimate 

VCS Voluntary Consensus Standards 

VOC Volatile Organic Compounds 

VRU Vapor Recovery Unit 

II. General Information 

A. Executive Summary 

1. Purpose of the Regulatory Action 

Responding to the requirements of a 

consent decree, this action finalizes 

several rules that apply to the oil and 

gas production industry and 

significantly reduce emissions of air 

pollutants. More particularly, the action 

finalizes: 

• New source performance standards 

(NSPS) for the Crude Oil and Natural 

Gas Production and onshore natural gas 

processing plant source category. The 

EPA reviewed two existing NSPS for 

onshore natural gas processing plant 

source category under section 111(b) of 

the Clean Air Act (CAA). This action 

improves the existing NSPS and 

finalizes standards for certain crude oil 

and natural gas sources that are not 

covered by existing NSPS for this sector. 

• National Emissions Standards for 

Hazardous Air Pollutants (NESHAP) for 

the Oil and Natural Gas Production 

source category and the Natural Gas 

Transmission and Storage source 

category. The EPA conducted risk and 

technology reviews (RTR) for these rules 

under section 112 of the CAA. In 

addition, the EPA has established 

emission limits for certain currently 

uncontrolled emission sources in these 

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49492 Federal Register / Vol. 77, No. 159 / Thursday, August 16, 2012 / Rules and Regulations 

source categories. These limits reflect 

maximum achievable control 

technology (MACT). 

2. Summary of the Major Provisions of 

the Regulatory Actions 

New Source Performance Standards 

(NSPS). The newly established NSPS for 

the Crude Oil and Natural Gas 

Production source category regulate 

volatile organic compound (VOC) 

emissions from gas wells, centrifugal 

compressors, reciprocating compressors, 

pneumatic controllers, storage vessels 

and leaking components at onshore 

natural gas processing plants, as well as 

sulfur dioxide (SO2) emissions from 

onshore natural gas processing plants. 

This rule sets cost-effective performance 

standards for: 

Gas wells. The rule covers any gas 

well that is ‘‘an onshore well drilled 

principally for production of natural 

gas.’’ Oil wells (wells drilled principally 

for the production of crude oil) are not 

subject to this rule. For fractured and 

refractured gas wells, the rule generally 

requires owners/operators to use 

reduced emissions completions, also 

known as ‘‘RECs’’ or ‘‘green 

completions,’’ to reduce VOC emissions 

from well completions. To achieve these 

VOC reductions, owners and/or 

operators may use RECs or completion 

combustion devices, such as flaring, 

until January 1, 2015; as of January 1, 

2015, owners and/or operators must use 

RECs and a completion combustion 

device. The rule does not require RECs 

where their use is not feasible, as 

specified in the rule. See sections IX.A 

and IX.B of this preamble for further 

discussion. 

Storage vessels. Individual storage 

vessels in the oil and natural gas 

production segment and the natural gas 

processing, transmission and storage 

segments with emissions equal to or 

greater than 6 tons per year (tpy) must 

achieve at least 95.0 percent reduction 

in VOC emissions. See section IX.E of 

this preamble for further discussion. 

Certain controllers. The rule sets a 

natural gas bleed rate limit of 6 scfh for 

individual, continuous bleed, natural 

gas-driven pneumatic controllers 

located between the wellhead and the 

point at which the gas enters the 

transmission and storage segment. For 

individual, continuous bleed, natural 

gas-driven pneumatic controllers 

located at natural gas processing plants, 

the rule sets a natural gas bleed limit of 

zero scfh. See section IX.C of this 

preamble for further discussion. 

Certain compressors. The rule 

requires a 95.0 percent reduction of 

VOC emissions from wet seal centrifugal 

compressors located between the 

wellhead and the point at which the gas 

enters the transmission and storage 

segment. The rule also requires 

measures intended to reduce VOC 

emissions from reciprocating 

compressors located between the 

wellhead and the point where natural 

gas enters the natural gas transmission 

and storage segment. Owners and/or 

operators of these compressors must 

replace the rod packing based on 

specified usage or time. See section IX.D 

of this preamble for further discussion. 

For onshore natural gas processing 

plants, this final action revises the 

existing NSPS requirements for leak 

detection and repair (LDAR) to reflect 

the procedures and leak thresholds 

established in the NSPS for Equipment 

Leaks of VOCs in the Synthetic Organic 

Chemicals Manufacturing Industry. This 

final action also revises the existing 

NSPS requirements for SO2 emission 

reductions 99.8 percent to 99.9 percent 

based on reanalysis of the original data. 

National Emissions Standards for 

Hazardous Air Pollutants (NESHAP). 

This action also revises the NESHAP for 

glycol dehydration unit process vents 

and leak detection and repair (LDAR) 

requirements. In the final rule for major 

sources at oil and natural gas 

production facilities, we have lowered 

the leak definition for valves at natural 

gas processing plants to 500 parts per 

million (ppm) and thus require the 

application of LDAR procedures at this 

level. In this final rule, we also have 

established MACT standards for ‘‘small’’ 

glycol dehydration units, which were 

unregulated under the initial NESHAP. 

Covered glycol dehydrators are those 

with an actual annual average natural 

gas flow rate less than 85,000 standard 

cubic meters per day (scmd) or actual 

average benzene emissions less than 1 

ton per year (tpy), and they must meet 

unit-specific limits for benzene, 

ethylbenzene, toluene and xylene 

(BTEX). 

In the final rule for major sources at 

natural gas transmission and storage 

facilities, we have established MACT 

standards for ‘‘small’’ glycol 

dehydrators also not regulated under the 

initial NESHAP. Covered glycol 

dehydrators are those with an actual 

annual average natural gas flow rate less 

than 283,000 scmd or actual average 

benzene emissions less than 0.90 Mg/yr, 

and they must meet unit-specific BTEX 

emission limits. v. See sections VII and 

X of this preamble for further discussion 

of both standards. 

3. Costs and Benefits 

Table 1 summarizes the costs and 

benefits of this action. See section XI of 

this preamble for further discussion. 

TABLE 1—SUMMARY OF THE MONETIZED BENEFITS, SOCIAL COSTS AND NET BENEFITS FOR THE FINAL OIL AND NATURAL

GAS NSPS AND NESHAP AMENDMENTS IN 2015 

[Millions of 2008$] 1

Final NSPS Final NESHAP amendments Final NSPS and NESHAP 

amendments combined 

Total Monetized Benefits 2 ............. N/A ................................................ N/A ................................................ N/A. 

Total Costs 3 ................................... ¥$15 million ................................. $3.5 million ................................... ¥$11 million. 

Net Benefits ................................... N/A ................................................ N/A ................................................ N/A. 

Non-monetized Benefits 4 .............. 11,000 tons of HAP ......................

190,000 tons of VOC ....................

670 tons of HAP ...........................

1,200 tons of VOC ........................

12,000 tons of HAP. 

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. 

1All estimates are for the implementation year (2015). 

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2While 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. 3The 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). 4For the NSPS, reduced exposure to HAP and climate effects are co-benefits. For the NESHAP, reduced VOC emissions, PM2.5 and ozone 

exposure, visibility and vegetation effects and climate effects are co-benefits. The specific control technologies for the final NSPS are anticipated 

to have minor secondary disbenefits, including an increase of 1.1 million tons of carbon dioxide (CO2), 550 tons of nitrogen oxides (NOX), 19 

tons of PM, 3,000 tons of carbon monoxide (CO) and 1,100 tons of total hydrocarbons (THC), as well as emission reductions associated with the 

energy system impacts. The specific control technologies for the NESHAP are anticipated to have minor secondary disbenefits, but the EPA was 

unable to estimate the secondary disbenefits. The net CO2-equivalent emission reductions are 18 million metric tons. 

B. Does this action apply to me? 

The regulated categories and entities 

potentially affected 

by the final standards are shown in 

Table 2 of this preamble. 

TABLE 2—INDUSTRIAL SOURCE CATEGORIES AFFECTED BY THIS ACTION

Category NAICS code 1 Examples of regulated entities 

Industry ....................................................................................... 211111 Crude Petroleum and Natural Gas Extraction. 

211112 Natural Gas Liquid Extraction. 

221210 Natural Gas Distribution. 

486110 Pipeline Distribution of Crude Oil. 

486210 Pipeline Transportation of Natural Gas. 

Federal government .................................................................... ........................ Not affected. 

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

1 North American Industry Classification System. 

This table is not intended to be 

exhaustive, but rather is meant to 

provide a guide for readers regarding 

entities likely to be affected by this 

action. If you have any questions 

regarding the applicability of this action 

to a particular entity, consult either the 

air permitting authority for the entity or 

your EPA regional representative as 

listed in 40 CFR 60.4 or 40 CFR 63.13 

(General Provisions). 

C. What are the emission sources 

affected by this action? 

1. What are the emission sources 

affected by the NSPS? 

The emission sources affected by the 

NSPS include well completions, 

pneumatic controllers, equipment leaks 

from natural gas processing plants, 

sweetening units at natural gas 

processing plants, reciprocating 

compressors, centrifugal compressors 

and storage vessels which are 

constructed, modified or reconstructed 

after August 23, 2011. Well completions 

subject to the NSPS are limited to the 

flowback period following hydraulic 

fracturing operations at a gas well 

affected facility. These completions 

include those conducted at newly 

drilled and fractured wells, as well as 

completions conducted following 

refracturing operations that may occur 

at various times over the life of the well. 

Pneumatic controllers affected by the 

NSPS include continuous bleed, natural 

gas-driven pneumatic controllers with a 

natural gas bleed rate greater than 6 scfh 

and which commenced construction 

after August 23, 2011, in the oil and 

natural gas production segment (except 

for gas processing plants) and 

continuous bleed natural gas-driven 

pneumatic controllers which 

commenced construction after August 

23, 2011, at natural gas processing 

plants. The NSPS applies to centrifugal 

compressors with wet seals and 

reciprocating compressors located in the 

natural gas production and processing 

segments. The NSPS also applies to 

equipment leaks from onshore natural 

gas processing plants and to storage 

vessels located in the oil and natural gas 

production segment, the natural gas 

processing segment and the natural gas 

transmission and storage segment. The 

NSPS also affects sweetening units 

located onshore that process natural gas 

from onshore or offshore wells. 

2. What are the emission sources 

affected by the NESHAP? 

The emission sources that are affected 

by the Oil and Natural Gas Production 

NESHAP (40 CFR part 63, subpart HH) 

or the Natural Gas Transmission and 

Storage NESHAP (40 CFR part 63, 

subpart HHH) include glycol 

dehydrators and equipment leaks. 

D. Where can I get a copy of this 

document? 

In addition to being available in the 

docket, an electronic copy of this action 

will also be available on the World 

Wide Web (WWW). Following signature 

by the Administrator, a copy of the 

action will be posted on the EPA’s Web 

site at the following address: http://

www.epa.gov/airquality/oilandgas. 

Additional information is available on 

the EPA’s RTR Web site at http://www.

epa.gov/ttn/vatw/rrisk/oarpg.html. This 

information includes the most recent 

version of the rule, source category 

descriptions, detailed emissions and 

other data were used as inputs to the 

risk assessments. 

E. Judicial Review 

Under CAA section 307(b)(1), judicial 

review of this final rule is available only 

by filing a petition for review in the 

United States Court of Appeals for the 

District of Columbia Circuit by October 

15, 2012. Under CAA section 

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

final rule that was raised with 

reasonable specificity during the period 

for public comment (including any 

public hearing) can be raised during 

judicial review. This section also 

provides a mechanism for the EPA to 

convene a proceeding for 

reconsideration ‘‘[i]f the person raising 

an objection can demonstrate to the 

Administrator that it was impracticable 

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49494 Federal Register / Vol. 77, No. 159 / Thursday, August 16, 2012 / Rules and Regulations 

to raise such objection within [the 

period for public comment] or if the 

grounds for such objection arose after 

the period for public comment (but 

within the time specified for judicial 

review) and if such objection is of 

central relevance to the outcome of the 

rule[.]’’ Any person seeking to make 

such a demonstration to us should 

submit a Petition for Reconsideration to 

the Office of the Administrator, 

Environmental Protection Agency, 

Room 3000, Ariel Rios Building, 1200 

Pennsylvania Ave. NW., Washington, 

DC 20004, with a copy to the person 

listed in the preceding FOR FURTHER

INFORMATION CONTACT section, and the 

Associate General Counsel for the Air 

and Radiation Law Office, Office of 

General Counsel (Mail Code 2344A), 

Environmental Protection Agency, 1200 

Pennsylvania Ave. NW., Washington, 

DC 20004. Note, under CAA section 

307(b)(2), the requirements established 

by this final rule may not be challenged 

separately in any civil or criminal 

proceedings brought by the EPA to 

enforce these requirements. 

III. Background Information on the 

NSPS and NESHAP 

A. What are the statutory authorities for 

the NSPS and NESHAP? 

1. What is the statutory authority for the 

NSPS? 

Section 111 of the CAA requires the 

EPA Administrator to list categories of 

stationary sources, if such sources cause 

or contribute significantly to air 

pollution, which may reasonably be 

anticipated to endanger public health or 

welfare. The EPA must then issue 

performance standards for such source 

categories. Whereas CAA section 112 

standards are issued for new and 

existing stationary sources, standards of 

performance are issued for new and 

modified stationary sources. These 

standards are referred to as NSPS. The 

EPA has the authority to define the 

source categories, determine the 

pollutants for which standards should 

be developed, identify the facilities 

within each source category to be 

covered and set the emission level of the 

standards. 

CAA section 111(b)(1)(B) requires the 

EPA to ‘‘at least every 8 years review 

and, if appropriate, revise’’ performance 

standards. However, the Administrator 

need not review any such standard if 

the ‘‘Administrator determines that such 

review is not appropriate in light of 

readily available information on the 

efficacy’’ of the standard. When 

conducting a review of an existing 

performance standard, the EPA has 

authority to revise that standard to add 

emission limits for pollutants or 

emission sources not currently regulated 

for that source category. 

In setting or revising a performance 

standard, CAA section 111(a)(1) 

provides that performance standards are 

to ‘‘reflect the degree of emission 

limitation achievable through the 

application of the BSER which (taking 

into account the cost of achieving such 

reduction and any nonair quality health 

and environmental impact and energy 

requirements) the Administrator 

determines has been adequately 

demonstrated.’’ In this notice, we refer 

to this level of control as the BSER. In 

determining BSER, we typically conduct 

a technology review that identifies what 

emission reduction systems exist and 

how much they reduce air pollution, in 

practice. Next, for each control system 

identified, we evaluate its costs, 

secondary air benefits (or disbenefits) 

resulting from energy requirements and 

nonair quality impacts such as solid 

waste generation. Based on our 

evaluation, we would determine BSER. 

The resultant standard is usually a 

numerical emissions limit, expressed as 

a performance level (i.e., a rate-based 

standard or percent control), that 

reflects the BSER. Although such 

standards are based on the BSER, the 

EPA may not prescribe a particular 

technology that must be used to comply 

with a performance standard, except in 

instances where the Administrator 

determines it is not feasible to prescribe 

or enforce a standard of performance. 

Typically, sources remain free to select 

any control measures that will meet the 

emission limits. Upon promulgation, an 

NSPS becomes a national standard to 

which all new sources must comply. 

2. What is the statutory authority for the 

NESHAP? 

Section 112 of the CAA establishes a 

two-stage regulatory process to address 

emissions of HAP from stationary 

sources. In the first stage, after the EPA 

has identified categories of sources 

emitting one or more of the HAP listed 

in section 112(b) of the CAA, section 

112(d) of the CAA calls for us to 

promulgate NESHAP for those sources. 

‘‘Major sources’’ are those that emit or 

have the potential to emit (PTE) 10 tpy 

or more of a single HAP or 25 tpy or 

more of any combination of HAP. For 

major sources, the technology-based 

emission standards must reflect the 

maximum degree of emission reductions 

of HAP achievable (after considering 

cost, energy requirements and nonair 

quality health and environmental 

impacts) and are commonly referred to 

as MACT standards. 

MACT standards are set to reflect 

application of measures, processes, 

methods, systems or techniques, 

including, but not limited to, measures 

which, (1) reduce the volume of or 

eliminate pollutants through process 

changes, substitution of materials or 

other modifications, (2) enclose systems 

or processes to eliminate emissions, (3) 

capture or treat pollutants when 

released from a process, stack, storage or 

fugitive emissions point, (4) are design, 

equipment, work practice or operational 

standards (including requirements for 

operator training or certification) or (5) 

are a combination of the above. CAA 

sections 112(d)(2)(A)–(E). A MACT 

standard may take the form of a design, 

equipment, work practice or operational 

standard where the EPA first determines 

either that, (1) a pollutant cannot be 

emitted through a conveyance designed 

and constructed to emit or capture the 

pollutant or that any requirement for or 

use of such a conveyance would be 

inconsistent with law or (2) the 

application of measurement 

methodology to a particular class of 

sources is not practicable due to 

technological and economic limitations. 

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

The MACT ‘‘floor’’ is the minimum 

control level allowed for MACT 

standards promulgated under CAA 

section 112(d)(3) and may not be based 

on cost considerations. For new sources, 

the MACT floor cannot be less stringent 

than the emission control that is 

achieved in practice by the bestcontrolled 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). 

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1 ‘‘Adverse environmental effect’’ is defined in 

CAA section 112(a)(7) as any significant and 

widespread adverse effect, which may be 

reasonably anticipated to wildlife, aquatic life or 

natural resources, including adverse impacts on 

populations of endangered or threatened species or 

significant degradation of environmental qualities 

over broad areas. 

The second stage in standard-setting 

focuses on reducing any remaining 

‘‘residual’’ risk according to CAA 

section 112(f). This provision requires, 

first, that the EPA prepare a Report to 

Congress discussing (among other 

things) methods of calculating risk 

posed (or potentially posed) by sources 

after implementation of the MACT 

standards, the public health significance 

of those risks and the EPA’s 

recommendations as to legislation 

regarding such remaining risk. The EPA 

prepared and submitted this report 

(Residual Risk Report to Congress, EPA– 

453/R–99–001) in March 1999. Congress 

did not act in response to the report, 

thereby triggering the EPA’s obligation 

under CAA section 112(f)(2) to analyze 

and address residual risk. 

CAA section 112(f)(2) requires us to 

determine for source categories subject 

to MACT standards, whether the 

emissions standards provide an ample 

margin of safety to protect public health. 

CAA section 112(f)(2) expressly 

preserves our use of a two-step process 

for developing standards to address any 

residual risk and our interpretation of 

‘‘ample margin of safety’’ developed in 

the National Emission Standards for 

Hazardous Air Pollutants: Benzene 

Emissions from Maleic Anhydride 

Plants, Ethylbenzene/Styrene Plants, 

Benzene Storage Vessels, Benzene 

Equipment Leaks, and Coke By-Product 

Recovery Plants (Benzene NESHAP) (54 

FR 38044, September 14, 1989). The 

first step in this process is the 

determination of acceptable risk. The 

second step provides for an ample 

margin of safety to protect public health, 

which is the level at which the 

standards must be set (unless a more 

stringent standard is required to prevent 

an adverse environmental effect, taking 

into consideration costs, energy, safety 

and other relevant factors). 

If the MACT standards for HAP that 

are ‘‘classified as a known, probable, or 

possible human carcinogen do not 

reduce lifetime excess cancer risks to 

the individual most exposed to 

emissions from a source in the category 

or subcategory to less than 1-in-1 

million,’’ the EPA must promulgate 

residual risk standards for the source 

category (or subcategory), as necessary, 

to provide an ample margin of safety to 

protect public health. In doing so, the 

EPA may adopt standards equal to 

existing MACT standards if the EPA 

determines that the existing standards 

are sufficiently protective. NRDC v. 

EPA, 529 F.3d 1077, 1083 (D.C. Cir. 

2008) (‘‘If EPA determines that the 

existing technology-based standards 

provide an ‘ample margin of safety,’ 

then the Agency is free to readopt those 

standards during the residual risk 

rulemaking.’’). As mentioned, the EPA 

must also adopt more stringent 

standards, if necessary, to prevent an 

adverse environmental effect,1 but must 

consider cost, energy, safety and other 

relevant factors in doing so. 

The terms ‘‘individual most exposed,’’ 

‘‘acceptable level,’’ and ‘‘ample margin 

of safety’’ are not specifically defined in 

the CAA. However, CAA section 

112(f)(2)(B) preserves the interpretation 

set out in the Benzene NESHAP, and the 

United States Court of Appeals for the 

District of Columbia Circuit has 

concluded that the EPA’s interpretation 

of CAA section 112(f)(2) is a reasonable 

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

(‘‘[S]ubsection 112(f)(2)(B) expressly 

incorporates the EPA’s interpretation of 

the Clean Air Act from the Benzene 

standard, complete with a citation to the 

Federal Register’’). See, also, A 

Legislative History of the Clean Air Act 

Amendments of 1990, volume 1, p. 877 

(Senate debate on Conference Report). 

We notified Congress in the Residual 

Risk Report to Congress that we 

intended to use the Benzene NESHAP 

approach in making CAA section 112(f) 

residual risk determinations (EPA–453/ 

R–99–001, p. ES–11). 

In the Benzene NESHAP, we stated as an 

overall objective: 

* * * in protecting public health with an 

ample margin of safety, we strive to provide 

maximum feasible protection against risks to 

health from hazardous air pollutants by, (1) 

protecting the greatest number of persons 

possible to an individual lifetime risk level 

no higher than approximately 1-in-1 million; 

and (2) limiting to no higher than 

approximately 1-in-10 thousand [i.e., 100-in1 million] the estimated risk that a person 

living near a facility would have if he or she 

were exposed to the maximum pollutant 

concentrations for 70 years. 

The agency also stated in the Residual 

Risk Report to Congress that ‘‘The EPA 

also considers incidence (the number of 

persons estimated to suffer cancer or 

other serious health effects as a result of 

exposure to a pollutant) to be an 

important measure of the health risk to 

the exposed population. Incidence 

measures the extent of health risk to the 

exposed population as a whole, by 

providing an estimate of the occurrence 

of cancer or other serious health effects 

in the exposed population.’’ The agency 

went on to conclude that ‘‘estimated 

incidence would be weighed along with 

other health risk information in judging 

acceptability.’’ As explained more fully 

in our Residual Risk Report to Congress, 

the EPA does not define ‘‘rigid line[s] of 

acceptability,’’ but considers rather 

broad objectives to be weighed with a 

series of other health measures and 

factors (EPA–453/R–99–001, p. ES–11). 

The determination of what represents an 

‘‘acceptable’’ risk is based on a 

judgment of ‘‘what risks are acceptable 

in the world in which we live’’ 

(Residual Risk Report to Congress, p. 

178, quoting the Vinyl Chloride 

decision at 824 F.2d 1165) recognizing 

that our world is not risk-free. 

In the Benzene NESHAP, we stated 

that ‘‘EPA will generally presume that if 

the risk to [the maximum exposed] 

individual is no higher than 

approximately 1-in-10 thousand, that 

risk level is considered acceptable.’’ 54 

FR 38045. We discussed the maximum 

individual lifetime cancer risk (or 

maximum individual risk (MIR)) as 

being ‘‘the estimated risk that a person 

living near a plant would have if he or 

she were exposed to the maximum 

pollutant concentrations for 70 years.’’ 

Id. We explained that this measure of 

risk ‘‘is an estimate of the upper bound 

of risk based on conservative 

assumptions, such as continuous 

exposure for 24 hours per day for 70 

years.’’ Id. We acknowledge that 

maximum individual lifetime cancer 

risk ‘‘does not necessarily reflect the 

true risk, but displays a conservative 

risk level which is an upper-bound that 

is unlikely to be exceeded.’’ Id. 

Understanding that there are both 

benefits and limitations to using 

maximum individual lifetime cancer 

risk as a metric for determining 

acceptability, we acknowledged in the 

1989 Benzene NESHAP that 

‘‘consideration of maximum individual 

risk * * * must take into account the 

strengths and weaknesses of this 

measure of risk.’’ Id. Consequently, the 

presumptive risk level of 100-in-1 

million (1-in-10 thousand) provides a 

benchmark for judging the acceptability 

of maximum individual lifetime cancer 

risk, but does not constitute a rigid line 

for making that determination. 

The agency also explained in the 1989 

Benzene NESHAP the following: ‘‘In 

establishing a presumption for MIR, 

rather than a rigid line for acceptability, 

the Agency intends to weigh it with a 

series of other health measures and 

factors. These include the overall 

incidence of cancer or other serious 

health effects within the exposed 

population, the numbers of persons 

exposed within each individual lifetime 

risk range and associated incidence 

within, typically, a 50-kilometer (km) 

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49496 Federal Register / Vol. 77, No. 159 / Thursday, August 16, 2012 / Rules and Regulations 

2On 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. 

exposure radius around facilities, the 

science policy assumptions and 

estimation uncertainties associated with 

the risk measures, weight of the 

scientific evidence for human health 

effects, other quantified or unquantified 

health effects, effects due to co-location 

of facilities and co-emission of 

pollutants.’’ Id. 

In some cases, these health measures 

and factors taken together may provide 

a more realistic description of the 

magnitude of risk in the exposed 

population than that provided by 

maximum individual lifetime cancer 

risk alone. As explained in the Benzene 

NESHAP, ‘‘[e]ven though the risks 

judged ‘acceptable’ by the EPA in the 

first step of the Vinyl Chloride inquiry 

are already low, the second step of the 

inquiry, determining an ‘ample margin 

of safety,’ again includes consideration 

of all of the health factors, and whether 

to reduce the risks even further.’’ In the 

ample margin of safety decision process, 

the agency again considers all of the 

health risks and other health 

information considered in the first step. 

Beyond that information, additional 

factors relating to the appropriate level 

are considered, including costs and 

economic impacts of controls, 

technological feasibility, uncertainties 

and any other relevant factors. 

Considering all of these factors, the 

agency will establish the standard at a 

level that provides an ample margin of 

safety to protect the public health, as 

required by CAA section 112(f). See 54 

FR 38046. 

B. What is the litigation history? 

On January 14, 2009, pursuant to 

section 304(a)(2) of the CAA, WildEarth 

Guardians and the San Juan Citizens 

Alliance filed a complaint in the United 

States District Court for the District of 

Columbia and alleged that the EPA 

failed to meet its obligations under CAA 

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

112(f)(2) to take actions relative to the 

review/revision of the NSPS and the 

NESHAP with respect to the Oil and 

Natural Gas Production source category. 

On February 5, 2010, the Court entered 

a consent decree that, as successively 

modified, required the EPA to sign by 

July 28, 2011,2 proposed standards and/ 

or determinations not to issue standards 

pursuant to CAA sections 111(b)(1)(B), 

112(d)(6) and 112(f)(2) and to take final 

action by April 3, 2012. On April 2, 

2012, the consent decree was modified 

to change the date for final action to no 

later than April 17, 2012. 

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 sectorbased approaches is by reviewing 

multiple regulatory programs together 

whenever possible, for example the 

NSPS and NESHAP, consistent with all 

applicable legal requirements. This 

approach essentially expands the 

technical analyses on costs and benefits 

of particular technologies, to consider 

the interactions of rules that regulate 

sources. The benefit of multi-pollutant 

and sector-based analyses and 

approaches includes the ability to 

identify optimum strategies, considering 

feasibility, cost impacts and benefits 

across the different pollutant types 

while streamlining administrative and 

compliance complexities and reducing 

conflicting and redundant requirements, 

resulting in added certainty and easier 

implementation of control strategies for 

the sector under consideration. In order 

to benefit from a sector-based approach 

for the oil and gas industry, the EPA 

analyzed how the NSPS and NESHAP 

under consideration relate to each other 

and other regulatory requirements 

currently under review for oil and gas 

facilities. In this analysis, we looked at 

how the different control requirements 

that result from these requirements 

interact, including the different 

regulatory deadlines and control 

equipment requirements that result, the 

different reporting and recordkeeping 

requirements and opportunities for 

states to account for reductions resulting 

from this rulemaking in their State 

Implementation Plans (SIP). The 

requirements analyzed affect criteria 

pollutants, HAP and methane emissions 

from oil and natural gas processes and 

cover the NSPS and NESHAP reviews. 

As a result of the sector-based 

approach, this rulemaking will reduce 

conflicting and redundant requirements. 

Also, the sector-based approach 

streamlines the monitoring, 

recordkeeping and reporting 

requirements, thus, reducing 

administrative and compliance 

complexities associated with complying 

with multiple regulations. In addition, 

the sector-based approach in this rule 

promotes a comprehensive control 

strategy that maximizes the co-control of 

multiple regulated pollutants while 

obtaining emission reductions as cobenefits. 

D. What are the health effects of 

pollutants emitted from the oil and 

natural gas sector? 

The final oil and natural gas sector 

NSPS and NESHAP amendments are 

expected to result in significant 

reductions in existing emissions and 

prevent new emissions from expansions 

of this industry. These emissions 

include HAP, VOC (a precursor to both 

PM2.5 and ozone formation) and 

methane (a GHG and a precursor to 

global ozone formation). These 

emissions are associated with 

substantial health effects, welfare effects 

and climate effects. One HAP of 

particular concern from the oil and 

natural gas sector is benzene, which is 

a known human carcinogen. PM2.5 is 

associated with health effects, including 

premature mortality for adults and 

infants, cardiovascular morbidity, such 

as heart attacks, hospital admissions 

and respiratory morbidity such as 

asthma attacks, acute and chronic 

bronchitis, hospital and emergency 

room visits, work loss days, restricted 

activity days and respiratory symptoms, 

as well as visibility impairment. Ozone 

is associated with health effects, 

including hospital and emergency 

department visits, school loss days and 

premature mortality, as well as injury to 

vegetation and climate effects. 

IV. Summary of the Final NSPS Rule 

A. What are the final actions relative to 

the NSPS for the Crude Oil and Natural 

Gas Production source category? 

We are revising the existing NSPS, 

which regulate VOC emissions from 

equipment leaks and SO2 emissions 

from sweetening units at onshore gas 

processing plants. In addition, we are 

promulgating standards for several new 

oil and natural gas affected facilities. 

The final standards apply to affected 

facilities that commence construction, 

reconstruction or modification after 

August 23, 2011, the date of the 

proposed rule. 

The listed Crude Oil and Natural Gas 

Production source category covers, at a 

minimum, those operations for which 

we are establishing standards in this 

final rule. Table 3 summarizes the 40 

CFR part 60, subpart OOOO standards. 

Further discussion of these changes may 

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Federal Register / Vol. 77, No. 159 / Thursday, August 16, 2012 / Rules and Regulations 49497 

be found below in this section and in 

sections V and IX of this preamble. 

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

Affected facility Pollutant Standard Compliance dates 

Hydraulically fractured wildcat and delineation 

wells.

VOC ............ Route flowback emissions to completion combustion device.October 15, 2012. 

Hydraulically fractured low pressure wells, nonwildcat and non-delineation wells.VOC ............ Route flowback emissions to completion combustion device.October 15, 2012. 

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 .......................... October 15, 2012. 

Reciprocating compressors .................................... VOC ............ Change rod packing after 26,000 hours or after 

36 months.

October 15, 2012. 

Continuous bleed natural gas-driven pneumatic 

controllers at natural gas processing plants.

VOC ............ Natural gas bleed rate of zero .............................. October 15, 2012. 

Continuous bleed natural gas-driven pneumatic 

controllers with a bleed rate greater than 6 scfh 

between wellhead and natural gas processing 

plant or oil pipeline.

VOC ............ Natural gas bleed rate less than 6 scfh ................ October 15, 2013. 

Storage vessels with VOC emissions equal to or 

greater than 6 tpy.

VOC ............ Reduce emissions by 95 percent .......................... October 15, 2013. 

Equipment leaks at onshore natural gas processing plants.VOC ............ LDAR program ...................................................... October 15, 2012. 

Sweetening units at onshore natural gas processing plants.SO2 .............. Reduce SO2 emissions based on sulfur feed rate 

and sulfur content of acid gas.

October 15, 2012. 

1. Standards for Gas Well Affected 

Facilities 

We are finalizing operational 

standards for completions of 

hydraulically fractured and refractured 

gas wells. For purposes of this rule, well 

completion is defined as the flowback 

period beginning after hydraulic 

fracturing and ending with either well 

shut in or when the well continuously 

flows to the flow line or to a storage 

vessel for collection, whichever occurs 

first. The final rule applies to three 

subcategories of fractured and 

refractured gas wells for which well 

completion operations are conducted: 

(1) Wildcat (exploratory) and 

delineation gas wells; (2) non-wildcat 

and non-delineation gas wells for which 

the reservoir pressure is insufficient for 

a REC, commonly referred to as a ‘‘green 

completion,’’ to be performed, as 

determined by a simple calculation 

involving reservoir pressure, well depth 

and flow line pressure at the sales meter 

(we refer to these wells as ‘‘low pressure 

gas wells’’) and (3) other fractured and 

refractured gas wells. For subcategory 

(3) wells, each well completion 

operation begun on or after January 1, 

2015, must employ REC in combination 

with use of a completion combustion 

device to control gas not suitable for 

entering the flow line (we refer to this 

as REC with combustion). For well 

completion operations at subcategory (1) 

wells (exploratory and delineation gas 

wells), subcategory (2) wells (low 

pressure gas wells) and for well 

completion operations begun prior to 

January 1, 2015, at subcategory (3) gas 

wells, the final rule requires the control 

of emissions using either REC with 

combustion or just a completion 

combustion device. Owners and 

operators are encouraged to use REC 

with combustion during this period. 

Well completions subject to the 

standards are gas well completions 

following hydraulic fracturing and 

refracturing operations. These 

completions include those conducted at 

newly drilled and fractured wells, as 

well as completions conducted 

following refracturing operations at 

various times over the life of the well. 

As we explained in the proposal 

preamble, a completion operation 

associated with refracturing performed 

at a well is considered a modification 

under CAA section 111(a), because 

physical change occurs to the well 

resulting in emissions increases during 

the refracturing and completion 

operation. In response to comment, we 

further clarify this point in the final 

rule, including providing a specific 

modification provision for well 

completions in lieu of the General 

Provisions in 40 CFR 60.14. For a more 

detailed explanation, please see section 

IX.A of this preamble. The modification 

determination and resulting 

applicability of NSPS to the completion 

operation following refracturing of gas 

wells is limited strictly to the gas well 

affected facility and does not by itself 

trigger applicability beyond the 

wellhead to other ancillary components 

that may be at the well site such as 

existing storage vessels, process vessels, 

separators, dehydrators or any other 

components or apparatus (that is, such 

equipment is not part of the affected 

facility). 

The final rule provides that 

uncontrolled well completions 

conducted on gas wells that are 

subsequently refractured on or after the 

effective date of this rule are 

modifications and are subject to the 

NSPS. However, gas wells that undergo 

completion following refracturing are 

not considered modified and, as a 

result, are not affected facilities under 

the NSPS if the completion operation is 

conducted with the use, immediately 

upon flowback, of emission control 

techniques otherwise required on or 

after January 1, 2015, for new wells and 

satisfies other requirements, including 

notification, recordkeeping and 

reporting requirements. 

In the final rule, we provide for a 

streamlined notification process for well 

completions at gas well affected 

facilities consisting of an email prenotification no later than 2 days in 

advance of impending completion 

operations. The email must include 

information that had been part of the 30- 

day advance notification, as described 

in the proposed rule, including contact 

information for the owner and operator, 

well identification, geographic 

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49498 Federal Register / Vol. 77, No. 159 / Thursday, August 16, 2012 / Rules and Regulations 

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 selfcertification required in the standard 

annual report. The operator retains a 

digital image of each REC in progress. 

The image must include a digital date 

stamp and geographic coordinates 

stamp to help link the photograph with 

the specific well completion operation. 

2. Standards for Compressor Affected 

Facilities 

The final rule requires measures to 

reduce VOC emissions from centrifugal 

and reciprocating compressors. 

Compressors located at the wellhead or 

in the transmission, storage and 

distribution segments are not covered by 

this final rule and, therefore, are not 

affected facilities. The final rule 

contains standards for wet seal 

centrifugal compressors located in the 

natural gas production segment and the 

natural gas processing segment up the 

point at which the gas enters the 

transmission and storage segment. The 

final standards require 95.0 percent 

reduction of the emissions from each 

wet seal centrifugal compressor affected 

facility. The standard can be achieved 

by capturing and routing the emissions 

to a control device that achieves an 

emission reduction of 95.0 percent. 

The operational standards for 

reciprocating compressors in the final 

rule require replacement of the rod 

packing based on usage. The owner or 

operator of a reciprocating compressor 

affected facility is required to change 

the rod packing immediately when 

hours of operation reach 26,000 hours 

(equivalent to 36 months of continuous 

usage). Alternatively, owners or 

operators can elect to change the rod 

packing every 36 months in lieu of 

monitoring compressor operating hours. 

An owner or operator who elects to 

meet the 26,000 hour requirement is 

required to monitor the duration (in 

hours) that the compressor is operated, 

beginning on the date of initial startup 

of the reciprocating compressor affected 

facility, or on the date of the previous 

rod packing replacement, whichever is 

later. 

3. Standards for Pneumatic Controller 

Affected Facilities 

We are also finalizing pneumatic 

controller VOC standards. The affected 

facility is a continuous bleed, natural 

gas-driven pneumatic controller with a 

natural gas bleed rate greater than 6 scfh 

for which construction commenced after 

August 23, 2011, located (1) in the oil 

production segment between the 

wellhead and the point of custody 

transfer to an oil pipeline; or (2) in the 

natural gas production segment, 

excluding natural gas processing plants, 

between the wellhead and the point at 

which the gas enters the transmission 

and storage segment. Except for 

controllers located at natural gas 

processing plants, each continuous 

bleed, natural gas-driven pneumatic 

controller that emits more than 6 scfh is 

an affected facility if it is constructed or 

modified after August 23, 2011. 

Pneumatic controllers with a bleed rate 

of 6 scfh or less in the oil and natural 

gas production segment and all 

pneumatic controllers located in the 

natural gas transmission, storage and 

distribution segments are not covered by 

this final rule and, therefore, are not 

affected facilities. At natural gas 

processing plants, the affected facility is 

each individual continuous bleed 

natural gas-operated pneumatic 

controller, and the final rule includes a 

natural gas bleed rate limit of zero scfh. 

The final emission standards for 

pneumatic controllers at natural gas 

processing plants reflect the emission 

level achievable from the use of nonnatural gas-driven pneumatic 

controllers. At other locations in the oil 

and natural gas production segment, the 

final rule includes a natural gas bleed 

rate limit of 6 standard cubic feet of gas 

per hour for an individual pneumatic 

controller. The standards provide 

exemptions in cases where it has been 

demonstrated that the use of a natural 

gas-driven pneumatic controller with a 

bleed rate above the applicable standard 

is required. However, as discussed in 

section IX.C, the EPA is allowing a 1- 

year phase-in period for pneumatic 

controllers in the final rule. 

4. Standards for Storage Vessels 

The final rule contains VOC standards 

for new, modified or reconstructed 

storage vessels located in the oil and 

natural gas production, natural gas 

processing and natural gas transmission 

and storage segments. The final rule, 

which applies to individual storage 

vessels, requires that storage vessels 

with VOC emissions equal to or greater 

than 6 tpy achieve at least 95.0 percent 

reduction in VOC emissions. For storage 

vessels constructed, modified or 

reconstructed at well sites with no wells 

already in production at the time of 

construction, modification or 

reconstruction, the final rule provides a 

30-day period from startup for the 

owner or operator to determine whether 

the magnitude of VOC emissions from 

the storage vessel will be at least 6 tpy. 

If the storage vessel requires control, the 

final rule provides an additional 30 days 

for the control device to be installed and 

operational. For storage vessels 

constructed, modified or reconstructed 

at well sites with one or more wells 

already in production at the time of 

construction, modification or 

reconstruction, these estimation and 

installation periods are not provided 

because an estimate of VOC emissions 

can be made using information on the 

liquid production characteristics of the 

existing wells. 

In addition, the final rule provides for 

a 1-year phase-in period for storage 

vessel controls. Refer to section IX.E.4 of 

this preamble for further discussion. 

5. Standards for Affected Facilities 

Located at Onshore Natural Gas 

Processing Plants 

For onshore natural gas processing 

plants, we are revising the existing 

NSPS requirements for LDAR to reflect 

the procedures and leak thresholds 

established by 40 CFR part 60, subpart 

VVa. Subpart VVa lowers the leak 

definition for valves from 10,000 ppm to 

500 ppm, and requires the monitoring of 

connectors. Pumps, pressure relief 

devices and open-ended valves or lines 

are also monitored. 

6. Standards for Sweetening Unit 

Affected Facilities at Onshore Natural 

Gas Processing Plants 

The final rule regulates SO2 emissions 

from natural gas processing plants by 

requiring affected facilities to reduce 

SO2 emissions by recovering sulfur. The 

final rule incorporates the provisions of 

40 CFR part 60, subpart LLL into 40 CFR 

part 60, subpart OOOO, and minor 

revisions were made to adapt the 

subpart LLL language to subpart OOOO. 

The final rule also increased the SO2

emission reduction standard from the 

subpart LLL requirement of 99.8 percent 

to 99.9 percent for units with sulfur 

production rate of at least 5 long tons 

per day. This change is based on 

reanalysis of the original data used in 

the subpart LLL BSER analysis. 

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B. What are the effective and 

compliance dates for the final NSPS? 

The revisions to the existing NSPS 

standards and the new NSPS standards 

promulgated in this action are effective 

on October 15, 2012. Affected facilities 

must be in compliance with the final 

standards on the effective date, October 

15, 2012. 

V. Summary of the Significant Changes 

to the NSPS Since Proposal 

The previous section summarized the 

requirements that the EPA is finalizing 

in this rule. This section will discuss in 

greater detail the key changes the EPA 

has made since proposal. These changes 

result from the EPA’s review of the 

additional data and information 

provided to us and our consideration of 

the many substantive and thoughtful 

comments submitted on the proposal. 

We believe the changes make the final 

rule more flexible and cost-effective, 

address concerns with equipment 

availability, streamline recordkeeping 

and reporting requirements and improve 

clarity, while fully preserving or 

improving the public health and 

environmental protection required by 

the CAA. 

A. Gas Well Affected Facilities 

We have revised the requirements for 

gas well affected facilities since 

proposal in response to comment. The 

final rule applies to three subcategories 

of fractured and refractured gas wells for 

which well completion operations are 

conducted: (1) Wildcat (exploratory) 

and delineation gas wells; (2) nonwildcat and non-delineation gas wells 

for which the reservoir pressure is 

insufficient for a REC to be performed, 

as determined by a simple calculation 

involving reservoir pressure, well depth 

and flow line pressure at the sales meter 

(we refer to these wells as ‘‘low pressure 

gas wells’’); and (3) other fractured and 

refractured gas wells. In the proposed 40 

CFR part 60, subpart OOOO, upon 

promulgation of this rule, each well 

completion or recompletion at a nonexploratory 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 nondelineation 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 nondelineation low pressure gas wells) 

begun on or after October 15, 2012 are 

required to control flowback emissions 

by using REC with combustion or by 

routing emissions to a completion 

combustion device alone unless it is 

technically infeasible or unsafe to do so. 

The final rule includes a specific 

modification provision for well 

completions in lieu of the General 

Provisions in 40 CFR 60.14. For a more 

detailed explanation, please see section 

IX.A of this preamble. In addition, we 

have revised the definition of ‘‘flowback 

period’’ to more clearly define when the 

flowback period begins and ends. 

In the proposed rule, all completions 

at existing wells (i.e., those originally 

constructed on or before August 23, 

2011) that are subsequently fractured or 

refractured were considered to be 

modifications. In the final rule, 

completions of wells that are refractured 

on or after the rule’s effective date are 

not considered modified and, as a 

result, are not affected facilities under 

the NSPS, if the completion operation is 

conducted with the use, immediately 

upon flowback, of emission control 

techniques required on or after January 

1, 2015, for new wells and satisfies 

other requirements, including 

notification, recordkeeping and 

reporting requirements. 

In the proposed rule, we prescribed 

specific equipment to accomplish an 

REC. In the final rule, we have removed 

the required equipment specifications 

for REC and added operational 

standards that will result in minimizing 

emissions and maximizing product 

recovery. In light of the comments 

received, we conclude that it is 

inappropriate and unnecessary to 

prohibit the use of other equipment that 

can be used to accomplish an REC and 

that the operational standards can be 

achieved using a variety of equipment 

that can change from well to well. 

Initial compliance requirements for 

gas well affected facilities have also 

been revised and streamlined. Owners 

and operators are now required to notify 

the Administrator of the actual date of 

each well completion operation by 

email no later than 2 days prior to the 

well completion operation, rather than 

the proposed requirement of notifying 

the Administrator of the date of the well 

completion operation within 30 days of 

the commencement of each well 

completion operation. The email must 

include information that had been part 

of the 30-day advance notification, as 

described in the proposed rule, 

including contact information for the 

owner and operator, well identification, 

geographic coordinates of the well and 

planned date of the beginning of 

flowback. However, if the owner or 

operator is subject to state regulations 

that require advance notification of well 

completions and has met those advance 

notification requirements, then the 

owner or operator is considered to have 

met the advance notification 

requirements for gas well completions 

under the NSPS. 

In the final rule, the recordkeeping 

and reporting requirements for well 

completions also provide for a 

streamlining option that owners and 

operators may choose in lieu of the 

standard annual reporting requirements. 

The standard annual report must 

include copies of all well completion 

records for each gas well affected 

facility for which a completion 

operation was performed during the 

reporting period. The alternative, 

streamlined annual report for gas well 

affected facilities requires submission of 

a list, with identifying information of all 

affected gas wells completed, electronic 

or hard copy photographs documenting 

REC in progress for each well for which 

REC was required and the selfcertification required in the standard 

annual report. The operator retains a 

digital image of each REC in progress. 

The image must include a digital date 

stamp and geographic coordinates 

stamp to help link the photograph with 

the specific well completion operation. 

Refer to section IX.B of this preamble 

and the Responses to Comments 

document, available in the docket, for 

detailed discussion regarding these 

changes. 

B. Centrifugal and Reciprocating 

Compressor Affected Facilities 

In the final rule, we have made 

changes that impact both reciprocating 

and centrifugal compressor affected 

facilities in response to comments 

requesting clarification. Because we are 

not finalizing standards covering them, 

centrifugal and reciprocating 

compressors located in the 

transmission, storage and distribution 

segments are not affected facilities. 

In the proposed rule, all centrifugal 

compressors would be required to use 

dry seals. We had also solicited 

comment on the use of wet seals with 

controls as an acceptable alternative to 

dry seals due to potential technical 

infeasibility of using dry seals for 

certain applications. Based on 

comments received, the final rule 

requires that centrifugal compressors 

with wet seals reduce emissions by 95.0 

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percent. The standard can be achieved 

by capturing and routing emissions from 

the wet seal fluid degassing system to a 

control device that reduces VOC 

emissions by 95.0 percent. Testing, 

monitoring, recordkeeping, reporting 

and notification requirements associated 

with the control devices have also been 

added. In contrast to the proposed rule, 

in the final rule, centrifugal compressors 

with dry seals are not affected facilities. 

More detailed discussion of this change 

is presented in section IX.D of this 

preamble. 

As proposed, owners or operators of 

reciprocating compressor affected 

facilities were required to change rod 

packing after 26,000 hours of operation. 

This is equivalent to approximately 36 

months of continuous operation. Based 

on comments we received, we are 

changing the final rule to provide 

operators the option of changing the rod 

packing every 36 months instead of 

tracking compressor hours of operation 

and changing rod packing after 26,000 

hours of operation. 

Refer to section IX.D of this preamble 

and the Responses to Comments 

document, available in the docket, for 

detailed discussion regarding these 

changes. 

C. Pneumatic Controller Affected 

Facilities 

For pneumatic controller affected 

facilities located in the oil and natural 

gas production segments, we have 

revised the definition of pneumatic 

controller affected facility from a single 

pneumatic controller to a single, 

continuous bleed, natural gas-driven 

pneumatic controller with a continuous 

bleed rate greater than 6 scfh for which 

construction, modification or 

reconstruction commenced after August 

23, 2011. At natural gas processing 

plants, individual continuous bleed 

natural gas-operated pneumatic 

controllers for which construction, 

modification or reconstruction 

commenced after August 23, 2011, are 

affected facilities under this rule. As 

explained further in section IX.C of this 

preamble, this change provides clarity 

by more specifically defining the 

pneumatic controllers we intended to 

regulate in this final rule. In addition, 

only pneumatic controllers located prior 

to the point at which the gas enters the 

transmission and storage segment are 

subject to the NSPS. Because we are not 

finalizing standards covering them, 

controllers located in the transmission 

and storage segment are not affected 

facilities. The emission rates we 

proposed for pneumatic controllers have 

not changed in the final rule. 

All new pneumatic controller affected 

facilities are required, in the final rule, 

to be tagged with the month and year of 

installation and identification that 

allows traceability to the records for that 

controller. 

In the proposed rule, each pneumatic 

controller affected facility would have 

to comply upon promulgation. The final 

rule allows a 1-year phase-in beginning 

October 15, 2012 before the bleed rate 

limit is effective for an affected facility. 

We believe this is necessary for at least 

two reasons. First, owners and operators 

would demonstrate compliance based 

on information in the manufacturers’ 

specification. We have concluded that 

such information is not always included 

in current manufacturers’ specifications 

and a period of time is required for 

manufacturers to test their products and 

modify specifications to include the 

information. Second, we are not aware 

of any add-on control device that is or 

can be used to reduce VOC emissions 

from gas-driven pneumatic devices. 

Finally, language in the proposed rule 

could have been interpreted to mean 

that all pneumatic controllers installed 

in any year after the proposal date must 

be reported each year, rather than those 

installed only during the reporting 

period. In order to clarify and 

streamline the recordkeeping and 

reporting requirements associated with 

pneumatic controllers, we are requiring 

only information concerning those 

affected facilities constructed, modified 

or reconstructed during the reporting 

period to be included in the annual 

report. 

Refer to section IX.C of this preamble 

and the Responses to Comments 

document, available in the docket, for 

detailed discussion regarding these 

changes. 

D. Storage Vessel Affected Facilities 

We have modified the definition of 

‘‘storage vessel’’ to exclude surge 

control vessels, knockout vessels and 

pressure vessels designed to operate 

without emissions to the atmosphere. In 

addition, we have clarified that we 

consider a storage vessel that is skidmounted or permanently attached to 

something that is mobile (such as 

trucks, railcars, barges or ships) to be 

subject to 40 CFR part 60, subpart 

OOOO if it is intended to be located at 

a site for at least 180 consecutive days. 

In the proposed rule, we established 

a throughput threshold for storage 

vessels below which they were not 

subject to the NSPS. In order to remove 

confusion with respect to the emission 

factors used to develop the throughput 

threshold and to address comments 

indicating significant difficulty 

measuring throughput, we have revised 

the final rule such that storage vessels 

that emit 6 tpy of VOC or more are 

subject to the NSPS, based on our 

analysis in the proposed rule showing 

that the proposed NSPS is cost-effective 

for storage vessels with that level of 

VOC emissions. In the final rule, for 

storage vessels constructed, modified or 

reconstructed at well sites with no wells 

already in production at the time of 

construction, the final rule provides a 

30-day period for the owner or operator 

to determine whether the magnitude of 

VOC emissions from the storage vessel 

will be at least 6 tpy. If the storage 

vessel requires control, the final rule 

provides an additional 30 days for the 

control device to be installed and 

operational. For storage vessels 

constructed, modified or reconstructed 

at well sites with one or more wells 

already in production at the time of 

construction, modification or 

reconstruction, VOC emissions can be 

determined prior to startup. 

Accordingly, these estimation and 

installation periods are not necessary 

and, therefore, not provided. 

Several requirements for storage 

vessels in the proposed rule pointed to 

40 CFR part 63, subpart HH (the Oil and 

Natural Gas Production NESHAP). 

However, subpart HH regulates HAP 

while this NSPS regulates VOC. 

Therefore, in order to eliminate 

confusion caused by cross-referencing 

another regulation and to tailor the 

requirements for VOC regulation, we 

have incorporated the storage vessel 

requirements from subpart HH into 40 

CFR part 60, subpart OOOO and 

modified those requirements, as 

appropriate for this rule. 

In the proposed rule, each storage 

vessel required to reduce emissions 

would have to comply upon 

promulgation. In the final rule, owners 

or operators are allowed a 1-year phasein beginning October 15, 2012 before the 

95.0-percent control requirement is 

effective. We believe this is necessary 

because of initial problems securing 

control devices that are manufacturertested 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. 

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E. Equipment Leaks Affected Facilities 

and Sweetening Unit Affected Facilities 

at Onshore Natural Gas Processing 

Plants 

We have revised the identification of 

affected facilities for equipment leaks at 

natural gas processing plants. We 

proposed that compressors and 

equipment (as defined in the rule) 

located at onshore natural gas 

processing plants were affected 

facilities. As discussed above, 

compressors (reciprocating and 

centrifugal) have requirements under 40 

CFR part 60, subpart OOOO that extend 

beyond the natural gas processing plant. 

To remove the duplicative requirements 

for compressors at natural gas 

processing plants, we have revised the 

identification of affected facility to 

exclude compressors from the standards 

that apply to equipment leaks at 

onshore natural gas processing plants. 

Refer to the Responses to Comments 

document, available in the docket, for 

detailed discussion regarding these 

affected facilities. 

F. Changes to Notification, 

Recordkeeping and Reporting 

Requirements 

In response to comment expressing 

concern with the burdens associated 

with demonstrating and monitoring 

compliance, we have reanalyzed the 

notification, recordkeeping and 

reporting requirements in the proposed 

rule and eliminated duplicative and 

unnecessary requirements for all 

emission points. For well completions, 

compressors, pneumatic controllers and 

storage vessels, we have removed the 

General Provisions notification 

requirements in 40 CFR 60.7(a)(1), (3) 

and (4). These requirements relate to 

notification of construction and initial 

performance testing and are more suited 

to construction of more traditional 

facilities (e.g., gas processing plants, 

refineries and chemical plants) than the 

numerous individual pieces of 

apparatus (e.g., individual pneumatic 

controllers, compressor and storage 

vessels) that are ‘‘affected facilities’’ 

under this final rule. Specific 

notification and initial compliance 

demonstration requirements in the final 

rule make the General Provisions 

notification requirements unnecessary 

for gas well affected facilities. 

As mentioned previously, we have 

also streamlined the notification, 

recordkeeping and reporting 

requirements for gas well affected 

facilities. In place of a written 

notification of each well completion 

operation 30 days prior to the 

completion, owners or operators must 

submit a notification no later than 2 

days prior to the date of the completion. 

This notification may be submitted by 

email. To avoid duplicative and 

potentially conflicting advance 

notification requirements, the final rule 

provides that owners or operators who 

are subject to state regulations that 

require advance notification of well 

completions and have met those 

notification requirements are considered 

to have met the advance notification 

requirements of the NSPS. Additionally, 

in lieu of the standard annual reporting 

requirements, the final rule allows 

submission of an annual report for gas 

well affected facilities that consists only 

of a list, with identifying information of 

all affected gas wells completed, 

electronic or hard copy photographs 

documenting REC in progress for each 

well for which REC was required and 

the self-certification required in the 

standard annual report. 

In the affirmative defense provisions 

of the rule, a citation was corrected, 

minor wording changes were made and 

reporting requirements were refined. 

The provisions we retained in the final 

rule are those we believe are necessary 

to assure regulatory agencies and the 

public that the owner or operator is in 

compliance with the final rule. Refer to 

section IX.F of this preamble and the 

Responses to Comments document, 

available in the docket, for detailed 

discussion regarding these changes. 

VI. Summary of the Final NESHAP 

Rules 

A. What are the final rule actions 

relative to the Oil and Natural Gas 

Production (subpart HH) source 

category? 

Table 4 summarizes the changes to 40 

CFR part 63, subpart HH. Further 

discussion of these changes may be 

found below in this section and in 

sections VII and X of this preamble. 

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

Affected source Nature of change Standard 

Small glycol dehydrators ...... Established MACT standards for previously unregulated 

source.

BTEX emission limit: 

New sources—4.66 × 10¥6 g/scm-ppmv. 

Existing sources—3.28 × 10¥4 g/scm-ppmv. 

‘‘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 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, 

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shutdown and malfunction. Lastly, the 

final rule revises and adds certain 

testing and monitoring and related 

notification, recordkeeping and 

reporting requirements and makes 

certain other minor technical revisions 

to the NESHAP. 

1. Standards for Small Glycol 

Dehydration Units 

In this final rule, we have established 

MACT standards under CAA sections 

112(d)(2) and (3) for small glycol 

dehydration units, which were left 

unregulated in the initial NESHAP. This 

subcategory consists of glycol 

dehydrators with an actual annual 

average natural gas flowrate less than 

85,000 standard cubic meters per day 

(scmd) or actual average benzene 

emissions less than 0.9 megagrams per 

year (Mg/yr). The final MACT standards 

for small dehydrators at oil and gas 

production facilities require that 

existing affected sources at a major 

source meet a unit-specific BTEX limit 

of 3.28 × 10¥4 grams BTEX/standard 

cubic meters (scm)-parts per million by 

volume (ppmv) and that new affected 

sources meet a BTEX limit of 4.66 × 

10¥6 grams BTEX/scm-ppmv. 

2. Standards for Equipment Leaks 

In the final rule, as a result of our 

technology review under CAA section 

112(d)(6), we are revising the leak 

definition for valves to 500 ppm, thus 

requiring the application of the LDAR 

requirement at this lower detection 

level. This leak definition applies only 

to valves at natural gas processing 

plants, and not other components. 

3. Notification, Recordkeeping and 

Reporting Requirements 

The final rule revises certain 

recordkeeping requirements of 40 CFR 

part 63, subpart HH. Specifically, 

facilities using carbon adsorbers as a 

control device are required to keep 

records of their carbon replacement 

schedule and records for each carbon 

replacement. In addition, owners and 

operators are required to keep records of 

the occurrence and duration of each 

malfunction of operation (i.e., process 

equipment) or the air pollution control 

equipment and monitoring equipment. 

In conjunction with the new MACT 

standards for small existing glycol 

dehydration units, owners and operators 

of such affected units are required to 

submit an initial notification within 1 

year after they become subject to the 

provisions of this subpart or by October 

15, 2013, whichever is later. 

The final amendments to the NESHAP 

also include additional requirements for 

the contents of the periodic reports. The 

periodic reports are required to include 

periodic test results and information 

regarding any carbon replacement 

events that occurred during the 

reporting period. Additionally, periodic 

reports are required to include the 

number, duration, and a brief 

description for each type of malfunction 

which occurred during the reporting 

period and which caused or may have 

caused any applicable emission 

limitation to be exceeded. The periodic 

report is also required to include a 

description of actions taken by an owner 

or operator during a malfunction of an 

affected source to minimize emissions, 

including actions taken to correct a 

malfunction. 

B. What are the final rule amendments 

for the Natural Gas Transmission and 

Storage (subpart HHH) source category? 

Table 5 summarizes the changes to 40 

CFR part 63, subpart HHH. Further 

discussion of these changes may be 

found below in this section and in 

sections VII and X of this preamble. 

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

Affected source Nature of change Standard 

Small glycol dehydrators ...... Established MACT standards for previously unregulated 

source.

BTEX emission limit: 

New sources—5.44 × 10¥5 g/scm-ppmv. 

Existing sources—3.01 × 10¥4 g/scm-ppmv. 

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 

dehydrators) provide an ample margin 

of safety to protect public health and 

prevent adverse environmental effects. 

Accordingly, we are re-adopting those 

standards to satisfy the requirements of 

CAA section 112(f). Thus, our reviews 

under CAA sections 112(d)(6) and 

112(f)(2) did not result in any revisions 

to the standards. 

1. Standards for Glycol Dehydration 

Units 

In this final rule, we have established 

MACT standards for small glycol 

dehydration units in the Natural Gas 

Transmission and Storage source 

category. This subcategory consists of 

glycol dehydrators with an actual 

annual average natural gas flowrate less 

than 283,000 scmd or actual average 

benzene emissions less than 0.9 Mg/yr. 

The final MACT standard for this 

subcategory of small dehydrators 

requires existing affected sources to 

meet a unit-specific BTEX emission 

limit of 3.01 × 10¥4 grams BTEX/scmppmv and new affected sources are 

required to meet a BTEX limit of 5.44 

× 10¥5 grams BTEX/scm-ppmv. 

2. Notification, Recordkeeping and 

Reporting Requirements 

The final rule revises certain 

recordkeeping requirements of 40 CFR 

part 63, subpart HHH. Specifically, 

facilities using carbon adsorbers as a 

control device are required to keep 

records of their carbon replacement 

schedule and records for each carbon 

replacement. In addition, owners and 

operators are required to keep records of 

the occurrence and duration of each 

malfunction of operation (i.e., process 

equipment) or the air pollution control 

equipment and monitoring equipment. 

In conjunction with the promulgation 

of the MACT standards for small glycol 

dehydration units, the final rule 

requires that owners and operators of 

such affected units submit an initial 

notification within 1 year after the unit 

becomes subject to the provisions of this 

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3At proposal, we used an incorrect factor (or 

multiplier) in calculating allowable emissions for 

Continued 

subpart or by October 15, 2013, 

whichever is later. 

The final amendments to the NESHAP 

also include additional requirements for 

the contents of the periodic reports. For 

40 CFR part 63, subpart HHH, the 

periodic reports are required to include 

periodic test results and information 

regarding any carbon replacement 

events that occurred during the 

reporting period. Additionally, periodic 

reports are required to include the 

number, duration, and a brief 

description for each type of malfunction 

which occurred during the reporting 

period and which caused or may have 

caused any applicable emission 

limitation to be exceeded. The periodic 

report is also required to include a 

description of actions taken by an owner 

or operator during a malfunction of an 

affected source to minimize emissions, 

including actions taken to correct a 

malfunction. 

C. What is the effective date of this final 

rule and compliance dates for the 

standards? 

The effective date of this rule is 

October 15, 2012. 

The compliance date for new affected 

sources (those that commenced 

construction or reconstruction on or 

after August 23, 2011) is immediately 

upon initial startup or the effective date 

of the standards, October 15, 2012, 

whichever is later. 

The compliance date for existing 

small glycol dehydration units that are 

subject to MACT for the first time (i.e., 

those that commenced construction 

before August 23, 2011) is October 15, 

2015. 

An affected source at a production 

field facility that constructed before 

August 23, 2011, that was previously 

determined to be an area source but 

becomes a major source on October 15, 

2012 due to the amendment to the 

associated equipment definition in 40 

CFR part 63, subpart HH, has until 

October 15, 2015 to comply with the 

relevant emission standards. 

The compliance date for valves at 

existing natural gas processing plants, 

constructed before August 23, 2011, due 

to the amendment to the leak definition 

in 40 CFR part 63, subpart HH, is 1 year 

after the effective date of the standards 

October 15, 2013. 

VII. Summary of the Significant 

Changes to the NESHAP Since Proposal 

The previous section described the 

requirements that the EPA is finalizing 

in this rule. This section discusses in 

greater detail the key changes the EPA 

is making from the proposal. These 

changes result from the EPA’s review of 

the additional data and information 

provided to us and our consideration of 

the substantive comments submitted on 

the proposal. 

We have retained the same approach 

and methodology to establishing the 

standards as described at proposal. We 

have, however, made some changes in 

response to comments, which are 

described further below. One change 

resulted in revisions to the MACT 

emission limits for small glycol 

dehydration units. In addition, based on 

the comments received, we are not 

finalizing the MACT standard for the 

subcategory of storage vessels without 

the PFE, which was a subcategory that 

was left unregulated in the 1999 40 CFR 

part 63, subpart HH rule. Specifically, 

based on our review of the comments, 

we believe that we need additional data 

and information to set an emission 

standard for storage vessels without the 

PFE, and we intend to collect the 

additional data and propose MACT 

emission standards under section 

112(d)(2) and (3) of the CAA for such 

storage vessels. Finally, we are retaining 

the 0.9 Mg/yr compliance option for 

large dehydration units. 

A. What are the significant changes 

since proposal for the Oil and Natural 

Gas Production (subpart HH) source 

category? 

1. Changes Made to Amendments 

Proposed Under the Authority of CAA 

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

Under the authority of sections 

112(d)(2) and (3) of the CAA, we 

proposed amendments to 40 CFR part 

63, subpart HH by adding requirements 

for previously unregulated units; 

specifically, we proposed standards for 

small glycol dehydration units and 

storage vessels without the PFE. 

In the final amendments for 40 CFR 

part 63, subpart HH, we have revised 

the proposed MACT standards for small 

glycol dehydration units in response to 

comments that we did not take into 

account variability in the development 

of the MACT floor. In our proposal, the 

MACT standards for existing affected 

sources was a unit-specific BTEX limit 

of 1.10 × 10¥4 g BTEX/scm-ppmv and 

for new affected sources was a BTEX 

limit of 4.66 × 10¥6 g BTEX/scm-ppmv. 

In this final rule, we accounted for 

variability by using an upper prediction 

limit to develop a revised BTEX 

emission limit for existing small glycol 

dehydration units of 3.28 × 10¥4 grams 

BTEX/standard cubic meters (scm)-parts 

per million by volume (ppmv) and for 

new small glycol dehydration units the 

revised BTEX limit is 4.66 × 10¥6 grams 

BTEX/scm-ppmv. The process for 

developing these emissions limitations 

is documented in the Response to 

Comments document and a technical 

memorandum, both of which are in the 

docket. 

Finally, as noted above, in response to 

comments, we are not finalizing MACT 

standards for storage vessels without the 

PFE in this rule. We received numerous 

comments expressing concerns with 

how we established the proposed 

standards for this subcategory. In 

response to such comments, we have reevaluated the proposed MACT 

standards and concluded that we need 

(and intend to gather) additional data on 

these sources in order to analyze and 

establish MACT emission standards for 

this subcategory of storage vessels under 

section 112(d)(2) and (3) of the CAA. 

See the Response to Comments 

document for additional discussion. 

2. Changes Made to Amendments 

Proposed Under the Authority of CAA 

Section 112(f)(2) 

We proposed to eliminate the 0.9 

Mg/yr benzene compliance option for 

large glycol dehydration units because, 

in the proposed rule, we estimated that 

the emissions allowed as the result of 

this compliance option resulted in 

estimated cancer risks up to 400-in-1- 

million. We received multiple 

comments concerning our proposed risk 

estimate. After reviewing these 

comments, we discovered that we had 

significantly overestimated the 

allowable emissions associated with this 

compliance option. First, for several 

sources, including the source that we 

predicted had the 400-in-1 million MIR, 

we used an incorrect factor (or 

multiplier) to scale up actual emissions 

associated with sources that could 

utilize the compliance option level of 

0.9 Mg/yr to allowables. We used an 

incorrect factor due to an inadvertent 

transcription error in our calculations. 

Second, we learned that the risk 

assessment supporting the proposed 

rule erroneously included several area 

sources, which are not subject to 40 CFR 

part 63, subpart HH and thus should not 

have been included in the CAA section 

112(f) risk assessment. After revising the 

risk assessment to remove area sources, 

and considering the MACT standard 

promulgated today for small glycol 

dehydrators pursuant to CAA sections 

112(d)(2) and (3), the MIR for the Oil 

and Natural Gas Production source 

category based on actual and allowable 

emissions is 10-in-1 million, compared 

to the 400-in-1 million3 based on 

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49504 Federal Register / Vol. 77, No. 159 / Thursday, August 16, 2012 / Rules and Regulations 

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. 

4We 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. 

5See 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. 

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 noncancer TOSHI value (0.1) is unchanged, 

driven by naphthalene emissions from 

fugitive sources. The maximum acute 

non-cancer hazard quotient value (9, 

based on the California EPA reference 

exposure level (REL) for benzene) is also 

unchanged from the proposed rule. 

Although driven by the same pollutant 

that drives the MIR, benzene, the 

maximum acute hazard quotient value 

did not change from the proposed rule 

because the source driving the acute 

value was not identified as an area 

source and, thus, remained in the 

revised analysis. It is common for the 

maximum acute hazard quotient and 

cancer MIR not to coincide because the 

acute value is strongly dependent on 

short-term meteorology and the distance 

to the facility property boundary, 

whereas the MIR is dependent on longterm meteorology and the distance to 

census block receptors. There are 13 

cases in the source category (out of 

approximately 1,000 facilities) where 

the REL is exceeded by more than a 

factor of 2. 

Based on the conservative nature of 

the acute exposure scenario used in the 

screening assessment for this source 

category, the EPA has judged that, 

considering all associated uncertainties, 

the potential for effects from acute 

exposures is low. Screening estimates of 

acute exposures were evaluated for each 

HAP at the point of highest off-site 

exposure for each facility (i.e., not just 

the census block centroids) assuming 

that a person is present at this location 

at a time when both the peak emission 

rate and worst-case dispersion 

conditions occur. Although the REL 

(which indicates the level below which 

adverse effects are not anticipated) is 

exceeded in this case, we believe the 

potential for acute effects is low for 

several reasons. The acute modeling 

scenario is worst-case because of the 

confluence of peak emission rates and 

worst-case dispersion conditions. Also, 

the generally sparse populations near 

the facilities with the highest estimated 

1-hour exposures make it less likely that 

a person would be near the plant to be 

exposed. 

We also conducted a facility-wide risk 

assessment. The maximum facility-wide 

risk estimate of 100-in-1 million is 

unchanged from the proposed rule. Also 

unchanged from proposal is the fact that 

the facility-wide risk is driven by 

emissions from reciprocating internal 

combustion engines (RICE) and these 

engines are not part of the Oil and 

Natural Gas Production source category. 

In fact, oil and natural gas production 

operations contribute only about one 

percent or less to the total facility-wide 

risks. In the last few years, the Agency 

has revised the MACT standards for 

certain RICE. See 75 FR 9648 and 51570. 

Although it is difficult to discern from 

the available data which types of RICE 

are driving the facility-wide risk, it is 

important to note that the 2005 National 

Emissions Inventory (NEI) data on 

which we modeled risk did not take into 

account the recent MACT revisions to 

the RICE rule. Finally, our assessment 

that the potential for significant human 

health risks due to multipathway 

exposures or adverse environmental 

effects is low has not changed since 

proposal (see 76 FR 52774). 

Consistent with the approach 

established in the Benzene NESHAP, 

the EPA weighed all health risk 

measures and information, including 

the maximum individual cancer risk, 

the cancer incidence, the number of 

people exposed to a risk greater than 1- 

in-1-million, the distribution of risks in 

the exposed population, and the 

uncertainty of our risk calculations in 

determining whether the risk posed by 

emissions from Oil and Natural Gas 

Production is acceptable. In this case, 

because the MIR is well below 100-in1-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

In making our proposed ample margin 

of safety determination under CAA 

section 112(f)(2), we subsequently 

evaluated the risk reductions and costs 

associated with various emissions 

control options to determine whether 

we should impose additional standards 

to reduce risks further. As stated above, 

we made certain revisions to the risk 

assessment in response to comments 

and the resulting MIR for 40 CFR part 

63, subpart HH is 10-in-1 million. We 

have not identified any emission control 

options that would reduce emissions 

and risk associated with subpart HH 

sources for glycol dehydration units and 

storage vessels. Our proposed 

amendment to remove the 0.9 Mg/yr 

compliance option does not affect the 

risk driver, which is fugitive emissions. 

As a result, we are retaining the 0.9 

Mg/yr compliance option in the final 

rule. We have determined that the risks 

associated with the level of emissions 

allowed by the MACT standards are 

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

Since a LDAR program is the typical 

method for reducing emissions from 

fugitive sources, we considered 

requiring a LDAR program to reduce 

risk for this source category. The NEI 

dataset for this source category contains 

approximately 2,500 emission points 

that we characterized as fugitive. These 

emission points are located at 639 

facilities. The fugitive emissions 

associated with those 639 facilities are 

747 tons of HAP. 

In evaluating the effectiveness of a 

LDAR program at these facilities we 

looked at two different LDAR 

programs—one is a program equivalent 

to 40 CFR part 60, subpart VV, and the 

second is a more stringent program 

equivalent to 40 CFR part 60, subpart 

VVa.5 A LDAR program equivalent to 

subpart VV can achieve emission 

reductions of approximately 39 percent 

with capital and annual costs of 

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Federal Register / Vol. 77, No. 159 / Thursday, August 16, 2012 / Rules and Regulations 49505 

6Memorandum 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. 

$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 control requirements would 

reduce the MIR for the source category 

from 10-in-1 million to approximately 7- 

in-1 million. 

As explained in the proposal, in 

accordance with the approach 

established in the Benzene NESHAP, we 

weigh all health risk measures and 

information considered in the risk 

acceptability determination, along with 

the costs and economic impacts of 

emissions controls, technological 

feasibility, uncertainties and other 

relevant factors, in making our ample 

margin of safety determination and 

deciding whether standards are 

necessary to reduce risks further. 

Considering all of this information, we 

conclude that the costs of the options 

analyzed are not reasonable considering 

the emissions reductions and risk 

reductions potentially achievable with 

the control measures evaluated. Thus, 

we conclude that the MACT standards 

in 40 CFR part 63, subpart HH (coupled 

with the new MACT standard for small 

glycol dehydrators) provide an ample 

margin of safety to protect public health 

and prevent adverse environmental 

effects. Accordingly, we are re-adopting 

those standards to satisfy the 

requirements of CAA section 112(f). 

3. Changes Made to Standards Proposed 

Under the Authority of CAA Section 

112(d)(6) 

As discussed in detail in the preamble 

for the proposed rule (76 FR 52784), we 

conducted a technology review for 

glycol dehydration units, storage vessels 

and equipment leaks under the 

authority of CAA section 112(d)(6). We 

assessed developments in practices, 

processes and control technologies 

sources for those regulated under the 

initial NESHAP and determined that it 

was cost-effective to lower the leak 

definition for valves at natural gas 

processing plants. We did not identify 

developments in practices, processes 

and control technologies for glycol 

dehydration units and storage vessels. 

As a result of this assessment, we 

proposed revisions to the equipment 

leak requirements in 40 CFR part 63, 

subpart HH to lower the leak definition 

for valves to an instrument reading of at 

least 500 ppm. No significant changes 

since proposal were made to the 

equipment leak standards proposed 

under the authority of section 112(d)(6) 

of the CAA.6

4. Other Changes to the Proposed Rule 

We are revising the emission 

reduction demonstrated using the 

manufacturers performance test from 

98.0 percent to 95.0 percent. 

Specifically, if an owner or operator 

chooses to install a combustion control 

device that is tested under, and passes, 

the prescribed manufacturers 

performance test the final rule states 

that the control device has 

demonstrated a destruction efficiency of 

95.0 percent. This change is a result of 

comments and data provided on the 

actual performance of these devices in 

the field. 

In the proposed rule, we proposed 

that the standards apply at all times and 

removed provisions that provided an 

exemption from the emission standards 

during SSM. In response to comments 

that the monitoring and reporting 

provisions related to excursions 

occurring during SSM events that 

remain in the subpart suggest exemption 

and therefore should be removed, we 

are removing these provisions in the 

final rule. 

Refer to the Reponses to Comments 

document, available in the docket, for 

detailed discussion regarding these 

changes. 

B. What are the significant changes 

since proposal for the Natural Gas 

Transmission and Storage (subpart 

HHH) source category? 

1. Changes Made to Amendments 

Proposed Under the Authority of CAA 

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

Under the authority of sections 

112(d)(2) and (3) of the CAA, we 

proposed amendments to 40 CFR part 

63, subpart HHH by adding 

requirements for previously unregulated 

units; specifically, we proposed 

standards for small glycol dehydration 

units. 

In the final amendments for 40 CFR 

part 63, subpart HHH, we have revised 

the proposed BTEX limits for small 

glycol dehydration units in response to 

comments that we did not take into 

account variability in the development 

of the MACT floor. We had proposed a 

unit-specific BTEX emission limit of 

6.42 × 10¥5 grams BTEX/scm-ppmv for 

existing sources and a BTEX limit of 

1.10 × 10¥5 g BTEX/scm-ppmv for new 

sources. In the final rule, we accounted 

for variability by using an upper 

prediction limit to develop a revised 

emission limit for existing affected 

sources of 3.10 × 10¥4 g BTEX/scmppmv and for new affected sources is a 

BTEX limit of 5.44 × 10¥5 grams BTEX/ 

scm-ppmv. The process for developing 

these emissions limitations is 

documented in the response to 

comments document and a technical 

memorandum both of which can be 

found in the docket. 

2. Changes to Amendments Proposed 

Under the Authority of CAA Section 

112(f)(2) 

We proposed to eliminate the 0.9 Mg/ 

yr benzene compliance option for large 

glycol dehydration unit process vents 

because, in the proposed rule, we 

estimated that the emissions allowed as 

the result of this compliance option 

resulted in estimated cancer risks up to 

90-in-1-million. In response to 

comments, we learned that the risk 

assessment supporting the proposed 

rule erroneously included some sources 

that have permanently shut down, and 

several area sources, which are not 

subject to 40 CFR part 63, subpart HHH 

and, thus, should not have been 

included in the CAA section 112(f) risk 

assessment. After revising the risk 

assessment to remove these sources and 

considering the MACT standards 

promulgated here pursuant to CAA 

section 112(d)(2) and (3), the MIR for 

the Natural Gas Transmission and 

Storage source category based on actual 

and allowable emissions is 20-in-1 

million, compared to the 90-in-1 million 

based on allowable emissions and 20-in1 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 

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49506 Federal Register / Vol. 77, No. 159 / Thursday, August 16, 2012 / Rules and Regulations 

7We 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. 

8See 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. 

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 noncancer TOSHI value (0.2) is unchanged, 

driven by benzene emissions from 

fugitive sources. The maximum acute 

non-cancer hazard quotient value (4, 

based on the benzene REL) changed 

from the proposed rule; the value in the 

proposed rule was 5, but was associated 

with an area source that was removed 

from the risk assessment. There are two 

cases in the source category (out of 

approximately 300 facilities) where the 

REL is exceeded by more than a factor 

of 2. 

Based on the conservative nature of 

the acute exposure scenario used in the 

screening assessment for this source 

category, the EPA has judged that, 

considering all associated uncertainties, 

the potential for effects from acute 

exposures is low. Screening estimates of 

acute exposures were evaluated for each 

HAP at the point of highest off-site 

exposure for each facility (i.e., not just 

the census block centroids) assuming 

that a person is present at this location 

at a time when both the peak emission 

rate and worst-case dispersion 

conditions occur. Although the REL 

(which indicates the level below which 

adverse effects are not anticipated) is 

exceeded in this case, we believe the 

potential for acute effects is low for 

several reasons. The acute modeling 

scenario is worst-case because of the 

confluence of peak emission rates and 

worst-case dispersion conditions. Also, 

the generally sparse populations near 

the facilities with the highest estimated 

1-hour exposures make it less likely that 

a person would be near the plant to be 

exposed. 

We also conducted a facility-wide risk 

assessment. The maximum facility-wide 

risk estimate of 200-in-1 million is 

unchanged from the proposed rule. Also 

unchanged from proposal is the fact that 

the facility-wide risk is driven by 

emissions from reciprocating internal 

combustion engines (RICE) and these 

engines are not part of the Natural Gas 

Transmission and Storage source 

category. In fact, natural gas 

transmission and storage operations 

contribute only about one percent or 

less to the total facility-wide risks. In 

the last few years, the Agency has 

revised the MACT standards for certain 

RICE. See 75 FR 9648 and 51570. 

Although it is difficult to discern from 

the available data which types of RICE 

are driving the facility-wide risk, it is 

important to note that the 2005 NEI data 

on which we modeled risk did not take 

into account the recent MACT revisions 

to the RICE rule. Finally, our assessment 

that the potential for significant human 

health risks due to multipathway 

exposures or adverse environmental 

effects is low has not changed since 

proposal (see 76 FR 52774). 

Consistent with the approach 

established in the Benzene NESHAP, 

the EPA weighed all health risk 

measures and information, including 

the maximum individual cancer risk, 

the cancer incidence, the number of 

people exposed to a risk greater than 1- 

in-1-million, the distribution of risks in 

the exposed population and the 

uncertainty of our risk calculations in 

determining whether the risk posed by 

emissions from natural gas transmission 

and storage is acceptable. In this case, 

because the MIR is well below 100-in1-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 million. We 

have not identified any emission control 

options that would reduce emissions 

and risk associated with subpart HHH 

sources for glycol dehydration units. 

Our proposed amendment to remove the 

0.9 Mg/yr compliance option does not 

affect the risk driver, which is fugitive 

emissions. As a result, we are retaining 

the 0.9 Mg/yr compliance option in the 

final rule. 

We have determined that the risks 

associated with the level of emissions 

allowed by the MACT standards are 

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

Since a LDAR program is the typical 

method for reducing emissions from 

fugitive sources, we evaluated the costs 

and emissions reductions associated 

with requiring such a program to reduce 

risk for this source category. The NEI 

dataset for the natural gas transmission 

and storage source category contains 

approximately 314 emission points that 

we characterized as being fugitive in 

nature. These emission points are 

located at 212 facilities. The fugitive 

emissions associated with those 212 

facilities are 187 tons of HAP. 

In evaluating the effectiveness of a 

LDAR program at these facilities we 

looked at two different LDAR 

programs—one is a program equivalent 

to 40 CFR part 60, subpart VV, and the 

second is a more stringent program 

equivalent to 40 CFR part 60, subpart 

VVa.8 A LDAR program equivalent to 

subpart VV can achieve emission 

reductions of approximately 51 percent 

with capital and annual costs of 

$361,800 and $142,600 per facility, 

respectively. Therefore, such a program 

for 212 facilities would be expected to 

reduce emissions by 95.4 tons of HAP 

and have total capital and annual costs 

of $76.7 million and $30.2 million, 

respectively. The cost effectiveness 

would be approximately $317,000 per 

ton of HAP. 

A LDAR program equivalent to 40 

CFR part 60, subpart VVa can achieve 

emission reductions of approximately 

78 percent overall with capital and 

annual costs of $369,500 and $154,300 

per facility, respectively. Therefore, a 

LDAR program for 212 facilities would 

be expected to reduce emissions by 146 

tons of HAP with total capital and 

annual costs of $78.3 million and $32.7 

million, respectively. The cost 

effectiveness would be approximately 

$224,000 per ton of HAP. These 

additional control requirements would 

reduce the MIR from the source category 

to approximately 3-in-1 million for the 

subpart VVa level of control and 7-in-1- 

million for the 40 CFR part 60, subpart 

VV level of control. 

As explained in the proposal, in 

accordance with the approach 

established in the Benzene NESHAP, we 

weigh all health risk measures and 

information considered in the risk 

acceptability determination, along with 

the costs and economic impacts of 

emissions controls, technological 

feasibility, uncertainties and other 

relevant factors, in making our ample 

margin of safety determination and 

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Federal Register / Vol. 77, No. 159 / Thursday, August 16, 2012 / Rules and Regulations 49507 

9See footnote 6. 

deciding whether standards are 

necessary to reduce risks further. 

Considering all of this information, we 

conclude that the costs of the options 

analyzed are not reasonable considering 

the emissions reductions and risk 

reductions potentially achievable with 

the control measures. Thus, we 

conclude that the MACT standards in 40 

CFR part 63, subpart HHH (coupled 

with the new MACT standard for small 

glycol dehydrators) provide an ample 

margin of safety to protect public health 

and prevent adverse environmental 

effects. Accordingly, we are re-adopting 

those standards to satisfy the 

requirements of CAA section 112(f)(2). 

3. Changes Made to Amendments 

Proposed Under the Authority of CAA 

Section 112(d)(6) 

As discussed in detail in the preamble 

for the proposed rule (76 FR 52784), we 

conducted a technology review for 

glycol dehydration units under the 

authority of CAA section 112(d)(6). We 

did not identify developments in 

practices, processes and control 

technologies for large glycol 

dehydration units. As a result of this 

assessment, we did not propose 

amendments to 40 CFR part 63, subpart 

HHH. We have not made any changes 

since proposal under the authority of 

CAA section 112(d)(6).9 Further 

discussion on our technology review 

analysis can be found in section X.C of 

this preamble, and in the Response to 

Comments document. 

4. Other Changes to the Proposed Rule 

We are revising the emission 

reduction efficiency demonstration 

using the manufacturer’s performance 

test from 98.0 percent to 95.0 percent. 

Specifically, if an owner or operator 

chooses to install a combustion control 

device that is tested under, and passes, 

the prescribed manufacturer’s 

performance test, the final rule states 

that the control device has 

demonstrated a reduction efficiency of 

95.0 percent. This change is a result of 

comments and data provided on the 

actual performance of these devices in 

the field. 

In the proposed rule, we proposed 

that the standards apply at all times and 

removed provisions that provided an 

exemption from the emission standards 

during SSM. In response to comments 

that the monitoring and reporting 

provisions related to excursions 

occurring during SSM events that 

remain in the subpart suggest exemption 

and therefore should be removed, we 

are removing these provisions in the 

final rule. 

VIII. Compliance Related Issues 

Common to the NSPS and NESHAP 

A. How do the rules address startup, 

shutdown and malfunction? 

The United States Court of Appeals 

for the District of Columbia Circuit 

vacated portions of two provisions in 

the EPA’s CAA section 112 regulations 

governing the emissions of HAP during 

periods of SSM. Sierra Club v. EPA, 551 

F.3d 1019 (D.C. Cir. 2008), cert. denied, 

130 S. Ct. 1735 (U.S. 2010). Specifically, 

the Court vacated the SSM exemption 

contained in 40 CFR 63.6(f)(1) and 40 

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

regulation, commonly referred to as the 

‘‘General Provisions Rule,’’ that the EPA 

promulgated under section 112 of the 

CAA. When incorporated into CAA 

section 112(d) regulations for specific 

source categories, these two provisions 

exempt sources from the requirement to 

comply with the otherwise applicable 

CAA section 112(d) emission standard 

during periods of SSM. 

As proposed in the NESHAP, we have 

eliminated the SSM exemption in this 

rule. Consistent with Sierra Club v. 

EPA, the EPA has established standards 

in both rules that apply at all times. We 

have also revised Table 3 (the NESHAP 

General Provisions table) in several 

respects. For example, we have 

eliminated the incorporation of the 

NESHAP General Provisions’ 

requirement that the source develop an 

SSM plan. We have also eliminated or 

revised certain NESHAP recordkeeping 

and reporting that related to the SSM 

exemption. The EPA has attempted to 

ensure that we have not included in the 

regulatory language, for the NSPS and 

NESHAP, any provisions that are 

inappropriate, unnecessary or 

redundant in the absence of the SSM 

exemption. 

In establishing the standards in both 

rules, the EPA has taken into account 

startup and shutdown periods and, for 

the reasons explained in section IX of 

this preamble for the NSPS and in 

section X of this preamble for the 

NESHAP, did not establish different 

standards for those periods. Based on 

the information available in the record 

about actual operations during startups 

and shutdowns, we believe that 

operations and emissions do not differ 

from normal operations during these 

periods such that it warrants a separate 

standard. Therefore, we have not 

proposed different standards for these 

periods. 

Periods of startup, normal operations 

and shutdown are all predictable and 

routine aspects of a source’s operations. 

However, by contrast, malfunction is 

defined as a ‘‘sudden, infrequent, and 

not reasonably preventable failure of air 

pollution control and monitoring 

equipment, process equipment, or a 

process to operate in a normal or usual 

manner * * * ’’ (40 CFR 63.2) and as 

‘‘any sudden, infrequent, and not 

reasonably preventable failure of air 

pollution control equipment, process 

equipment, or a process to operate in a 

normal or usual manner * * *’’ (40 CFR 

60.2). The EPA has determined that 

CAA sections 111 and 112 do not 

require that emissions that occur during 

periods of malfunction be factored into 

development of CAA section 111 or 112 

standards. 

CAA section 111 standards—See 

section III of this preamble for a detailed 

discussion on how the EPA sets or 

revises CAA section 111 NSPS to reflect 

the degree of emission limitation 

achievable through the application of 

the BSER. 

CAA section 112 standards—Under 

CAA section 112, emissions standards 

for new sources must be no less 

stringent than the level ‘‘achieved’’ by 

the best controlled similar source and 

for existing sources, generally must be 

no less stringent than the average 

emission limitation ‘‘achieved’’ by the 

best performing 12 percent of sources in 

the category. Nothing in CAA section 

112 directs the agency to consider 

malfunctions in determining the level 

‘‘achieved’’ by the best performing or 

best controlled sources when setting 

emission standards. Moreover, while the 

EPA accounts for variability in setting 

emissions standards consistent with the 

CAA section 112 case law, nothing in 

that case law requires the agency to 

consider malfunctions as part of that 

analysis. CAA section 112 uses the 

concept of ‘‘best controlled’’ and ‘‘best 

performing’’ unit in defining the level of 

stringency that CAA section 112 

performance standards must meet. 

Applying the concept of ‘‘best 

controlled’’ or ‘‘best performing’’ to a 

unit that is malfunctioning presents 

significant difficulties, as malfunctions 

are sudden and unexpected events. 

Further, accounting for malfunctions 

in setting NESHAP or NSPS standards 

would be difficult, if not impossible, 

given the myriad different types of 

malfunctions that can occur across all 

sources in the category and given the 

difficulties associated with predicting or 

accounting for the frequency, degree 

and duration of various malfunctions 

that might occur. As such, the 

performance of units that are 

malfunctioning is not ‘‘reasonably’’ 

foreseeable. See, e.g., Sierra Club v. 

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EPA, 167 F.3d 658, 662 (D.C. Cir. 1999) 

(‘‘[T]he EPA typically has wide latitude 

in determining the extent of datagathering necessary to solve a problem. 

We generally defer to an agency’s 

decision to proceed on the basis of 

imperfect scientific information, rather 

than to ‘invest the resources to conduct 

the perfect study.’ ’’); see, also, 

Weyerhaeuser Co. v. Costle, 590 F.2d 

1011, 1058 (D.C. Cir. 1978) (‘‘In the 

nature of things, no general limit, 

individual permit, or even any upset 

provision can anticipate all upset 

situations. After a certain point, the 

transgression of regulatory limits caused 

by ‘uncontrollable acts of third parties,’ 

such as strikes, sabotage, operator 

intoxication or insanity, and a variety of 

other eventualities, must be a matter for 

the administrative exercise of case-bycase 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 nonmalfunctioning source. Similarly, in the 

NSPS context, accounting for 

malfunctions when setting standards of 

performance under CAA section 111, 

which reflect the degree of emission 

limitation achievable through ‘‘the 

application of the best system of 

emission reduction’’ that the EPA 

determines is adequately demonstrated 

could lead to standards that are 

significantly less stringent than levels 

that are achieved by a well-performing 

non-malfunctioning source. The EPA’s 

approach to malfunctions is consistent 

with CAA section 112 and CAA section 

111 and is a reasonable interpretation of 

the statute. 

Finally, the EPA recognizes that even 

equipment that is properly designed and 

maintained can sometimes fail and that 

such failure can sometimes cause a 

violation of the relevant emission 

standard. See, e.g., State 

Implementation Plans: Policy Regarding 

Excessive Emissions During 

Malfunctions, Startup, and Shutdown 

(September 20, 1999); Policy on Excess 

Emissions During Startup, Shutdown, 

Maintenance, and Malfunctions 

(February 15, 1983). The EPA is, 

therefore, adding to the final NSPS and 

NESHAP an affirmative defense to civil 

penalties for violations of emission 

standards that are caused by 

malfunctions. See 40 CFR 63.761 for 

sources subject to the Oil and Natural 

Gas Production MACT standards; 40 

CFR 63.1271 for sources subject to the 

Natural Gas Transmission and Storage 

MACT standards (defining ‘‘affirmative 

defense’’ to mean, in the context of an 

enforcement proceeding, a response or 

defense put forward by a defendant, 

regarding which the defendant has the 

burden of proof, and the merits of which 

are independently and objectively 

evaluated in a judicial or administrative 

proceeding). We also have added other 

regulatory provisions to specify the 

elements that are necessary to establish 

this affirmative defense; a source subject 

to the Oil and Natural Gas Production 

or Natural Gas Transmission and 

Storage MACT standards must prove by 

a preponderance of the evidence that it 

has met all of the elements set forth in 

40 CFR 63.762 and a source subject to 

the Natural Gas Transmission and 

Storage NSPS must prove by a 

preponderance of the evidence that it 

has met all of the elements set forth in 

40 CFR 60.41Da (NSPS). See 40 CFR 

22.24. The criteria ensure that the 

affirmative defense is available only 

where the event that causes a violation 

of the emission standard meets the 

narrow definition of malfunction in 40 

CFR 60.2 (NSPS) and 40 CFR 63.2 

(NESHAP), respectively, (sudden, 

infrequent, not reasonably preventable 

and not caused by poor maintenance 

and/or careless operation). For example, 

the final NSPS and NESHAP provide 

that to successfully assert the 

affirmative defense, the source must 

prove by a preponderance of the 

evidence that the violation ‘‘[w]as 

caused by a sudden, infrequent, and 

unavoidable failure of air pollution 

control and process equipment, or a 

process to operate in a normal or usual 

manner. * * *’’ The criteria also are 

designed to ensure that steps are taken 

to correct the malfunction, to minimize 

emissions in accordance with 40 CFR 

63.762 for sources subject to the Oil and 

Natural Gas Production MACT 

standards, 40 CFR 63.1272 for sources 

subject to the Natural Gas Transmission 

and Storage MACT standards, and 40 

CFR 60.5415(h) for the Standards of 

Performance for Crude Oil and Natural 

Gas Production, Transmission and 

Distribution, and to prevent future 

malfunctions. For example, the final 

NSPS and NESHAP provide that the 

source must prove by a preponderance 

of the evidence that ‘‘[r]epairs were 

made as expeditiously as possible when 

a violation occurred * * *’’ and that 

‘‘[a]ll possible steps were taken to 

minimize the impact of the violation on 

ambient air quality, the environment 

and human health. * * *’’ In any 

judicial or administrative proceeding, 

the Administrator may challenge the 

assertion of the affirmative defense and, 

if the respondent has not met its burden 

of proving all of the requirements in the 

affirmative defense, appropriate 

penalties may be assessed in accordance 

with section 113 of the CAA (see also 40 

CFR part 22.27). 

The EPA proposed and is now 

finalizing an affirmative defense in the 

final NSPS and NESHAP in an attempt 

to balance a tension, inherent in many 

types of air regulations, to ensure 

adequate compliance, while 

simultaneously recognizing that, despite 

the most diligent of efforts, emission 

standards may be violated under 

circumstances beyond the control of the 

source. The EPA must establish 

emission standards that ‘‘limit the 

quantity, rate, or concentration of 

emissions of air pollutants on a 

continuous basis.’’ 42 U.S.C. 7602(k) 

(defining ‘‘emission limitation and 

emission standard’’). See, generally, 

Sierra Club v. EPA, 551 F.3d 1019, 1021 

(D.C. Cir. 2008). Thus, the EPA is 

required to ensure that CAA section 112 

emissions standards are continuous. 

The affirmative defense for malfunction 

events meets this requirement by 

ensuring that, even where there is a 

malfunction, the emission standard is 

still enforceable through injunctive 

relief. While ‘‘continuous’’ standards, 

on the one hand, are required, there is 

also case law indicating that, in many 

situations, it is appropriate for the EPA 

to account for the practical realities of 

technology. For example, in Essex 

Chemical v. Ruckelshaus, 486 F.2d 427, 

433 (D.C. Cir. 1973), the District of 

Columbia Circuit acknowledged that, in 

setting standards under CAA section 

111, ‘‘variant provisions’’ such as 

provisions allowing for upsets during 

startup, shutdown and equipment 

malfunction ‘‘appear necessary to 

preserve the reasonableness of the 

standards as a whole and that the record 

does not support the ‘never to be 

exceeded’ standard currently in force.’’ 

See, also, Portland Cement Ass’n v. 

Ruckelshaus, 486 F.2d 375 (D.C. Cir. 

1973). Though intervening case law 

such as Sierra Club v. EPA and the CAA 

1977 amendments call into question the 

relevance of these cases today, they 

support the EPA’s view that a system 

that incorporates some level of 

flexibility is reasonable. The affirmative 

defense simply provides for a defense to 

civil penalties for violations that are 

proven to be beyond the control of the 

source. By incorporating an affirmative 

defense, the EPA has formalized its 

approach to upset events. In a Clean 

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Federal Register / Vol. 77, No. 159 / Thursday, August 16, 2012 / Rules and Regulations 49509 

Water Act setting, the Ninth Circuit 

required this type of formalized 

approach when regulating ‘‘upsets 

beyond the control of the permit 

holder.’’ Marathon Oil Co. v. EPA, 564 

F.2d 1253, 1272–73 (9th Cir. 1977); see, 

also, Mont. Sulphur & Chem. Co. v. 

EPA, 2012 U.S. App. LEXIS 1056 (Jan 

19, 2012) (rejecting industry argument 

that reliance on the affirmative defense 

was not adequate). But see 

Weyerhaeuser Co. v. Costle, 590 F.2d at 

1057–58 (holding that an informal 

approach is adequate). The affirmative 

defense provisions give the EPA the 

flexibility to both ensure that its 

emission standards are ‘‘continuous,’’ as 

required by 42 U.S.C. 7602(k), and 

account for unplanned upsets and, thus, 

support the reasonableness of the 

standard as a whole. 

Refer to preamble section IX for the 

NSPS, preamble section X for the 

NESHAP and the Response to 

Comments document for both the NSPS 

and the NESHAP, available in the 

docket, for detailed discussions 

regarding these changes. 

B. How do the NSPS and NESHAP 

provide for compliance assurance? 

The final rule includes various 

notification, recordkeeping and 

reporting requirements that we believe 

provide a robust compliance assurance 

program, while reducing burden and 

streamlining requirements. The EPA 

also considered a variety of innovative 

compliance approaches that could 

maximize compliance and transparency, 

while minimizing burden on the 

regulated community and regulators. 

More detailed information on public 

comments received and the EPA’s 

responses are included in sections IX 

and X of the preamble or in the response 

to comments document. 

1. Notification, Recordkeeping and 

Reporting Requirements 

For well completions, owners or 

operators are required to submit an 

email notification no later than 2 days 

prior to each anticipated well 

completion. The notification must 

identify the owner or operator and 

provide the American Petroleum 

Institute (API) well number, 

geographical coordinates of the affected 

wells and the estimated date of 

commencement of the flowback period 

immediately following hydrofracturing. 

The owner or operator must keep 

records identifying each well 

completion operation and documenting 

the portions of the flowback period 

when the gas was recovered, combusted 

or vented. 

Annually, owners or operators of all 

affected facilities under the NSPS, 

including gas wells, compressors, 

pneumatic controllers, storage vessels 

and gas processing plants, must report 

any deviation from the NSPS 

requirements during the reporting 

period. Each annual report must include 

a signed certification by a senior 

company official that attests to the truth, 

accuracy and completeness of the 

report. For affected gas wells, the report 

must also identify each well completion 

conducted during the reporting period 

and submit detailed completion records 

for each well as part of the annual 

report. 

In the final rule, the recordkeeping 

and reporting requirements for well 

completions also provide a streamlining 

option that owners and operators may 

choose in lieu of the standard annual 

reporting requirements. The alternative, 

streamlined annual report for gas well 

affected facilities requires submission of 

a list, with identifying information of all 

affected gas wells completed, electronic 

or hard copy photographs documenting 

REC in progress for each well for which 

REC was required and the selfcertification required in the standard 

annual report. The operator retains a 

digital image of each REC in progress. 

The image must include a digital date 

stamp and geographic coordinates 

stamp to help link the photograph with 

the specific well completion operation. 

The owner or operator is not required to 

submit detailed completion records as 

part of the annual report. 

For centrifugal compressors with wet 

seal systems, the annual report must 

include identification of each affected 

facility constructed, modified or 

reconstructed during the reporting 

period. The annual report for 

reciprocating compressors must identify 

each reciprocating compressor 

constructed, modified or reconstructed 

during the reporting period. The report 

also must include, for each affected 

compressor, the elapsed time of 

operation since the most recent rod 

packing change as of the end of the 

reporting period. For affected pneumatic 

controllers and storage vessels, the 

annual report must identify each 

affected facility constructed, modified 

or reconstructed during the reporting 

period. 

Owners or operators who conduct 

certain performance tests on control 

devices must report results of those tests 

using the Electronic Reporting Tool 

(ERT). Further discussion of reporting of 

emissions tests is presented in section 

VIII.D of this preamble. 

NESHAP 

The final amendments to 40 CFR part 

63, subparts HH and 40 CFR part 63, 

subpart HHH revise certain 

recordkeeping requirements. 

Specifically, facilities using carbon 

adsorbers as a control device are now 

required to keep records of their carbon 

replacement schedule and records of 

each carbon replacement. We are 

requiring that owners and operators that 

use a manufacturer’s tested control 

device keep records of visible emissions 

readings and flowrate calculations and 

records of periods when the pilot flame 

is absent. The final amendments require 

records of the date of each semi-annual 

maintenance inspection be maintained. 

Finally, owners and operators are 

required to keep records of the 

occurrence and duration of each 

malfunction or operation of the air 

pollution control equipment and 

monitoring equipment. 

In conjunction with the final MACT 

standards for small glycol dehydration 

units, owners and operators of such 

units are required to submit an initial 

notification within 1 year after 

becoming subject to 40 CFR part 63, 

subpart HH or by October 15, 2013, 

whichever is later. 

Similarly, in conjunction with the 

final MACT standards for small glycol 

dehydration units in the final 40 CFR 

part 63, subpart HHH amendments, 

owners and operators of small glycol 

dehydration units are required to submit 

an initial notification within 1 year after 

becoming subject to subpart HHH or by 

October 15, 2013, whichever is later. 

The final amendments to 40 CFR part 

63, subpart HH and 40 CFR part 63, 

subpart HHH include new requirements 

for the contents of Notification of 

Compliance Status Reports. The owners 

and operators are required to include an 

electronic copy of the performance test 

results for the manufacturer’s tested 

control device, if applicable; the 

predetermined carbon replacement 

schedule for carbon adsorbers, if 

applicable; and data related to the 

manufacturer’s performance tests 

conducted for certain models of control 

devices, if compliance is being achieved 

using the manufacturer’s performance 

tests. 

The final amendments to the NESHAP 

also include additional requirements for 

the contents of periodic reports. Each 

semiannual report must include a 

signed certification by a senior company 

official that attests to the truth, accuracy 

and completeness of the report. For both 

40 CFR part 63, subpart HH and 40 CFR 

part 63, subpart HHH, in the final 

amendments, periodic reports are 

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49510 Federal Register / Vol. 77, No. 159 / Thursday, August 16, 2012 / Rules and Regulations 

required to include periodic test results 

and information regarding any carbon 

replacement events that occurred during 

the reporting period. Owners and 

operators are also required to include in 

the periodic reports information 

regarding any excursions that occur 

when the inlet gas flow rate deviates 

from that identified in the 

manufacturer’s performance test, and 

any excursions caused when visible 

emissions exceed the maximum 

allowable duration. 

Owners or operators who conduct 

certain performance tests on control 

devices must report results of those tests 

using the ERT. Further discussion of 

reporting of emissions tests is presented 

in section VIII.C below. 

2. Innovative Compliance Approaches 

At proposal, given the number and 

diversity of sources potentially affected 

by the NSPS and/or the NESHAP, we 

solicited comments on optional 

compliance tools that could reduce 

compliance burden and enhance 

transparency. Specifically, we asked for 

suggestions on: (1) Registration of wells 

and advance notification of planned 

completions; (2) use of third party 

verification; and (3) electronic reporting 

using existing mechanisms. We received 

comments on each of the topics above 

and have presented summaries of those 

comments and the EPA’s responses in 

the Response to Comments document. 

The commenters were generally 

opposed to third party verification. 

However, one suggestion was a 

voluntary random verification program, 

similar to one used in the past for 

gasoline marketing, where operators 

who participated in this program 

potentially could receive lower priority 

for enforcement inspections by 

regulators. Other suggested innovative 

approaches include use of social media, 

including Facebook and Twitter, plus 

new technologies such as quick 

response codes, to provide timely public 

notification and access to compliance 

records for individual wells and other 

affected facilities. Other suggestions 

included use of a centralized database 

for industry and public access to 

compliance information. Further 

discussion of these approaches is 

provided in the response to comments. 

While we considered these suggestions, 

we did not adopt them in the final rule, 

for reasons explained further in the 

Responses to Comments document. 

C. What are the requirements for 

submission of performance test data to 

the EPA? 

The EPA must have performance test 

data to conduct effective reviews of 

CAA sections 111, 112 and 129 

standards, as well as for many other 

purposes, including compliance 

determinations, emission factor 

development and annual emission rate 

determinations. 

As stated in the proposal preamble, 

the EPA is taking a step to increase the 

ease and efficiency of data submittal 

and data accessibility. Specifically, the 

EPA is requiring owners and operators 

of oil and natural gas sector facilities to 

submit electronic copies of required 

performance test reports. 

As mentioned in the proposal 

preamble, data entry will be conducted 

through an electronic emissions test 

report structure called the ERT. The 

ERT will generate an electronic report 

which will be submitted to the EPA’s 

Central Data Exchange (CDX) through 

the Compliance and Emissions Data 

Reporting Interface (CEDRI). A 

description of the ERT can be found at 

http://www.epa.gov/ttn/chief/ert/ 

index.html and CEDRI can be accessed 

through the CDX Web site 

(www.epa.gov/cdx). 

The requirement to submit 

performance test data electronically to 

the EPA does not create any additional 

performance testing and would apply 

only to those performance tests 

conducted using test methods that are 

supported by the ERT. A list of the 

pollutants and test methods supported 

by the ERT is available at http:// 

www.epa.gov/ttn/chief/ert/index.html. 

The major advantages of electronic 

reporting are more fully explained in 

the proposal preamble. 

An important benefit of using the ERT 

is that the performance test data will 

become available to the public through 

WebFIRE. Having such data publicly 

available enhances transparency and 

accountability. 

In summary, in addition to supporting 

regulation development, control strategy 

development and other air pollution 

control activities, having an electronic 

database populated with performance 

test data will save industry; state, local 

and tribal agencies; and the EPA 

significant time, money and effort while 

improving the quality of emission 

inventories and, as a result, air quality 

regulations. 

IX. Summary of Significant NSPS 

Comments and Responses 

For purposes of this document, the 

text within the comment summaries was 

provided by the commenter(s) and 

represents their opinion(s), regardless of 

whether the summary specifically 

indicates that the statement is from a 

commenter(s) (e.g., ‘‘The commenter 

states’’ or ‘‘The commenters assert’’). 

The comment summaries do not 

represent the EPA’s opinion unless the 

response to the comment specifically 

agrees with all or a portion of the 

comment. 

A. Major Comments Concerning 

Applicability 

1. Activities That Constitute a 

Modification 

Comment: Referring to the definition 

of ‘‘modification’’ in section 111(a)(4) of 

the CAA, one commenter asserts that a 

modification occurs only if two things 

happen: (1) There must be a ‘‘physical 

change or change in the method of 

operation,’’ and (2) the change must 

result in an emissions increase. 

The commenter states that, in the 

context of the New Source Review 

program, the District of Columbia 

Circuit Court has opined that 

‘‘Congress’s use of the word ‘any’ in 

defining a ‘modification’ means that all 

types of ‘physical changes’ are covered’’ 

(New York v. EPA, 443 F.3d 880, 890 

(D.C. Cir. 2006)) and that the District of 

Columbia Circuit Court has determined 

that ‘‘the plain language of the CAA 

indicates that Congress intended to 

apply NSR to changes that increase 

actual emissions instead of potential or 

allowable emissions.’’ New York v. EPA, 

413 F.3d 3, 40 (DC Cir. 2005). 

However, according to the 

commenter, the Supreme Court has 

concluded that the CAA section 111 

definition of modification does not have 

to have the same meaning under the 

NSPS and New Source Review (NSR) 

programs (Environmental Defense v. 

Duke Energy Corp., 127 S. Ct. 1423, 

1434 (2007)), and, thus, the EPA has 

latitude within the context of CAA 

section 111 to implement different rules 

regarding modifications. 

The commenter believes, in 

particular, that the EPA’s regulatory 

definition of ‘‘modification’’ under the 

NSPS program provides several 

categories of activities that alone, are 

not to be considered modifications, 

including ‘‘maintenance, repair, and 

replacement which the Administrator 

determines to be routine for a source 

category,’’ and ‘‘an increase in 

production rate that can be 

accomplished without a capital 

expenditure.’’ 40 CFR 60.14(e). The 

commenter believes these provisions 

reflect the fact that Congress established 

the NSPS program for ‘‘new’’ sources. 

According to the commenter, without 

these exclusions, even the most minor 

activities would convert an existing 

source into a ‘‘new source.’’ The 

commenter states that the premise 

behind characterizing these activities as 

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10At proposal, EPA used the term 

‘‘recompletion’’ to describe completions of 

previously fractured new gas wells that are 

refractured at some future date, and we specified 

that such actions are considered modifications. In 

addition, we used the term ‘‘recompletion’’ to 

describe completions of existing wells (i.e., those 

wells that were constructed before August 23, 2011) 

that subsequently are fractured for the first time or 

that are refractured. 

11We 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. 

12While 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). 

13We 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. 

not being ‘‘changes’’ is that they all 

contemplate that the plant will continue 

to be operated in a manner consistent 

with its original design and, thus, is not 

a ‘‘new’’ facility. 

We also received a number of 

comments objecting to consideration of 

recompletion activities 10 as 

modifications, claiming that it is a 

significant departure from the definition 

of ‘‘modification’’ under the General 

Provision at 40 CFR 60.14. Some 

commenters argue that well completion 

expenditures do not meet the regulatory 

definition of ‘‘capital expenditure’’ 

while others argue that they are 

maintenance activities excluded in 40 

CFR 60.14 others note that we have not 

traditionally regulated temporary 

‘‘construction’’ activities.11

Response: In this final rule, the EPA 

addresses modifications in the context 

of well completions and has deleted the 

proposed definition of ‘‘modification,’’ 

though the underlying rationale 

presented in the proposal remains, and 

we are providing alternative regulatory 

text. Pursuant to this final rule and as 

discussed below, well completions 

conducted on gas wells that are 

refractured on or after the effective date 

of this rule are considered modifications 

and subject to the NSPS, with the 

exception of such well completions that, 

immediately upon flowback, use 

emission control techniques otherwise 

required for new wells and satisfy other 

requirements for gas well facilities, 

including notification, recordkeeping 

and reporting requirements. 

As discussed in the proposal, the EPA 

has chosen to depart from the definition 

of modification in 40 CFR 60.14 with 

respect to regulation of wells that 

primarily produce natural gas. As 

explained in the proposal and elsewhere 

in the preamble for this rule, the VOC 

emissions from the flowback following 

refracturing of gas wells are significant, 

the EPA has identified cost-effective 

controls to reduce VOC emissions 

during this operating phase, and these 

controls are required for only a 

relatively short time during the well’s 

operating life. The EPA therefore 

concludes that it is appropriate for 

treatment of these activities to depart 

from the definition of modification in 40 

CFR 60.14 to ensure that emissions from 

these activities are controlled. 

We do not in this package question 

the broad appropriateness of the NSPS 

General Provisions at 40 CFR 60.14. 

However, as the General Provisions on 

modification in 40 CFR 60.14 

themselves recognize, they may not be 

appropriate in all cases. Given the 

significant, although short-term, 

increase in emissions from flowback 

caused by refracturing activities when 

such activities are not controlled, and 

the cost-effective nature of the control 

on such emissions, we have concluded 

that covering these refracturing 

activities is appropriate even if it 

requires departing from the General 

Provisions’ definition of modification. 

Specifically, we are providing in the 

final rule at 40 CFR 60.5365: 

(h) The following provisions apply to gas 

well facilities that are hydraulically 

refractured. 

(1) A gas well facility that conducts a well 

completion operation following hydraulic 

refracturing is not an affected facility, 

provided that the requirements of § 60.5375 

are met. For purposes of this provision, the 

dates specified in § 60.5375(a) do not apply, 

and such facilities, as of the effective date of 

this rule, must meet the requirements of 

§ 60.5375(a)(1)–(4). 

(2) A well completion operation following 

hydraulic refracturing at a gas well facility 

not conducted pursuant to § 60.5375 is a 

modification to the gas well affected facility. 

(3) Refracturing of a gas well facility does 

not affect the modification status of other 

equipment, process units, storage vessels, 

compressors, or pneumatic controllers 

located at the well site. 

(4) Sources initially constructed after 

August 23, 2011, are considered affected 

sources regardless of this provision. 

As a result of this provision, a 

modification of a well, defined as ‘‘an 

onshore well drilled principally for 

production of natural gas,’’ occurs when 

a well is refractured on or after the 

effective date of this rule, except when 

the owner or operator of a well controls 

emissions during the 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 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 reperforation because it is an expected 

part of well operation. However, both 

the CAA and our regulation define 

modification to mean ‘‘physical change’’ 

without providing any qualification to 

that term, thus indicating that the term 

‘‘physical change’’ is very broad to 

include any physical change. The 

commenter’s interpretation of the term 

‘‘physical change’’ is without support. 

Emissions Increase 

As a result of these physical changes, 

a multi-day period of flowback of 

natural gas, hydrocarbon condensate, 

water and sand is necessary to clean up 

the formation and wellbore prior to 

production of gas for sale. This flowback 

period is characterized by release of 

substantial amounts of VOC-containing 

natural gas and hydrocarbon condensate 

that would not have occurred absent the 

refracturing operation, thus meeting the 

second part of the statutory test—an 

increase in the amount of emissions. 

As discussed in the proposal, EPA’s 

data indicate that uncontrolled well 

completions with hydraulic refracturing 

consistently result in VOC emissions 

that were not present prior to such 

activities. Data in comments received 

also confirm that these uncontrolled 

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49512 Federal Register / Vol. 77, No. 159 / Thursday, August 16, 2012 / Rules and Regulations 

14One commenter relies on a passage from a 

proposed, but never finalized, rule preamble to 

argue that under the NSPS emission increase test 

prechange emissions are based on the highest level 

achievable in the 5 years immediately preceding a 

physical change. The passage, however, is not 

addressing the NSPS test generally applicable to 

modifications, but, rather, is addressing a specific 

regulatory provision applicable to modifications at 

electric utility steam generating units (EUSGU). See 

70 FR 61081, 61089 (October 20, 2005). 

Specifically, the preamble discussion is describing 

40 CFR 60.14(h), which states that a change at an 

EUSGU will not be a modification if ‘‘such change 

does not increase the maximum hourly emissions 

achievable at the unit during the five years prior to 

the change.’’ See, also, 57 FR 32314, 32330 (July 21, 

1992) (adopting 40 CFR 60.14(h) and contrasting the 

provision with the pre-existing test). 

15Our 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. 

16One 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. 

refracturing activities result in 

significant VOC emissions. Our data 

indicate very low VOC emissions from 

gas wells (2.6 tpy on average) at the 

wellhead during ongoing production 

prior to such activities. In light of the 

above, we reasonably conclude that 

such activities result in an increase in 

the amount of VOC emissions and, 

therefore, constitute a modification. 

We reject the comments suggesting 

that we should adopt the prior 

fracturing activity as the baseline for 

determining if an emission increase has 

occurred.14 We note that these 

comments appear in part to rely upon a 

misunderstanding of the EPA’s 

longstanding practice that the relevant 

baseline for determining an emissions 

increase under the NSPS is not based on 

the potential emissions profile 

associated with a prior physical change 

or the original construction but rather 

the emissions immediately prior to the 

physical change. See 57 FR 32314, 

32330 (July 21, 1992) (explaining that, 

under CAA section 111(a), an emission 

increase is based on current potential 

emissions rather than original design 

capacity). Accordingly, under historical 

regulations, the proposed regulatory 

language and the final rule that ‘‘initial 

production volumes may have been 

higher than subsequent re-completions 

or refracturing operations because the 

formation has been depleted by 

production activities’’ does not mean 

that there would not be an emissions 

increase. Ongoing emissions during dayto-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. 

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 

well-controlled refracturing activities 

performed by sources. We recognize that 

the approach that we are taking in this 

final rule differs from the approach that 

we have taken in the past, as it excludes 

certain emission increases associated 

with a physical change from 

constituting a modification based on the 

de minimis exception. This exception 

allows agency flexibility in interpreting 

a statute to prevent ‘‘pointless 

expenditures of effort’’ and has been 

previously recognized by the United 

States Court of Appeals for the District 

of Columbia Circuit as an appropriate 

tool when interpreting the CAA section 

111(a)(4) definition of modification in 

the context of New Source Review. 

Alabama Power Co. v. Costle, 636 F.2d 

323, 360 (D.C. Cir. 1979). 

Since the inception of the NSPS 

program, certain emission controls 

could be used by a source to avoid 

having an activity constitute a 

modification provided that the controls 

prevented emissions from increasing. As 

the District of Columbia Circuit 

explained: 

Under provisions of the regulations that are 

not challenged in this litigation, the operator 

of an existing facility can make any 

alterations he wishes in the facility without 

becoming subject to the NSPS as long as the 

level of emissions from the altered facility 

does not increase. Thus the level of 

emissions before alterations take place, rather 

than the strict NSPS, effectively defines the 

standard that an altered facility must meet. 

Asarco Inc. v. EPA, 578 F.2d 319, 328– 

29 (D.C. Cir. 1978); see, also, 75 FR 

54970, 54996 (September 9, 2010) 

(‘‘However, sources always have the 

option of adding sufficient NOX control 

to avoid an hourly emissions increase 

and avoid thus triggering the 

modification provision.’’). We have 

allowed such controls to permit the 

source to avoid being considered 

‘‘modified’’ if the controls fully negate 

the emissions increase. 

In this case, we are providing that 

where a source has in place, and, 

immediately upon flowback, applies 

emission controls equivalent to those 

required for a new source (as specified 

in 40 CFR 60.5375(a)(1) through (4)), the 

physical change will not constitute a 

modification despite the small 

remaining emission increase. 

Specifically, well completions 

conducted by sources for refractured 

wells and with the use, immediately 

upon flowback, of emission controls 

equivalent to those required for new 

sources will not be considered a 

modification, due to the de minimis 

increase in emissions of such wells 

using these controls. Several unique 

factors justify finding that application of 

the de minimis doctrine is appropriate 

here. 

First, to qualify for the exclusion from 

the definition of modification the source 

must be using controls equivalent to 

those required were it to trigger the 

NSPS. As a result, the imposition of the 

NSPS would not yield additional 

regulatory or environmental benefits. 

See Environmental Defense Fund, Inc. v. 

EPA, 82 F.3d 451, 466 (D.C. Cir. 1996). 

Second, as a result of imposition of 

controls emissions are very low in 

magnitude. This is both with respect to 

the size of the increase associated with 

the physical change and the total 

emissions from the unit after the 

physical change. Third, the emissions 

associated with the change, and peak 

emissions post change, are time-limited. 

A well completion is a discrete activity, 

occurring over a 3–10-day period on an 

occasional basis, which may be as 

infrequent as once every 10 years. This 

is different from the type of emitting 

activity typically regulated as a 

modification under NSPS, which would 

involve ongoing emissions indefinitely 

into the future. Further, a source 

qualifying for this exception must 

comply with the recordkeeping and 

reporting requirements that are required 

of new sources. Accordingly, the 

increase in emissions from the physical 

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17We are not considering ‘‘workovers’’ to be 

modifications because: (1) They include truly 

routine activities; (2) in most instances we would 

anticipate only a small emissions increase, if any; 

and (3) we have no reason to think that these wells 

differ in emission profile or control options from 

non-fractured wells (or fractured wells after flow 

back), and accordingly we have not identified a 

BSER that would apply following any such 

modification. 

change, and the total amount of 

additional emissions, will be very small. 

We are providing the de minimis 

exception discussed above to provide 

states with flexibility in application of 

their permitting authority and resources. 

Commenters pointed out that a number 

of state permitting programs are 

triggered for sources that are subject to 

an NSPS as a result of a modification. 

The EPA recognizes that states are the 

most appropriate entities to determine 

whether and how sources should be 

permitted, and we have concern 

regarding potential impacts of this final 

rule on states’ permitting resources. 

Accordingly, with this final rule, we 

intend that states retain the discretion to 

determine whether refracturing 

activities by sources employing control 

techniques that are required for new 

wells will require changes in that 

source’s permit status. 

Clarifying Changes 

Although we are not finalizing the 

proposed definition of ‘‘modification’’ 

for the reasons discussed above, we 

believe it is important to address certain 

comments regarding the proposed 

definition in order to clarify the 

agency’s intent as it relates to well 

completions. For example, we included 

‘‘natural gas’’ in the proposed definition 

for ‘‘modification’’ in recognition that 

our proposed work practice 

requirements for well completions use 

natural gas as a surrogate for VOC. We 

consider natural gas to be an 

appropriate surrogate for VOC for well 

completion activities because our 

analyses of data on composition of 

natural gas at the wellhead indicated 

that emissions of natural gas during well 

completions contain various chemical 

species that are VOC. The inclusion of 

natural gas in the proposed definition 

for modification was not an indication 

that EPA was proposing natural gas as 

a pollutant to be regulated, as some 

commenters mistakenly thought. 

We also received comment objecting 

to defining ‘‘modification’’ based on 

increase in the ‘‘amount of emission’’ 

instead of ‘‘emission rate’’ as provided 

in the General Provisions for 

modifications in 40 CFR 60.14. We had 

intended but were not clear in our 

proposed rule that the definition would 

apply only to well completions. In the 

final rule, we have promulgated the 

provisions discussed above regarding 

well provisions in lieu of the proposed 

definition for modification to clarify our 

intent. 

Finally, this provision is intended to 

address comments suggesting confusion 

associated with our proposed definition 

of ‘‘modification’’ and the separate, 

proposed provision in 40 CFR 60.5420 

that a workover is considered a 

modification. The second of these 

provisions is being removed in light of 

comments that there is no common 

understanding of this term and, as a 

result, it may be interpreted to cover 

more than the fracturing activities the 

EPA intended to cover.17

In summary, as a result of the 

comments and considerations discussed 

above, the final rule provides that well 

completions conducted on gas wells 

that are refractured on or after the 

effective date of this rule are 

modifications and are subject to the 

NSPS. However, gas wells that undergo 

completion following refracturing, with 

the use, immediately upon flowback, of 

emission control techniques otherwise 

required for new wells and that satisfy 

other requirements for gas well 

facilities, including notification, 

recordkeeping and reporting 

requirements, are not considered 

modified and, as a result, are not 

affected facilities under the NSPS. This 

provision is consistent with the NSPS 

program’s history of allowing sources to 

use certain emission controls to avoid 

having an activity constitute a 

modification. In this situation, we 

consider it appropriate to require 

notification, recordkeeping and 

reporting requirements in order to 

ensure that a source is meeting the 

requirements to avail itself of this 

provision. We believe this approach will 

encourage early use of REC and will 

result in 1,000 to 1,500 REC that would 

not otherwise occur during the REC 

phase-in period ending January 1, 2015, 

discussed in section IX.B of this 

preamble. 

2. Regulation of Methane and Other 

Pollutants 

Comment: One commenter believes 

that under CAA section 111, the EPA 

must regulate each dangerous pollutant 

emitted by sources in the oil and gas 

source category in more than de 

minimis quantities for which controls 

are available and asserts that the EPA 

has failed to do so. In particular, the 

commenter states that the EPA must 

regulate methane, particulate matter 

(PM), hydrogen sulfide and nitrogen 

oxides (NOX) from oil and gas 

operations. The commenter states that 

the EPA’s explanation of why it 

declined to regulate certain pollutants 

does not discuss PM or hydrogen 

sulfide, address the most important 

sources of NOX or offer a legal 

justification for its failure to regulate 

methane. The commenter interprets the 

CAA to mean that the EPA must, every 

8 years, (1) review its standards (as it 

has done here), (2) determine whether it 

is ‘‘appropriate’’ to revise them, 

including whether it is appropriate to 

add additional pollutants to the 

standards, and (3) if so, revise them 

accordingly. 

Response: In this rule, we are not 

taking final action with respect to 

regulation of methane. Rather, we 

intend to continue to evaluate the 

appropriateness of regulating methane 

with an eye toward taking additional 

steps if appropriate. On November 8, 

2010, EPA finalized reporting 

requirements for the petroleum and 

natural gas industry under 40 CFR Part 

98, the regulatory framework for the 

Greenhouse Gas Reporting Program 

(GHGRP). Beginning in September 2012, 

this program requires annual reporting 

of greenhouse gases (GHG) from large 

emissions sources and fuel suppliers in 

the United States. Petroleum and 

natural gas facilities will report annual 

methane and carbon dioxide (CO2) 

emissions from equipment leaks and 

venting, and emissions of CO2, methane 

and nitrous oxide from flaring, onshore 

production stationary and portable 

combustion emissions, and combustion 

emissions from stationary equipment 

involved in natural gas distribution. The 

EPA estimates that the rule will cover 

85 percent of the total GHG emissions 

from the United States petroleum and 

natural gas industry with approximately 

2,800 facilities reporting. The data 

submitted under the GHGRP will 

provide important information on the 

location and magnitude of GHG 

emissions from petroleum and natural 

gas systems and will allow petroleum 

and natural gas facilities to track their 

own emissions, compare them to similar 

facilities and aid in identifying costeffective 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 

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49514 Federal Register / Vol. 77, No. 159 / Thursday, August 16, 2012 / Rules and Regulations 

18For 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. 

19While 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. 

required by this rule; and (2) whether 

additional measures are available and 

appropriate for addressing such 

emissions. 

With regard to other pollutants, 

including PM, H2S and NOX, many of 

the sources of PM and NOX within the 

Crude Oil and Natural Gas Production 

source category are within the scope of 

units covered by other NSPS and will be 

evaluated in the context of subsequent 

revisions of those rules, if appropriate. 

This approach is consistent with what 

the agency articulated when we 

promulgated the original oil and gas 

rules. See 49 FR 2637. For example, 

NSPS covering stationary reciprocating 

internal combustion engines (40 CFR 

part 60, subparts IIII and JJJJ) and 

combustion turbines (40 CFR part 60, 

subpart KKKK) regulate emissions of 

PM and NOX from sources found in this 

category. These engines and turbines are 

found in a variety of locations in this 

category including gathering and 

boosting stations, natural gas processing 

plants and natural gas transmission and 

storage facilities. In addition, some 

mobile source regulations (40 CFR part 

1039) cover nonroad engines such as 

those used on drilling rigs, electrical 

generators and hydraulic fracturing 

pumps. As we discussed at proposal 

(see 76 FR 52756) most, if not all, of the 

process heaters and boilers used in this 

category fall below applicability 

thresholds for EPA’s boiler rules (40 

CFR part 60, subparts Db and Dc). 

Although these smaller heaters and 

boilers are generally within the scope of 

this category, we received no 

quantitative data in the public 

comments on NOX or PM emissions 

from these units. Given the broad 

coverage of the PM and NOX sources in 

this category by other NSPS we did not 

depart from the approach adopted in 

1984 of considering these pollutants in 

development of other standards. 

Although the NSPS does not provide 

direct regulation of H2S, the VOC 

control requirements in the final rule 

achieve reductions of H2S a co-benefit 

in cases where H2S is otherwise emitted 

in the oil and natural gas production 

segment. While amine treatment and 

sulfur recovery are routinely employed 

both upstream and at natural gas 

processing plants to remove H2S from 

the natural gas stream, we believe that 

it would not be reasonable or costeffective to require amine units and 

sulfur recovery for every emission point 

in the oil and natural gas production 

segment. We received no public 

comments suggesting other control 

technologies that could be applied to 

control H2S in the field. Such emissions 

occur in the field as fugitive emissions 

at the wellhead and vented emissions 

from well completions, storage vessels, 

pneumatic controllers and compressors. 

However, as mentioned above, the VOC 

control measures provided in the final 

rule for well completions, storage 

vessels, pneumatic controllers and 

compressors greatly reduce any H2S 

emissions along with the VOC 

emissions controlled. 

3. Expanded Scope of the Source 

Category 

Comment: One commenter states that, 

in the preamble, the EPA makes 

reference to its proposal to significantly 

expand the scope of oil and gas 

operations that would be covered by the 

new NSPS, and states that ‘‘[t]o the 

extent that there are oil and gas 

operations not covered by the currently 

listed Oil and Natural Gas source 

category, pursuant to CAA section 

111(b) we hereby modify the category 

list to include all operations in the oil 

and natural gas sector’’ (citing 76 FR 

52745, August 23, 2011). The 

commenter is not aware of any authority 

pursuant to which the EPA may affect 

a significant expansion of the category 

list merely through the language of the 

preamble in an NSPS rulemaking. The 

commenter states that, in a related 

context, the CAA requires that the EPA 

engage in consultation with state 

governors and air pollution control 

agencies, suggesting that more than a 

preamble reference is needed in order to 

expand the category list and impose 

NSPS requirements on the new and 

unique affected sources addressed in 

this rule. See 42 U.S.C. 7411(f)(3). The 

commenter asserts that the sources the 

EPA seeks to regulate are different types 

of stationary sources than gas processing 

plant, and contends that oil and gas 

production wells are stationary sources, 

but are, clearly, not processing plants. 

Response: Because EPA has 

concluded that the currently listed Oil 

and Natural Gas source category covers 

at least those operations in this industry 

for which we are finalizing standards, 

we need not address what steps the 

agency must take if expanding a source 

category.18 As we explained in the 

preamble to the proposed rule, when the 

EPA initially listed this source category, 

it did so in a document where it 

described its listings as broad. 76 FR at 

52745.19 Contrary to commenters 

assertions, the EPA has viewed this 

source category listing very broadly. 

Specifically, when promulgating the 

first sets of standards of performance for 

this source category, we stated that the 

source category ‘‘encompass[es] the 

operations of exploring for crude oil and 

natural gas products, drilling for these 

products, removing them from beneath 

the earth’s surface, and processing these 

products from oil and gas fields for 

distribution to petroleum refineries and 

gas pipelines.’’ 49 FR at 2637 (emphasis 

added). That preamble linked the 

endangerment finding under CAA 

section 111(a) to the industry as a 

whole: ‘‘The crude oil and natural gas 

production industry causes or 

contributes significantly to air pollution 

that may reasonably be anticipated to 

endanger public health or welfare’’ 

(Emphasis added). 49 FR 2636. The 

statements above affirm our conclusion 

that the currently listed Oil and Natural 

Gas source category covers all 

operations for which we are setting 

standards. That the original NSPS’s only 

set standards for a limited set of sources 

within the category cannot be taken to 

imply that other units were not within 

the scope of this original listing. See, 

e.g., Nat’l Lime Ass’n v. EPA, 627 F.2d 

at 426 n. 27 (noting that the EPA set 

standards for only certain kiln types 

within the source category). Indeed, the 

preamble to the 1984 proposed NSPS 

rule directly addresses regulation of 

wells, concluding that the agency was 

not setting standards at that time; not 

because they were outside the scope of 

the source category, but because the 

agency was unable at that time to 

identify ‘‘[b]est demonstrated control 

technology.’’ 49 FR at 2637. As all of the 

units that we are regulating fall within 

the scope of the original listing, we need 

not address what steps would be 

necessary were we to expand the scope 

of the listing. 

B. Major Comments Concerning Well 

Completions 

1. Applicability and Exemptions 

a. Well Exemptions 

Comment: One commenter suggests 

adding ‘‘appraisal wells’’ as a third 

subcategory of well to be exempt from 

the REC requirements, and defines these 

wells as those drilled in an area where 

the reservoir has not been classified for 

that area as containing proved reserves 

of natural gas. According to the 

commenter, adding this definition and 

exemption better reflects the universe of 

wells for which a gas flow line system 

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will not be available. The commenter 

adds that it also avoids a potential 

problem where a shale play appraisal 

well system is effectively compelled to 

install a flow line system before the 

wells are determined to be economically 

viable, in order to assure compliance 

with 40 CFR part 60, subpart OOOO. 

Response: The EPA recognizes that a 

flow line at the well pad is a necessary 

precondition to capture flowback gas for 

emissions control so that the REC 

process has an outlet for the captured 

gas. However, the EPA does not agree 

that appraisal wells need to be exempt. 

Appraisal wells are drilled and then 

logged to assess productivity. If well 

logs indicate that the well is productive, 

then fracturing will be performed, and 

the cost to fracture, complete and 

produce the well, including installing a 

flow line, will be incurred. If the well 

logs indicate the well is not 

economically productive, then no 

fracturing occurs and the NSPS does not 

apply. The EPA, therefore, believes it is 

reasonable to require appraisal wells 

that are hydraulically fractured to 

comply with Subcategory 3 rule 

requirements. 

b. Threshold for Low Pressure (Low 

Volume) Gas Wells and Wells with Low 

or No VOC Emissions 

Comment: One commenter expresses 

support for the REC requirements and 

urges the EPA to limit the number of 

well completions exempted from the 

requirements as much as possible. 

Several commenters contend that not all 

well completions can be conducted 

successfully under a requirement to 

flow back to the flow line, since the 

imposition of the flow line backpressure 

may reduce the flowback gas velocity 

sufficiently so that it is not energetic 

enough to clean up the well of liquid 

and sand. One commenter recommends 

that any well whose reservoir pressure 

(measured at the wellhead immediately 

after perforation) is less than 4 times (in 

absolute units) the line pressure 

measured at the flow meter, would be 

exempt from any requirement to flow to 

sales during the flowback period. 

According to the commenter, variability 

in reservoir and line pressures across 

the United States makes setting a 

specific pressure threshold difficult. 

Response: The EPA has established 

three subcategories of wells in response 

to public comments, as described above. 

One of those categories comprises nonwildcat and non-delineation low 

pressure gas wells. Low pressure gas 

wells are defined as wells with reservoir 

pressure and vertical well depth such 

that 0.445 times static reservoir pressure 

(in pounds per square inch absolute 

(psia)) minus 0.038 times the vertical 

well depth (in feet) minus 67.578 psia 

is less than the flow line pressure at the 

sales meter. Thus, wells above this 

pressure differential must implement 

REC, while wells below this pressure 

differential are required to route 

emissions to a completion combustion 

device. 

The EPA solicited comment in the 

proposed rule on situations where REC 

may be infeasible and criteria and 

thresholds for distinguishing well 

completion operations in those 

situations from others where REC is 

feasible. As noted above, several 

commenters highlighted the technical 

issues that prevent an operator from 

implementing an REC on a low pressure 

gas well, which is the inability to attain 

a gas velocity sufficient to clean up the 

well when flowing against the flow line 

backpressure. Based on this 

information, the EPA agrees that a 

pressure differential threshold is 

reasonable and addresses the technical 

limitations of low pressure gas wells to 

produce to the flow line during 

completion. 

As noted above, a commenter 

recommended specific approaches to 

developing a pressure threshold, 

including specifying that any well 

whose reservoir pressure is less than 4 

times (in absolute units) the line 

pressure measured at the flow meter 

would be exempt from any requirement 

to flow to the flow line during the 

flowback period. This recommendation 

is based on a flowing bottom hole to 

reservoir pressure ratio of 1:2 and a line 

pressure to flowing bottom hole 

pressure of 1:2. The EPA concurs with 

the commenter that flowing bottom hole 

pressure can be represented as half of 

the reservoir pressure for this rule. The 

EPA disagrees with the commenter that 

line pressure can be represented as half 

of the flowing bottom hole pressure for 

this rule since this pressure relationship 

can be more accurately determined 

using the Turner equation for liquids 

unloading from a well paired with 

models relating fluid velocity to 

pressure drop. Therefore, the EPA has 

modeled a worst-case pressure drop 

factor between the line pressure and 

flowing bottom hole pressure and has 

established a pressure threshold using 

this factor and the 1:2 factor for flowing 

bottom hole pressure to reservoir 

pressure. The result of this modeling is 

the equation discussed above in the 

definition of low pressure gas wells. 

As discussed in the proposal 

preamble, potential control options are 

REC with combustion or a completion 

combustion device alone. Because REC 

may not always be technically feasible 

for wells that fall below the pressure 

threshold, the EPA has determined that 

the BSER for reducing VOC emissions 

for this subcategory of wells is a 

completion combustion control device. 

However, the EPA encourages the use of 

REC with combustion should that be a 

viable option for any well within this 

subcategory. Therefore, in the final rule, 

for non-wildcat and non-delineation 

wells with a pressure drop below the 

differential described above, the EPA 

requires the use of either a completion 

combustion device or REC with 

combustion to control gas not suitable 

for entering the flow line. 

Comment: Several commenters 

address parameters for defining which 

well completions would be subject to 

REC requirements. Commenters request 

that the EPA exempt wells with low 

VOC concentrations from the REC 

requirements and not issue the 

proposed standards before reconsidering 

the emissions estimates. One 

commenter suggests that the EPA 

exempt hydraulically fractured natural 

gas horizontal wells with de minimis 

VOC concentrations because the cost 

per ton of VOC reductions is extremely 

high for these wells and the emissions 

from the combustion of the produced 

gas could worsen ozone formation in the 

area. Commenters also provide, as 

examples, some wells with low or no 

VOC as support for exempting wells 

with a low VOC content or for 

exempting certain classes of wells such 

as coal bed methane. Several 

commenters contend that coal bed 

methane wells have low VOC, while 

several other commenters contend that 

coal bed methane wells have no VOC. 

Some commenters provide examples of 

coal bed methane wells with low VOC 

or no VOC, and one commenter 

provides an example of a shale gas well 

with no VOC. 

Response: The EPA acknowledges 

that the VOC concentration in natural 

gas can vary across wells and reservoir 

types such as coal bed methane (CBM), 

shale and tight sands. However, the 

information provided in the comment is 

insufficient for the EPA to determine 

that any specific class of wells, or wells 

with VOC concentration below a 

specific threshold, would not be 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 

mstockstill on DSK4VPTVN1PROD with RULES2

49516 Federal Register / Vol. 77, No. 159 / Thursday, August 16, 2012 / Rules and Regulations 

20Memorandum 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. 

21Rice, Dudley, Composition and Origins of 

Coalbed Gas, U.S. Geological Survey, Denver, 

Colorado. 

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. 

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 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 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 costeffective, especially when taking into 

account the gas savings. Compliance 

with a VOC concentration thresholdbased rule for well completions could 

actually increase the burden to the 

operator by requiring numerous 

compositional analyses to demonstrate 

compliance with the rule. 

c. Definition of Gas Well 

Comment: Several commenters 

mentioned that the proposed definition 

of ‘‘gas well’’ was unclear due to the 

term ‘‘principal production’’ used in 

describing what the well produces. One 

commenter requests that the definition 

of gas well be modified to be each 

respective state’s definition of gas well. 

The commenter states that, by doing 

this, the EPA would eliminate any 

confusion associated with having to 

apply different criteria (NSPS versus 

state regulations) for how to define a 

well-type in assessing the applicability 

of the rule. 

Response: In response to comments 

requesting further clarity in the 

definition, the EPA has revised the 

definition. The proposed definition was 

‘‘Gas well means an onshore well, the 

principal production of which at the 

mouth of the well is gas.’’ In the final 

rule, in response to the comments we 

received, the EPA has revised the 

definition to exclude the phrase ‘‘at the 

mouth of the well is gas.’’ Based on this 

revision, the definition for the final rule 

is ‘‘Gas well or natural gas well means 

an onshore well drilled principally for 

production of natural gas.’’ 

EPA’s intent in setting standards for 

completion of hydraulically fractured 

gas wells is to require reduced 

emissions completions for wells where 

infrastructure is generally present to get 

recovered natural gas to market. Our 

understanding is that owners and 

operators plan their operations to 

extract a target product and evaluate 

whether the appropriate infrastructure 

is available to ensure their product has 

a viable path to market before 

completing a well. We expect that the 

final rule will result in control of 

hydraulically fractured gas wells drilled 

in the four formation types generally 

accepted as gas-producing formations: 

(1) High-permeability gas, (2) shale gas, 

(3) other tight reservoir rock or (4) coal 

seam. We believe that the wording 

changes made to the definition of ‘‘gas 

well’’ clarify the intent so that 

implementing agencies and industry 

will not be burdened with complex 

applicability determinations. 

With respect to using State gas well 

definitions, basing applicability on 

different definitions from State to State 

could introduce inconsistencies that are 

counter to the goal of nationwide 

regulation. We believe the NSPS, being 

a national rule, should contain a single 

definition applicable nationwide. 

However, states may choose to use a 

definition more expansive than our 

definition for their programs. 

Comment: One commenter states that, 

based on the EPA’s discussion in 

Section 4 of the Technical Support 

Document (TSD), it appears the EPA’s 

intent is to require reduced emissions 

completions only for natural gas wells. 

The commenter supports that the EPA 

applied reduced emissions completions 

only to natural gas wellhead facilities 

and excluded oil wellhead facilities and 

other types of gas wells which have 

little or no VOC emissions. The 

commenter states that, as shown on 

page 4–13 on Table 4.4, Nationwide 

Baseline Emissions from Uncontrolled 

Oil and Gas Well Completions and 

Recompletions, of the TSD, there are 

only 134 tpy of VOC emissions from oil 

well completions and recompletions for 

the entire United States, which is not 

worth regulating. 

One commenter recommends the 

following revision: ‘‘Gas well means a 

well, the principal production of which 

at the mouth of the well is [add: 

hydrocarbon gas, not CO2] * * * Well 

means an oil or gas well, a hole drilled 

for the purpose of producing oil or gas, 

or a well into which fluids are injected.’’ 

One commenter proposes the following 

revision: ‘‘Gas well means a well, 

[DELETE the principal production of 

which at the mouth of the well is gas] 

completed for production of natural gas 

from one or more gas zones or 

reservoirs. Such wells contain no 

completions for the production of crude 

oil.’’ The commenter also proposes the 

following revision: ‘‘Gas well means a 

well [STRIKETHROUGH: the principal 

production of which at the mouth of the 

well is gas.] [ADD TEXT: completed for 

production of natural gas from one or 

more gas zones or reservoirs. Such wells 

contain no completions for the 

production of crude oil.]’’ 

Response: Although some wells 

drilled in crude oil formations may 

produce associated gas along with the 

oil, without a gas infrastructure present, 

the EPA does not have sufficient data on 

VOC emissions during completion of 

hydraulically fractured oil wells to set 

standards for these operations at this 

time.22 As a result, the final rule will 

not affect drilling of oil wells. 

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Federal Register / Vol. 77, No. 159 / Thursday, August 16, 2012 / Rules and Regulations 49517 

d. Availability of Infrastructure to 

Convey Gas to Market 

Comment: Various commenters have 

asserted that, in some cases, REC cannot 

be performed on some wells because 

there is no gathering line available to 

convey gas produced during the 

completion flowback period. 

Response: As explained above, it is 

our understanding that owners and 

operators plan their operations to 

extract a target product and evaluate 

whether the appropriate infrastructure 

access is available to ensure their 

product has a viable path to market 

before completing a well. However, in 

the standards for gas well affected 

facilities, the provisions of 40 CFR 

60.5375(a)(1) through (4) apply to all 

fractured gas wells that are not 

exploratory wells, delineation wells or 

low pressure wells. These standards 

require that the well completion 

flowback be conducted using a 

combination of collection (i.e., REC), 

combustion and venting, depending on 

the characteristics of the flowback 

material and feasibility of routing the 

gas to a collection system to be 

conveyed to market. Section 

60.5375(a)(3) provides: 

‘‘You must capture and direct flowback 

emissions that cannot be directed to the flow 

line to a completion combustion device 

* * *’’. 

We believe that owners and operators 

of gas wells subject to 40 CFR 60.5375(a) 

that require REC for a portion of the 

flowback period will exercise due 

diligence in coordinating the 

completion event with availability of a 

flow line to convey captured gas to 

market. However, there may be cases in 

which, for some reason, the well is 

completed and flowback occurs without 

suitable flow line available. In those 

isolated cases, we believe 40 CFR 

60.5375(a)(3) provides for gas not being 

collected and instead combusted or 

vented pursuant to that section. 

e. Fracturing of Wells Using Nitrogen 

and Carbon Dioxide 

Comment: One commenter suggested 

that wells that are fractured using 

nitrogen or CO2 should be exempt from 

the NSPS but did not provide 

supporting rationale. Other commenters 

expressed concern that inert gases such 

as nitrogen are not flammable, making 

compliance with the combustion 

provisions of the NSPS impossible. 

Response: We believe that the 

standards for well completions 

adequately address the concerns 

expressed by operators using nitrogen 

and/or CO2 for fracturing. We provided 

in the proposed rule, and further 

clarified in the final rule, that these 

standards require that the well 

completion flowback be conducted 

using a combination of collection (i.e., 

REC), combustion and venting, 

depending on the characteristics 

(including flammability) of the flowback 

material and feasibility of routing the 

gas to a collection system to be 

conveyed to market. Both the proposed 

and final rules express our intent to 

require REC only where there is salable 

quality gas to the gather line. See 76 FR 

52800 and 40 CFR 60.5375(a)(2) of the 

final rule. 

Section 60.5375(a)(3) in the final rule 

provides: ‘‘you must capture and direct 

flowback emissions that cannot be 

directed to the flow line to a completion 

combustion device, except in conditions 

that may result in a fire hazard or 

explosion, or where high heat emissions 

from a completion combustion device 

may negatively impact tundra, 

permafrost or waterways. Completion 

combustion devices must be equipped 

with a reliable continuous ignition 

source over the duration of flowback.’’ 

Under this provision, operators who 

employ energized fracturing using inert 

gases and cannot route the flowback gas 

to a collection system because of poor 

gas quality must direct the flowback to 

a completion combustion device with a 

continuous ignition source. Although 

part of the flowback gases directed to 

the combustion device would not be 

flammable, the ignition source will 

ignite the flammable portion of the 

flowback, including VOC. Therefore, the 

presence of inert gases such as nitrogen 

and CO2 in the flowback gas has no 

bearing on the VOC reduction we expect 

to achieve through the NSPS or on 

compliance with provisions of the final 

rule. 

2. Rule Should Not Prescribe Equipment 

Comment: Several commenters 

suggest revising 40 CFR 60.5375(a)(2) 

equipment requirements to be less 

prescriptive, especially in cases where 

use of specified or all listed equipment 

may not be necessary, and to provide 

flexibility to include newly developing 

technology. Other commenters assert 

that language in 40 CFR 60.5375(a)(1) 

and (2) stating that source owners or 

operators should ‘‘minimize the 

emissions associated with venting of 

hydrocarbon fluids and gas’’ and that 

‘‘[a]ll salable gas must be routed to the 

gas gathering line as soon as 

practicable’’ is vague and recommended 

a requirement that facility owners 

follow a Best Management Practice 

(BMP) plan that the EPA could develop, 

informed by the Natural Gas STAR 

program. 

Response: The EPA agrees that 

prescribing specific equipment to 

accomplish a reduced emissions 

completion is not necessary and has 

revised the rule language to not 

prescribe specific equipment. The 

operational standards provided in the 

NSPS allow the operator flexibility to 

perform the REC using equipment and 

practices best determined by the 

operator. As a result, we believe that a 

BMP plan developed by the EPA would 

not provide a higher degree of emissions 

control and could hinder innovation. 

3. Availability of Equipment and 

Trained Personnel 

Comment: Commenters state that the 

supply of REC equipment and personnel 

is insufficient to meet the requirements 

of the proposed rule, applied nationally. 

According to commenters, proper 

surface equipment, collection 

infrastructure and qualified personnel 

are not readily available; they assert that 

this equipment is fairly specialized, the 

shops licensed to make it are limited 

and some of the components require a 

long lead time. For these reasons, 

commenters indicate that compliance by 

the issuance date of the rule would be 

unrealistic and that the EPA should 

provide a longer compliance period. 

Response: Based on information 

submitted by commenters, we have 

reason to believe that, currently, there is 

already significant demand for REC 

equipment. For example, Colorado, 

Wyoming, the City of Fort Worth, Texas, 

and the City of Southlake, Texas, 

require REC under certain conditions. 

Additionally, public comments, reports 

to the EPA’s Natural Gas STAR Program 

and press statements from companies 

indicate that some producers implement 

REC voluntarily, based upon economic 

and environmental objectives. If REC 

were to be immediately required of all 

well completions, NSPS would place 

significant additional demands on REC 

equipment supply and experienced 

personnel. 

As the near-term supply of REC 

equipment and trained personnel will 

be insufficient to meet the new national 

demand for equipment and labor, 

immediate compliance with the REC 

requirements could be impossible, 

potentially causing producers to delay 

well completions until appropriate 

equipment and labor are available. 

Resulting delays in well completions 

while awaiting equipment availability 

could cause a decrease in the 

nationwide natural gas supply and 

would drive up the cost of completions 

doing REC. It is not the EPA’s intent to 

set in motion a series of events through 

this rule that has the potential to affect 

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49518 Federal Register / Vol. 77, No. 159 / Thursday, August 16, 2012 / Rules and Regulations 

23Available at: http://www.epa.gov/gasstar/

documents/reduced_emissions_completions.pdf. 

the natural gas supply and increased 

cost of REC would undermine our BSER 

analysis. Accordingly, it is important 

that the EPA consider the availability of 

REC equipment and personnel in its 

BSER analysis. 

Through EPA and industry events and 

collaborative studies, the EPA has 

interacted with operating companies 

that have extensive experience 

implementing REC. In particular, the 

EPA developed a detailed study 23 on 

REC in collaboration with service 

providers. Based on this experience, the 

EPA has gained extensive information 

on this technology. Despite these efforts, 

the EPA is not aware of any quantitative 

information on the current and future 

supply of workers trained in REC 

techniques. 

The EPA received data on the current 

and future supply of REC equipment. 

According to one commenter, about 300 

REC units are in use today, with the 

ability to process about 4,000 wells per 

year, and 1,300 additional units would 

be required to perform 20,000 REC per 

year. About 1,600 units performing 

20,000 REC/year implies a REC 

productivity rate of about 12.5 REC/ 

year/unit, or roughly each unit 

performing one REC per month, on 

average. 

The NSPS proposal estimated 9,300 

REC performed for new natural gas well 

completions and 12,200 REC performed 

for existing natural gas well completions 

following refracturing would be 

required, in addition to those already 

required by state regulations. In the 

analysis supporting the final rule, the 

EPA revised estimates show 11,403 

hydraulically fractured and 1,417 

hydraulically refractured natural gas 

well completions will be performed in 

a representative year, which includes 

completions in states which currently 

have REC requirements. The revised 

estimate also reflects a change in the 

refracture frequency of existing wells 

from 10 percent to 1 percent based on 

information provided by commenters. 

Of the total hydraulically fractured well 

completions, the EPA estimates that 

about 11,300 REC will be required 

nationally on the basis of the final rule’s 

provisions for wildcat (exploratory) and 

delineation wells, flowback gas pressure 

and natural gas well completions 

conducted on existing gas wells that are 

subsequently fractured or refractured. 

This estimate excludes REC required by 

state regulations. 

Assuming a REC unit performs 12.5 

REC/year, as is asserted by the 

commenter, about 900 units would be 

required. This implies a current 

shortfall of about 600 units, based upon 

the numbers and assumptions provided 

by the commenter. The commenter 

states that industry can deliver about 50 

units per quarter, after a 1-year build-up 

period. Given that the EPA does not 

have an alternative estimate of the 

number of REC units industry can 

produce per year, we adopt the estimate 

of 50 units per quarter for this analysis, 

although the EPA disagrees with the 

assumption that a 1-year build-up 

period is required. Using the 

commenter’s assumptions, it would take 

about 4.25 years to meet demand. This 

scenario is depicted in Scenario A in 

Table 6 below, assuming compliance is 

initiated at the beginning of the second 

quarter, 2012, and the industry begins 

delivering 50 units per quarter roughly 

1 year after the compliance date. 

Surveys conducted by one commenter 

indicate that nine companies expect to 

perform more REC than the current 

stock is capable of. Given this growing 

demand, it is reasonable to assume 

industry can deliver units during the 

build-up period of the first year of 

implementation, which would reduce 

the time required to meet full demand 

another year to a total of about 3.25 

years (Scenario B). 

The EPA also assessed whether the 

productivity of equipment in use could 

be higher than the 12.5 REC/year/unit 

derived from the comment, and the 

potential impact of such increase on the 

equipment supply. The EPA estimated 

that flowback periods will typically be 

3 to 10 days with 7 being a reasonable 

average. Therefore, because it is likely 

that a REC unit could be moved to 

another well site and be in operation in 

less than 20 to 27 days, it is reasonable 

to conclude that each REC unit can 

perform more than 12.5 REC/year. 

If the utilization rate of REC units is 

increased gradually from performing 

12.5 REC/year/unit to 14 to 18 REC/ 

year/unit, the time required to build the 

supply of REC units decreases 

(Scenarios C–G). As Table 6 shows, each 

1 REC/year/unit increase reduces the 

build-up time by about 1 quarter. As is 

shown in Scenarios C and G, increasing 

the utilization rate of REC to 14 to 18 

REC/unit/year with industry supplying 

new units beginning with the 

compliance date would provide 

between 1.75 and 2.75 years for full 

build-out of the REC unit supply by the 

beginning of calendar year 2015. 

TABLE 6—REC UNIT SUPPLY ANALYSIS

Scenario A B C D E F G 

RECs Required .................................................................... 11,301 11,301 11,301 11,301 11,301 11,301 11,301 

RECs/year/unit ..................................................................... 12.5 12.5 14.0 15.0 16.0 17.0 18.0 

Units Needed ....................................................................... 904 904 807 753 706 665 628 

Stock in Existence (assume industry can build 50 units/quarter; assuming industry starts with 300 units); compliance begins approximately at 

the end of the second quarter, 2012. 

2012 (Q1) ............................................................................. 300 300 300 300 300 300 300 

2012 (Q2) ............................................................................. 300 300 300 300 300 300 300 

2012 (Q3) ............................................................................. 300 350 350 350 350 350 350 

2012 (Q4) ............................................................................. 300 400 400 400 400 400 400 

2013 (Q1) ............................................................................. 300 450 450 450 450 450 450 

2013 (Q2) ............................................................................. 300 500 500 500 500 500 500 

2013 (Q3) ............................................................................. 350 550 550 550 550 550 550 

2013 (Q4) ............................................................................. 400 600 600 600 600 600 600 

2014 (Q1) ............................................................................. 450 650 650 650 650 650 650 

2014 (Q2) ............................................................................. 500 700 700 700 700 700 ................

2014 (Q3) ............................................................................. 550 750 750 750 750 ................ ................

2014 (Q4) ............................................................................. 600 800 800 800 ................ ................ ................

2015 (Q1) ............................................................................. 650 850 850 ................ ................ ................ ................

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Federal Register / Vol. 77, No. 159 / Thursday, August 16, 2012 / Rules and Regulations 49519 

TABLE 6—REC UNIT SUPPLY ANALYSIS—Continued 

Scenario A B C D E F G 

2015 (Q2) ............................................................................. 700 900 ................ ................ ................ ................ ................

2015 (Q3) ............................................................................. 750 950 ................ ................ ................ ................ ................

2015 (Q4) ............................................................................. 800 ................ ................ ................ ................ ................ ................

2016 (Q1) ............................................................................. 850 ................ ................ ................ ................ ................ ................

2016 (Q2) ............................................................................. 900 ................ ................ ................ ................ ................ ................

2014 (Q3) ............................................................................. 950 ................ ................ ................ ................ ................ ................

Because of uncertainties in the supply 

of equipment and labor over the nearterm, 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 completionrelated 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 phasein period, VOC emissions reductions 

would be maintained because 

completion emissions will be either 

combusted or captured. The EPA 

maintains that the benefit of the VOC 

reduction during the phase-in period far 

outweighs the secondary impact of NOX

formation during pit flaring. The phasein period would also minimize the 

possibility that the cost of REC 

equipment and labor increases over the 

near-term, enabling producers to better 

plan efficient use of existing and new 

capital and labor, and providing 

additional time for innovation in REC 

technologies and/or practices. We 

believe this period provides ample time 

for this technology to be built and 

available for use. 

At the same time, for wells 

undergoing recompletions during the 

period prior to January 1, 2015, the 

terms of 40 CFR 60.5365(h), which 

specify that ‘‘[a] gas well facility that 

conducts a well completion operation 

following hydraulic refracturing is not 

an affected facility, provided that the 

requirements of section 60.5375 are 

met,’’ may provide an additional 

incentive for producers to use REC units 

prior to January 1, 2015, if they can 

obtain appropriate equipment and labor. 

Also, considering the requirement in 

some states that any source subject to a 

federal NSPS must get a state minor 

source air permit, we anticipate that the 

desire to avoid even short term delays 

caused by state permitting, as well as 

the associated costs, will serve as an 

incentive for the use of REC during well 

completion operation following 

hydraulic refracturing, including 

operations prior to January 1, 2015. 

Furthermore, as January 1, 2015, 

approaches it is highly likely that 

providers of REC equipment and related 

services will be increasing availability 

of such equipment and services in ways 

that benefit supply and price. For these 

reasons, the EPA anticipates that during 

the period between promulgation and 

January 1, 2015, between 1,000 and 

1,500 wells will be recompleted with 

REC units, notwithstanding the 

requirements of 40 CFR 60.5375(a) and 

the combustion option they provide. 

4. Cost and Emissions Calculations 

Comment: Some commenters request 

the EPA to fully explain or reconsider 

the 10-percent rate of refracturing of 

wells. 

Response: In response to comment, 

the EPA has reevaluated the assumption 

that, on average, each fractured gas well 

is re-fractured every 10 years, which 

equates to approximately 10 percent of 

fractured gas wells being re-fractured 

each year, based on drilling and refracture records from an industry 

representative. Based on its review of 

the comment, including references 

noted in the comment and other 

information available to the agency, the 

EPA concluded that it had 

overestimated the re-fracturing 

frequency. The information reviewed by 

the EPA, which, altogether, represent 

over 20,000 gas wells over multiple 

years, some as far back as 2000, indicate 

that the annual recompletion frequency 

can be as low as 0.1 percent and as high 

as 0.8 percent. Based on this 

information, the EPA has revised its 

estimate of re-fracturing frequency from 

10 percent to 1 percent of fractured gas 

wells per year. The EPA rounded the 

figures provided by the companies to 

reflect the uncertainty in the data. 

5. Definition of Affected Facility 

Comment: Several commenters assert 

that a well completion is different from 

a well workover and should be better 

defined in the rule. 

Response: Based on the comments 

received, the EPA acknowledges that the 

term ‘‘workover’’ is a general term that 

may have a number of different 

meanings. Based on the various 

definitions of the term provided by the 

commenters, we realize that workover 

may be interpreted to include routine 

maintenance activities that we did not 

intend to cover under the rule and 

which result in no increase in 

emissions. Therefore, in the final rule 

we have revised the definition of ‘‘well 

completion operation’’ to exclude the 

term ‘‘workover’’ and, instead, include 

the phrase ‘‘with hydraulic fracturing.’’ 

C. Major Comments Concerning 

Pneumatic Controllers 

1. Definition of Affected Facility 

Comment: Some commenters request 

that the EPA consider excluding or 

exempting emergency and/or safety 

system devices (such as a pilot operated 

pressure relief valve). According to one 

commenter, safety system devices 

typically do not emit gas unless there is 

an emergency, have a near-zero VOClevel 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 

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24The 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. 

natural gas emissions. According to the 

commenter, a gas-powered controller is 

a reliable alternative for safe plant 

operation during emergencies, and the 

commenter suggests that the final rule 

include an exception to allow gas plants 

to use natural gas-driven pneumatic 

controllers for emergency plant 

shutdown and subsequent startup. 

With regard to high-bleed pneumatic 

controllers, several commenters request 

that the EPA further explain when the 

use of high-bleed pneumatic controllers 

is allowed and provide specific 

examples of exemptions. The 

commenters suggest exemptions that 

address situations such as those where 

the natural gas includes impurities that 

could increase the likelihood of fouling 

a low-bleed pneumatic controller, such 

as paraffin or salts; where weather 

conditions could degrade pneumatic 

controller performance; during 

emergency conditions; where flow is not 

sufficient for low-bleed pneumatic 

controllers; where electricity is not 

available; and where engineering 

judgment recommends their use to 

maintain safety, reliability or efficiency. 

Several commenters request that the 

EPA provide additional information 

about how to demonstrate that the use 

of high-bleed pneumatic controllers is 

predicated, as stated in proposed 40 

CFR 60.5390(a). The commenters 

suggest that this exemption is very 

vague, will allow for excessive 

emissions and is not enforceable. 

Response: The EPA included in the 

proposed rule exemptions from the 

NSPS to allow the use of a controller 

with a natural gas bleed rate greater than 

6 scfh due to functional needs. These 

exemptions include, but are not limited 

to, response time, safety and actuation 

of valves. These functional exemptions 

to the requirement address the 

commenters’ concerns of safety, 

emergency and otherwise non-routine 

situations that require the use of a 

controller with a natural gas bleed rate 

greater than 6 scfh. In response to 

comments regarding vagueness of the 

proposed exemption, the EPA revised 

this exemption provision in the final 

rule. We believe the provision in the 

final rule clarifies the scope of this 

exemption. 

Comment: Several commenters 

express concerns with the proposed 

rule’s treatment of various types of 

pneumatic devices and controllers. One 

commenter requests that the EPA clarify 

in 40 CFR part 60, subpart OOOO that 

intermittent bleed pneumatic devices 

are not affected sources. Another 

commenter asserts that continuous lowbleed 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. 

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 segment 24 to address a 

number of the comments described 

above. Specifically, for pneumatic 

controllers at gas processing plants 

where the standard is zero bleed rate, 

we have defined the affected facility as 

a continuous bleed natural gas-driven 

pneumatic controller. For other areas in 

the production segment (i.e., excluding 

gas processing plants), where the 

standard is a bleed rate of 6 scfh or less, 

we have defined the affected facility as 

a continuous bleed natural gas-driven 

pneumatic controller operating at a 

bleed rate greater than 6 scfh. By 

defining the pneumatic controllers 

affected facilities to be continuous bleed 

and gas-driven, we clarify that the NSPS 

does not apply to intermittent bleed 

devices, no-bleed pneumatic devices (by 

design), self-contained devices and 

devices driven by instrument air. The 

revised definitions also exclude from 

the NSPS coverage owners and 

operators who are already using 

(including replacement) pneumatic 

controllers that meet the applicable 

standards, thus, relieving them from the 

cost and other burdens related to 

compliance. 

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, 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, 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. 

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25For 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. 

26For 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. 

According to the commenters, 

regulating the use of compressed air or 

‘‘instrument air’’ or other gas having 

little or no VOC would impose a 

significant burden on the industry 

without any added benefit. 

Response: The EPA disagrees with the 

comment that the pneumatic controller 

standards must be based on VOC 

emissions instead of natural gas bleed 

rate as a surrogate for VOC emissions 

rate. Natural gas is being used as a 

surrogate for VOC given the 

proportional relationship between them. 

When a natural gas stream is emitted to 

the atmosphere, VOC in the gas also 

reaches the atmosphere since it is a 

component of the natural gas stream. 

The natural gas emissions occur without 

any physical separation, chemical 

separation or chemical reaction process 

of the chemical species within the 

natural gas; therefore, the proportion of 

VOC in natural gas is not altered during 

the course of being emitted to the 

atmosphere, and natural gas is an 

appropriate surrogate for VOC. As an 

example, when the natural gas 

emissions change, the VOC emissions 

change proportionately. In addition, 

measuring the VOC content of a 

pneumatic controller’s bleed gas adds 

cost burden to companies and, to the 

EPA’s knowledge, vendors/ 

manufacturers do not report the VOC 

emissions from a pneumatic controller 

primarily because the VOC emissions 

would depend on the gas composition at 

the site the pneumatic controller is 

located. 

In the preamble to the proposed rule, 

the EPA set forth its BSER analysis for 

pneumatic controllers. In the TSD, the 

EPA has provided cost-effectiveness 

calculations for the proposed pneumatic 

device emission limits. The commenters 

do not dispute the EPA’s analysis. 

Rather, the commenters ask that the 

EPA establish a VOC threshold. 

However, the commenters have not 

provided information on how an 

appropriate threshold can be 

established. One commenter suggests a 

threshold of 10-percent VOC content by 

weight, but has not provided supporting 

information justifying this threshold. 

However, for the reasons stated in the 

response to comment in section IX.C.2 

of this preamble, the EPA has decided 

not to cover in this final rule the 

pneumatic controllers in the 

transmission and storage segment. With 

respect to those controllers we are not 

taking final action at this time. 

Comment: One commenter suggested 

that the EPA provide a phase-in period 

to allow manufacturers and companies 

time to designate which controllers 

qualify as low-bleed. This commenter 

further notes that bleed rates are not 

specified for pneumatic controllers or 

are inconsistently represented without 

distinguishing between the continuous 

bleed stream and the actuation stream 

rates within the gas consumption 

specifications. 

Response: In the proposed rule, for 

pneumatic controllers 25 in the 

production segment other than gas 

processing plants, the EPA proposed a 

performance standard of a natural gas 

bleed rate of 6 scfh to reflect the use of 

a low-bleed controller, which we had 

determined to be the BSER for reducing 

VOC emissions from pneumatic 

controllers in the production segment.26

Owners and operators would 

demonstrate compliance based on 

information in the manufacturers’ 

specifications for the pneumatic 

controllers, which we had believed 

would provide either the bleed rate or 

relevant information for such 

determination. Upon further 

investigation, in light of the comments, 

we conclude that such information is 

not always included in current 

manufacturers’ specifications. We 

anticipate that manufacturers who 

currently do not provide the relevant 

information for determining bleed rate 

would adjust to this need and begin 

testing their products and provide the 

necessary information on the products’ 

specifications. Based on public 

comments and other available 

information, the EPA believes that an 

adjustment period is needed, during 

which owners and operators could face 

increased cost and, in some instances, 

difficulty in obtaining necessary 

supplies due to the limited number of 

currently available controllers with 

adequate documentation for 

determining bleed rate. In light of the 

above, we conclude that a low-bleed 

controller is not the BSER for pneumatic 

controller affected facilities in the 

production segment (excluding gas 

processing plants) during this first year. 

As explained in the proposed rule, we 

are not aware of any add-on controls 

that are or can be used to reduce VOC 

emissions from gas driven pneumatic 

devices. 76 FR 52760. One commenter 

broadly suggests that we consider flares, 

combustion devices and vapor recovery, 

but provides no supporting information. 

In light of the above, we conclude that 

there is no BSER for pneumatic 

controller affected sources in the 

production segment (excluding gas 

processing plants) during the 

‘‘adjustment period’’ mentioned above. 

In determining the length of the 

adjustment period, the EPA evaluated 

relevant comments and available 

information, including information from 

promulgation and implementation of 40 

CFR part 98, subpart W of the 

Greenhouse Gas Reporting rule. Subpart 

W requires operators to conduct a 

complete inventory and report to EPA 

the number of low- and high-bleed 

pneumatic devices, as those terms are 

defined in subpart W, over a 3-year 

period (i.e., 1⁄3 of their devices every 

year over a 3-year period) starting 

January 2011. We believe that efforts are 

well under way for manufacturers to 

provide necessary information to help 

facilities subject to subpart W determine 

the pneumatic controllers’ bleed rates 

and comply with the reporting rule 

requirements, 1⁄3 of which must be 

reported by September 2012 and 

another third by September 2013 and 

the entire inventory by September 2014. 

In light of the above, we do not believe 

that owners and operators would face 

the difficulty described above beyond 

the first year after this NSPS becomes 

effective. After this first year of 

‘‘adjustment period,’’ we believe owners 

and operators should have no problem 

securing controllers with relevant 

documentation for determining bleed 

rate. Therefore, beginning the second 

year, the BSER remains the low-bleed 

controllers, as proposed. 

For the reasons stated above, the final 

rule contains no standards for 

pneumatic controller affected facilities 

in the production segment during the 

first year after this rule becomes 

effective, but, thereafter, requires that all 

new and modified affected facilities to 

meet a VOC limit of 6 scfh natural gas 

bleed rate to reflect the use of a lowbleed controller. The need for adequate 

manufacturers’ specifications is not an 

issue for pneumatic controllers at 

natural gas processing plants. For 

pneumatic controller affected facilities 

at natural gas processing plants, we had 

proposed a zero VOC emission limit, the 

compliance of which can be 

demonstrated by the use of a non-gasdriven controller system. As noted by 

commenters, most natural gas 

processing plants already use non-gasdriven technology such as instrument 

air systems for safety and operational 

reasons. While one cannot distinguish 

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gas-driven pneumatic controllers of 

different bleed-rates without 

information from manufacturers, a nongas-driven controller can be easily 

identified by visual inspection. 

Therefore, no change is made since 

proposal to the standards for pneumatic 

controller affected facilities at gas 

processing plants. 

In response to comments that units 

already in stock at the time of proposal 

cannot be used, the EPA clarifies that 

pneumatic controllers that were already 

in stock or ordered prior to August 23, 

2011, are considered existing sources 

and, therefore, their installation is not 

subject to the pneumatic controllers 

NSPS in this final rule. 

2. Controllers in the Transmission and 

Storage Segment 

Comment: Several commenters 

requested the EPA reevaluate 

requirements for pneumatic controller/ 

devices in the natural gas transmission 

segment of the industry. The 

commenters argue that the proposed 

rule’s applicability is too broad and 

would result in an undue recordkeeping 

and permitting burden. 

Several commenters recommend that 

40 CFR part 60, subpart OOOO should 

limit pneumatic controller applicability 

to upstream processes. Some 

commenters suggest that, for natural gas 

transmission and storage, either 

pneumatic controllers should be 

completely excluded or subpart OOOO 

should limit applicability to equipment 

located at ‘‘conventional’’ facilities, e.g., 

within the fence line at a compressor 

stations. One commenter recommends 

limiting the emission limit requirement 

to controllers at natural gas processing 

plants or locations upstream from gas 

processing that exceed a defined VOC 

threshold. The commenter suggests that 

this exclusion would reduce 

administrative costs in two ways: 

Mandatory recordkeeping and reporting 

would be removed and the 

documentation required to explain why 

excluded controllers would no longer be 

necessary would be removed. Another 

commenter suggests that the EPA state 

in the final rule that NSPS/NESHAP 

applicability alone should not trigger 

minor source permitting requirements. 

Response: The EPA agrees that cost 

and other compliance burdens are 

important considerations in a 

rulemaking. In fact, the EPA believes 

that such consideration is particularly 

important here given that coverage of 

the transmission sector would result in 

a significant number of sources and 

owner and operators that are not subject 

to the current standards. Specifically, 

were we to finalize standards, we 

estimate that we would end up covering 

an additional 67 sources. We estimate 

VOC emissions from these units to be 

0.1 tpy per facility or about 6 tpy 

nationwide for new sources, which is 

well below the level emitted by other 

affected facilities in this sector. 

While our analysis suggests that this 

is an important set of sources to 

regulate, given the large number of 

sources, and the relatively low level of 

VOC emitted from these sources, we 

have concluded that additional 

evaluation of these compliance and 

burden issues is appropriate prior to 

taking final action on pneumatic 

controllers in the transmission and 

storage segment. For this reason, the 

requirements for pneumatic controllers 

in the final rule only apply to 

production through processing 

segments. Our current data indicate that 

the VOC content of the natural gas used 

for pneumatic controllers in the 

transmission and storage segment is 

low, while higher VOC content natural 

gas is used in the segments we are 

regulating. Also, for the reasons 

explained in the previous response to 

comment, no VOC threshold will be 

included in this regulation. 

3. Cost and Emissions Calculations 

Comment: One commenter asserts 

that the EPA’s estimate of 14,000 new 

and replaced controllers in a given year 

is grossly underestimated. By the 

commenter’s data and calculations, 

approximately 750,000 controllers in 

Texas alone may need to be replaced 

(unless an exemption is granted) once a 

well becomes subject to the new rule. 

Response: The commenter incorrectly 

claims that the EPA’s estimate of the 

number of pneumatic controllers 

installed in a given year is 14,000. In 

Section 5.3.2 of the TSD, the EPA 

explains its methodology for estimating 

the number of pneumatic controllers in 

both gas/oil production and gas 

transmission and storage. Table 5–3 of 

the TSD gives a breakdown of snapacting versus bleed controllers and 

shows the total number of controllers to 

be 33,673. The commenter did not 

provide data to support its claim that 

there are 750,000 pneumatic controllers 

in Texas, or that all of them have bleed 

rates higher than the proposed NSPS 

requirements such that any future 

replacement would require the use of a 

different model (i.e., low bleed or no 

bleed, depending on its location) of 

controller. In any event, the EPA has 

analyzed and determined that such 

replacement is cost-effective. One 

explanation for the commenter’s high 

estimate may be a misunderstanding of 

the applicability of the final rule. We 

remind the commenter that the final 

rule does not apply to existing sources, 

unless the existing source is replaced, 

modified or reconstructed after August 

23, 2011. 

D. Major Comments Concerning 

Compressors 

1. Compressors in the Transmission and 

Storage Segment 

Comment: One commenter stated that 

the agency should exempt reciprocating 

and centrifugal compressors in the 

transmission and storage sector located 

after the point of custody transfer, 

because there is low-VOC content in 

natural gas from that sector. Another 

commenter urged the EPA to revise 40 

CFR 60.5365 to exclude centrifugal 

compressors not associated with the 

Crude Oil and Natural Gas Production, 

Transmission, and Distribution sector. 

One commenter noted that some large 

natural gas customers (who are not in 

the Crude Oil and Natural Gas 

Production, Transmission, and 

Distribution sector) have natural gas 

centrifugal compressors that are used to 

increase the pressure of natural gas for 

use in an industrial process, or to 

compress natural gas used as the fuel in 

compressed natural gas vehicles. 

One commenter argued further that 

even without regard to fundamental 

flaws stated in the five factors or 

methods, there still would be only 

trivial and inconsequential VOC 

reductions relative to the national VOC 

inventory. The commenter observed that 

achieving VOC reductions of 1 percent 

of the national anthropogenic VOC 

inventory would require over 21,000 

regulations at 6.9 tpy, and that the 

EPA’s estimated annual VOC reductions 

for compressors was similarly 

inconsequential. Nor, said the 

commenter, had the EPA adequately 

considered administrative burdens 

associated with reporting, 

recordkeeping and permitting. The 

commenter said the trivial, incremental 

emissions reductions that would result 

from the rule failed to justify the 

associated compliance costs and that the 

final rule should exclude transmission 

and storage sources. Another 

commenter expressly called on the EPA 

to reanalyze VOC emissions reductions 

and to reassess whether the rule would 

be cost effective. Also taking issue with 

supportive data, another commenter 

said the EPA should suspend 

rulemaking and expand its fact-finding 

to include a statistically significant 

sampling of affected sources. One 

commenter suggested that the EPA 

exclude centrifugal compressor facilities 

that compress natural gas that is less 

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than 10 percent, weight basis, VOC. The 

commenter stated that compression of 

gas that does not contain VOC should 

not be subject to standards for VOC. The 

commenter believes this is consistent 

with equipment leak rules which do not 

regulate components that are not in 

VOC service. 

Response: The EPA agrees with the 

commenter that natural gas in the 

transmission and storage segment has 

low-VOC content. The EPA notes that 

cost and other compliance burdens are 

important considerations in a 

rulemaking. We estimated the VOC 

emissions reductions from these units 

located in the transmission and storage 

segment to be 14.1 tpy for reciprocating 

compressors and 6.6 tpy for centrifugal 

compressors, which is well below the 

level emitted by other affected facilities 

in this segment. The EPA has not fully 

considered compliance burden for 

reciprocating and centrifugal 

compressors in the transmission and 

storage segment and is, therefore, not 

ready to take final action with respect to 

these sources. While our analysis 

suggests that this is an important set of 

sources to regulate, given the number of 

sources, and the relatively low level of 

VOC emitted from these sources, we 

have concluded that additional 

evaluation of these compliance and 

burden issues is appropriate prior to 

taking final action on reciprocating and 

centrifugal compressors in the 

transmission and storage segment. 

Also, no VOC threshold will be 

included in this regulation given the 

arbitrary nature of defining one using 

available data. We believe this revision 

also addresses centrifugal compressors 

not associated with the Crude Oil and 

Natural Gas Production, Transmission, 

and Distribution sector. 

2. Dry Seals Versus Wet Seals 

Comment: Several commenters 

address the issue of whether the EPA 

should permit the use of a system other 

than dry seal to control emissions from 

centrifugal compressors. Some 

commenters provide information on 

situations where dry seal systems for 

centrifugal compressors are not 

technically feasible, such as where gas 

composition is inadequate, in some 

processing plants that already have a 

capture system in place, and in retrofits 

of some existing compressors due to 

housing design or operational 

requirements. Commenters opine that 

the rule should allow compliance using 

either system, depending upon 

particular circumstances, and should 

not preclude use of a wet seal-equipped 

compressor with controls capable of 

meeting a 95-percent VOC control 

efficiency or routing captured seal-oil 

gas to a fuel gas, recycling or other 

processing system. According to another 

commenter, it would not be feasible to 

capture gas that escapes from a 

centrifugal compressor and route it back 

to a low-pressure fuel stream for 

combustion as fuel gas; although such a 

process would capture a minimal 

amount of VOC emissions, the high cost 

of equipment to recapture the emissions 

would make the method described costprohibitive. 

Commenters generally concurred that 

a 95-percent reduction in emissions was 

achievable through installing a capture 

system on a wet seal compressor. In 

addition, commenters disagreed with 

the EPA’s cost estimates and concluded 

that a wet seal capture system is cost 

effective. 

Response: In the preamble to the 

proposed rule, the EPA proposed that a 

dry seal system is the BSER for 

centrifugal compressors, but solicited 

comments on situations where the use 

of a dry seal is infeasible or otherwise 

inappropriate and wet seal is the only 

option. 76 FR 52762. As noted above, 

several commenters provided 

information on situations where dry 

seals are not technically feasible. 

Therefore, the EPA has concluded that 

dry seal is not the BSER for all new and 

modified centrifugal compressors. 

Instead, the EPA separately evaluates 

the control options for wet seal 

compressors. The EPA has identified 

one control option through its review of 

available information, including 

comments and other information 

obtained since proposal. The option is 

to route captured seal-oil gas to the 

compressor suction, fuel gas system or 

flare, all of which can achieve 95- 

percent control efficiency. 

Based on the discrepancy between 

commenters’ and the EPA’s cost data, 

the EPA re-evaluated its cost 

information for this control option. The 

EPA cost estimates in the proposed rule 

assumed the use of a new flare to 

combust the captured seal oil gas, and, 

based on commenter information, the 

EPA is revising this assumption since a 

flare or other combustion source is 

expected to be available in gas 

processing facilities. From reviewing 

comments received, the EPA is aware 

that the captured gas is not always 

routed to a flare but in many cases is 

routed back to the compressor suction 

or fuel system. Given this information, 

the EPA has re-evaluated the costs for 

the centrifugal compressor wet seal 

capture system and determined a system 

of this type, in which the seal oil 

degassing vents are routed to fuel gas, 

compressor suction or an existing flare 

would cost $22,000. The estimated cost 

includes an intermediate pressure 

degassing drum, new piping, gas 

demister/filter and a pressure regulator 

for the fuel line. With this cost, the 

estimated VOC control cost 

effectiveness is $161/ton of VOC for the 

processing segment. If savings are 

included, the cost effectiveness for VOC 

control is ¥$2,408/ton of VOC. 

In light of the above, we have 

determined that the control option 

described above is the BSER for wet seal 

compressors. Accordingly, the final 

NSPS would require that wet seal 

compressors reduce emission by 95 

percent. For dry seal compressors, the 

only emission control option we have 

identified is the use of dry seal. 

Accordingly, there is no requirement in 

the final rule for dry seal compressors, 

and dry seal compressors are not 

affected facilities under the NSPS. 

3. New Source Definition 

Comment: Several commenters 

oppose the proposal in 40 CFR 

60.5365(b) and (c) that a reciprocating 

compressor be considered as 

‘‘commenced construction’’ on the date 

of installation at a facility. Commenters 

argue that the EPA was ‘‘arbitrary and 

capricious’’ in proposing to apply the 

concept of ‘‘commenced construction’’ 

in the NSPS context to a relocated 

compressor, because the agency had no 

‘‘reasoned explanation’’ for making the 

change and that applying the concept of 

‘‘commenced construction’’ to a 

relocated compressor is contrary to the 

plain language of the CAA. 

Response: The EPA traditionally 

defines the term ‘‘commence 

construction,’’ as it applies to an 

equipment, to mean the time an owner 

or operator has entered into a 

contractual obligation to acquire the 

equipment. This is reflected in the 

definition of ‘‘commenced’’ in the 

General Provisions at 40 CFR 60.2, as 

well as in the relevant NSPS (see, e.g., 

40 CFR 60.4230(a) of subpart JJJJ). We, 

therefore, agree with the commenters 

that our proposed definition of 

‘‘commence construction’’ in 40 CFR 

60.5365(b) and 40 CFR 60.5365(c) as the 

time of installation is a deviation from 

our traditional view. Upon reviewing 

the comments and re-evaluating the 

proposed definition, we conclude that 

there is no discernible difference 

between the compressors at issue and 

other equipment subject to NSPS that 

would make such deviation necessary or 

appropriate in this case. We have, 

therefore, removed these specific 

definitions of ‘‘commence construction’’ 

in 40 CFR 60.5365(b) and 40 CFR 

60.5365(c) in the final rule. 

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The NSPS also does not apply to 

relocated compressors. As provided in 

the NSPS General Provisions at 40 CFR 

60.14(e)(6), relocation of an existing 

facility is not modification. 

E. Major Comments Concerning Storage 

Vessels 

1. Applicability Threshold Metric 

Comment: Numerous commenters 

objected to the EPA’s proposed use of 

liquid throughput to determine which 

storage vessels should be subject to the 

standards, asserting that the high 

variability in volatility of stored liquids 

and other parameters affecting 

emissions makes throughput a poor 

indicator of VOC emissions. The 

commenters indicate that, as a result, 

basing applicability on throughput 

would bring many storage vessels with 

low VOC emissions (some less than 1 

tpy) under the standard and the 

required emission controls would not be 

cost-effective. Some commenters point 

out that certain storage vessels with 

high emissions might not be subject to 

the standards based on throughput. 

Response: In its BSER analysis for 

storage vessels, the EPA estimated the 

VOC emissions for storage vessels with 

various levels of throughputs to 

determine the cost effectiveness of 

control. In that analysis, the EPA 

estimated that storage vessels with 

throughput rates of 1 barrel per day 

(bpd) of condensate or 20 bpd of crude 

oil are equivalent to VOC emissions of 

6 tpy and determined that control is cost 

effective for these storage vessels. The 

EPA agrees with the comments that 

throughput is not a good indicator of 

VOC emissions and, therefore, not 

appropriate for determining the 

standards’ applicability. However, the 

EPA has received no comment 

contesting the EPA’s conclusion that 

regulating storage vessels emitting 6 tpy 

or more of VOC is cost effective and 

appropriate (the basis of our proposed 

throughput limit). Accordingly, in the 

final rule, the storage vessels NSPS 

applies to those emitting 6 tpy or more 

of VOC. This change from proposal 

would ensure that controls will be 

required only on those storage vessels 

where they can be applied cost 

effectively. This approach also allows 

for broader coverage across all types of 

storage vessels, regardless of the fluid 

that is stored or where the storage vessel 

may be located. The final rule reflects 

this change and has established a VOC 

emissions threshold of 6 tpy for storage 

vessels to require control. Based on our 

revised cost analysis, we determined 

that storage vessels with VOC emissions 

equal to or greater than 6 tpy or greater 

were cost effective to control at $3,400/ 

ton of VOC. The final rule requires each 

facility to determine its own emission 

factor and calculate the estimated 

emissions from each storage vessel. 

2. Definition of Affected Facility 

Comment: Numerous commenters 

commented on the definition of storage 

vessel in 40 CFR part 60, subpart 

OOOO, calling for greater clarity and 

consistency and requesting that certain 

activities or equipment be included or 

excluded from the definition. 

Response: The EPA agrees with the 

commenters who assert that a more 

specific and consistent definition of a 

storage vessel is needed. The revised 

definition more clearly focuses on 

identifying which units are considered 

storage vessels under this subpart and 

which units are not and describes a 

storage vessel using terminology similar 

to that used in 40 CFR part 63, subpart 

HH. We believe it is important to be 

somewhat consistent in terminology 

because the NSPS and NESHAP both 

apply to the oil and natural production 

segment where these tanks are primarily 

located. We also removed the emissions 

threshold from the definition and, 

instead, based the standard in 40 CFR 

60.5395 on the VOC emission rate of the 

storage vessel. In response to comments 

requesting clarification on whether 

mobile units are considered storage 

vessels, we have set a minimum amount 

of time (180 consecutive days) that the 

storage vessel must be stationed at the 

same site before it is subject to 40 CFR 

part 60, subpart OOOO. Our reasoning 

for setting this minimum amount of 

time is discussed in the response to 

comment immediately below. 

Additionally, we have not excluded 

wastewater storage vessels, as the NSPS 

requires control for all storage vessels 

emitting at least 6 tpy of VOC. Further, 

some wastewater tanks containing 

significant amounts of organic 

compounds could exceed VOC 

emissions of 6 tpy. Finally, the revised 

definition includes specific exemptions 

for process vessels and pressure vessels 

to clarify that these units are not 

considered storage vessels. Since the 

applicability of subpart OOOO, as 

finalized, is not based on throughput, 

we believe it is not necessary to specify 

which types of stored materials are 

regulated and which are not, as 

suggested by commenters. If a stored 

material is emitting at least 6 tpy of 

VOC, then the storage vessel will need 

to reduce its VOC emissions by 95 

percent. 

Comment: Some commenters assert 

that the EPA should limit applicability 

to storage vessels that are stationary and 

should clarify the meaning of 

‘‘stationary’’ to include or exclude 

certain types of storage vessels. 

Additionally, the EPA received 

comments requesting that the stationary 

aspect of the ‘‘storage vessel’’ definition 

should be consistent with other rules, 

while acknowledging the particular 

scenarios unique to the oil and gas 

production segment. The commenter 

notes that the stationary aspect of a 

storage vessel is typically addressed by 

the EPA in terms of whether it is 

reasonably portable, although the EPA 

sometimes addresses portability based 

on the size of the vessel. The commenter 

states that another criterion specified by 

the EPA in several regulations is that 

‘‘vessels permanently attached to motor 

vehicles’’ are not storage vessels, and 

the EPA has issued a determination that 

this exemption extends to storage 

vessels ‘‘equipped with a permanently 

attached wheel assembly and a truck 

hitch’’ (U.S. Environmental Protection 

Agency, letter from George T. Czerniak 

to Ken Comey, Flint Hills Resources 

L.P., September 2, 2004). According to 

the commenter, this renders most 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 

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 

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concerns. Another commenter similarly 

states that costly control requirements 

are not appropriate for temporary 

storage vessels (on site less than 180 

days). 

Response: Based on the commenter’s 

suggestion, the EPA has revised the 

definition of storage vessel to clarify 

that a storage vessel is subject to 40 CFR 

part 60, subpart OOOO if it remains on 

a given site for more than 180 

consecutive days. 

In general, we agree with the 

commenter’s discussion about the EPA’s 

past practices related to storage vessels. 

In particular, we agree that the inherent 

differences between ‘‘mobile’’ or 

temporary storage vessels in this source 

category and other categories indicate 

that they should be regulated 

differently. As mentioned in the 

previous response, there are many 

storage vessels in this source category 

that travel from site to site, so we did 

not feel it was appropriate to exclude all 

of these mobile storage vessels from 

control requirements. Many temporary 

storage vessels in this source category 

are typically bringing in material such 

as fracking fluid to well sites and can 

stay at a well site for up to several 

months in order to receive flowback. 

These storage vessels are considered to 

be an essential part of the drilling and 

production operation, more akin to how 

permanent storage vessels are utilized in 

the refining and organic chemical 

manufacturing sectors, rather than to 

conventional tank trucks that are 

typically excluded in other EPA rules. 

Therefore, we believe that 180 days is 

an appropriate period of time to 

establish a temporary tank as being 

subject to 40 CFR part 60, subpart 

OOOO, and, therefore, potentially 

required to install controls. 

3. References to MACT Standards 

Comment: The EPA received 

comment asserting that the outcome of 

its best demonstrated technology (BDT) 

analysis for proposed 40 CFR part 60, 

subpart OOOO was calculated to 

achieve the same level of control as 40 

CFR part 63, subpart HH—undermining 

the BDT determination and effectively 

(and unlawfully) extending subpart HH 

major source MACT requirements to 

area source storage vessels. 

As a result, the commenter asserts 

that the EPA’s analysis precludes other 

potentially relevant regulatory 

alternatives—such as marginally less 

effective controls that might be applied 

to a broader range of storage vessels. 

The commenter states that the EPA’s 

failure to consider other control 

techniques and other levels of control 

efficiency that might be achieved by its 

preferred techniques is arbitrary and 

capricious. 

Response: The commenter incorrectly 

asserts that the EPA’s NSPS for storage 

vessels was designed to achieve the 

same level of control as MACT in 40 

CFR part 63, subpart HH. In Portland 

Cement Assoc. v. EPA, 665 F.3d 177 

(D.C. Cir. 2011), the United States Court 

of Appeals for the District of Columbia 

Circuit rejected an argument that the 

EPA adopted NESHAP PM standards for 

NSPS, noting that the EPA arrived at the 

same limit for both NESHAP and NSPS 

using two different mechanisms. 

Similarly, in this case, although both the 

NESHAP and the NSPS require 95- 

percent control, the EPA established the 

two standards based on separate 

mechanisms. The EPA established the 

MACT standard in 1998 pursuant to 

section 112(d)(2) and (3) of the CAA. In 

contrast, the EPA established the NSPS 

based on BSER analysis under CAA 

section 111. The BSER analysis for 

storage vessels consists of the same 

steps as those for other affected sources 

evaluated in the proposed NSPS. 

Specifically, the EPA evaluated 

available information to identify VOC 

control options. The EPA then assessed 

various aspects of the control options, 

including their VOC reduction 

potentials, their cost effectiveness and 

secondary air impacts. The commenter 

did not claim that any part of the EPA’s 

BSER analysis above was inaccurate or 

inappropriate. For the reasons stated 

above, the commenter’s assertion is 

without support. 

The commenter also claims that the 

EPA only analyzed two controls and, 

therefore, failed to consider other 

‘‘potentially relevant regulatory 

alternatives.’’ However, the commenter 

did not identify any other control option 

for the EPA’s consideration. The 

commenter simply suggests that the 

EPA should consider some less effective 

controls, which the commenter claims 

would have led to greater coverage. 

Without more information, it is unclear 

whether a less effective control than that 

we have identified would, in fact, 

qualify as BSER for controlling VOC 

emissions from storage vessels or would 

have resulted in coverage of additional 

storage vessels. 

Comment: Two commenters state that 

the cost of the performance tests, 

monitoring, recordkeeping, etc., that are 

required through cross-references to 40 

CFR part 63, subpart HH were not 

adequately considered by the EPA in the 

cost-effectiveness determination for 40 

CFR part 60, subpart OOOO, which 

applies to dispersed locations that do 

not have electricity or automation, and 

have limited remote transmitting unit 

space. 

Response: The EPA does not take into 

account monitoring, recordkeeping and 

reporting costs in determining cost 

effectiveness of controls and in 

evaluating BSER. Based on this and 

other comments detailed in the response 

to comments for this final rulemaking, 

the EPA removed from 40 CFR part 60, 

subpart OOOO the citations to the 

requirements for performance tests, 

monitoring, recordkeeping, etc., in 40 

CFR part 63, subpart HH and 

incorporated these subpart HH 

requirements into subpart OOOO. 

During the incorporation process, we 

made minor revisions to the subpart HH 

requirements, as appropriate for subpart 

OOOO. For example, we removed 

references to glycol dehydrators and 

paragraphs listed as ‘‘reserved.’’ 

4. Availability of Control Equipment 

Comment: Some commenters believe 

that there will be a shortage of control 

equipment available to meet the 

proposed storage vessel requirements, 

and recommend revisions to the 

compliance deadline for storage vessels 

based on a variety of considerations, 

including the availability of control 

devices, lead time needed for 

manufacturer testing of their combustors 

to be compliant with the NSPS and time 

needed to install the compliant devices. 

Response: We agree that it will likely 

take some time beyond the 

promulgation date of the NSPS for 

combustor manufacturers to have 

control devices constructed, tested, 

documented and available for operators 

to install in efforts to comply with the 

storage vessel requirements of the NSPS. 

Under the final rule, operators are not 

required to conduct individual 

performance tests on combustors 

installed in the field if the combustor 

manufacturer tests and documents for 

the owner or operator that the model 

achieves a control efficiency of 95.0 

percent. The time required for testing 

and documentation is often longer than 

for a single model when manufacturers 

provide multiple models for varying 

applications based on capacity. We 

believe this testing and documentation 

program would require an ‘‘adjustment 

period’’ for manufacturers to be ready to 

supply the operators with the correct 

equipment they need. 

We considered whether it would be 

feasible for on-site testing to mitigate the 

shortage of manufacturer tested 

combustors. Although owners and 

operators can test their individual 

combustors in the field to determine 

combustor efficiency, such emissions 

testing is expensive and can only be 

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performed if testing consultants are 

available to conduct the testing. We 

believe that immediately after the 

effective date of the NSPS there will be 

a shortage of available testing 

consultants concurrent with the 

shortage of pre-tested combustor 

models. As a result, we conclude that 

on-site testing would not sufficiently 

mitigate the difficulty of owners and 

operators complying with the NSPS. 

We evaluated whether controls other 

than combustors would be available 

during this adjustment period. Although 

vapor recovery units (VRU) can provide 

95.0-percent control for storage vessels 

and are one means of meeting the 

storage vessel standards in the NSPS, 

VRU cannot be used in every situation. 

For example, storage vessels located 

remotely where there is no available 

electrical service may not be able to be 

controlled using VRU. In addition, 

storage vessels with low concentration 

emission streams or fluctuating 

emissions may not be amenable to 

control by VRU. Further, VRU 

installations would also require on-site 

testing, and owners and operators 

would be hampered by the same 

consultant shortage situation described 

above for combustors. 

In light of the above, we conclude that 

there is no BSER for storage vessel 

affected sources during the first year 

after promulgation, which we believe is 

appropriate for the adjustment period 

mentioned above. At the end of this 

adjustment period, we believe owners 

and operators should have no problem 

securing control devices that are 

manufacturer-tested and have 

appropriate documentation for 

determining control efficiency. 

Accordingly, the final rule provides for 

a 1-year phase-in beginning October 15, 

2012 before the 95.0-percent control 

requirement is effective. 

With regard to providing time for 

operators to establish the need for 

controls and install them where called 

for, the EPA agrees that some lag time 

may be needed after initial start-up for 

the owner or operator to determine the 

long-term production level of a well and 

to procure the appropriate control 

equipment. The EPA evaluated the 

approach taken in the Wyoming rules 

for new sources, which allows from 30 

to 90 days for a source to achieve 

compliance, depending on the area of 

the state. Wyoming allows only 30 days 

in ozone nonattainment areas, 60 days 

for concentrated development areas or 

90 days elsewhere in the state. The EPA 

believes that 60 days is a reasonable 

period for controlling new storage 

vessels at wells sites with no wells 

already in production. 

However, for replacement storage 

vessels or additional storage vessels at 

well sites with one or more wells 

already in production, we believe the 

operator already should have 

information on liquid composition and 

throughput. This information would 

allow estimation of VOC emissions to 

determine applicability of control 

requirements and for acquisition and 

installation of a control device 

concurrent with the replacement or 

additional storage vessel being installed. 

In the final rule, for storage vessels 

constructed, modified or reconstructed 

at well sites with no well already in 

production, we have provided for a 30- 

day period for throughput to stabilize 

and for the operator to estimate VOC 

emissions to determine whether a 

control device will be required. If VOC 

emissions are estimated to be at least 6 

tpy, the operator is provided an 

additional 30 days for the control device 

to become operational. We believe that 

the Wyoming experience illustrates that 

this will be sufficient time to size and 

obtain suitable controls. 

F. Major Comments Concerning 

Notification, Recordkeeping and 

Reporting Requirements 

1. 30-Day Notification and Annual 

Reports 

Comment: Multiple commenters state 

that the 30-day advance notification of 

well completions under 40 CFR 

60.5420(a) should be removed from the 

final rule. Commenters assert that this 

and notification requirements in 40 CFR 

60.7(a) are unduly burdensome and 

costly, not adequately explained, not 

related to verifying compliance with the 

proposed rule and could conflict with 

the need to protect proprietary business 

information. 

Multiple commenters also note that 

industry’s estimate of annual 

completions is several times higher than 

the EPA’s estimate of 20,000 

completions following fracturing and 

completions following refracturing 

annually. The commenters believe that 

these requirements will likely 

overwhelm both regulated entities and 

state regulators alike. Commenters offer 

suggestions, including requiring annual 

certifications or maintaining records 

available for inspection, reducing the 

proposed advance notification 

requirement to 5–10 days and 

considering notification programs such 

as those in Texas and Wyoming. 

Different commenters support or oppose 

requiring a 30-day advance notice with 

follow-up notification of 1–2 days 

before an impending completion. 

Several commenters suggest that the 

EPA should coordinate with state and 

local agencies to eliminate duplicative 

recordkeeping and reporting 

requirements, and that records of 

interest other than those submitted to 

the respective Oil and Gas Commissions 

should only be required to be retained 

and available upon inspection, similar 

to other permit requirements. 

Several commenters do not agree that 

an annual report under 40 CFR 

60.7(a)(1), 40 CFR 60.7(a)(3) and 40 CFR 

60.7(a)(4) adds any value for verifying 

compliance and the EPA should remove 

this requirement from the final rule. The 

commenters add that the best method 

for compliance is for an owner or 

operator to maintain necessary records 

and to have the records available for 

review during an on-site inspection. 

One commenter suggests the annual 

report should include for each type of 

affected facility (1) the total number of 

affected facilities at the site; (2) the 

number of facilities that became affected 

facilities during the reporting period; (3) 

the number of exempted facilities; and 

(4) the number of affected facilities with 

a non-compliance situation during the 

reporting period. One commenter 

suggests that it would be easier for 

facilities to submit an annual report on 

a set date each year, and multiple 

affected facilities could be included in 

a single report. Two commenters 

propose that all notifications for each 

year be delivered in a single annual 

report corresponding to the reporting 

period in which the affected facilities 

become subject to the rule. One 

commenter suggests that operators 

should be required to keep records at 

the nearest manned office, but reports 

should only be required if they are 

requested by the EPA. 

The commenters recommend, where 

feasible, streamlining the final 

notification and reporting requirements 

to eliminate unduly burdensome 

notification and reporting requirements. 

Response: The EPA agrees that certain 

notification, recordkeeping and 

reporting requirements in the General 

Provisions are unduly burdensome for 

the new affected facilities in this NSPS. 

For that reason, well completions, 

pneumatic controllers and storage 

vessels will be exempt from the 

notifications required by 40 CFR 

60.7(a)(1), (3) and (4). We agree that 

notifications of well completions should 

be as streamlined as possible to remove 

excess burden from both the owners and 

operators and regulatory agencies, as 

well. As a result, we have removed the 

30-day advance notification requirement 

and instead are requiring an advance 

notice via email to the EPA or delegated 

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authority no later than 2 days prior to 

completion. 

To avoid duplicative and potentially 

conflicting notification requirements 

and to relieve notification burden from 

owners and operators, we have added a 

provision in the final rule that, if an 

owner or operator has met the state 

requirements for advance notification of 

well completions, then the owner and 

operator are considered to have met the 

advance notification requirement for gas 

well completions under the NSPS. 

We also believe that the operator 

should be provided flexibility to use 

new technology to document 

compliance that would result in less 

paperwork burden on the part of the 

operators themselves and on regulators. 

To lessen the reporting burden, the final 

recordkeeping and reporting 

requirements for well completions also 

provide for a streamlining option that 

owners and operators may choose in 

lieu of the standard annual reporting 

requirements. The standard annual 

report must include copies of all well 

completion records for each gas well 

affected facility for which a completion 

operation was performed during the 

reporting period. The alternative, 

streamlined annual report for gas well 

affected facilities requires submission of 

a list, with identifying information of all 

affected gas wells completed, electronic 

or hard copy photographs documenting 

REC in progress for each well for which 

REC was required and the selfcertification required in the standard 

annual report. The operator retains a 

digital image of each REC in progress. 

The image must include a digital date 

stamp and geographic coordinates 

stamp to help link the photograph with 

the specific well completion operation. 

Operators are not required to take 

advantage of the optional recordkeeping 

and reporting approach, as some may 

choose to follow the standard reporting 

requirements. Under either approach, 

the report must include a record of all 

deviations during the reporting period 

in cases where well completion 

operations with hydraulic fracturing 

were not performed in compliance with 

the requirements for each gas well 

affected facility. 

Comment: One commenter requested 

that the EPA add a self-certification 

requirement to the annual report similar 

to that used in the title V program. The 

commenter recommended that the final 

rule require the annual report to include 

a statement signed by a senior official of 

the facility attesting to the truth, 

accuracy and completeness of the 

report. 

The commenter also requested that 

the EPA require that the annual reports 

be submitted electronically to facilitate 

making the reports publicly available. 

The commenter suggested using social 

media outlets, smart phone applications 

and other electronic means to make the 

annual reports readily available. 

Response: The EPA agrees that selfcertification is an important mechanism 

for assuring the public that the 

information submitted by each facility is 

accurate. In addition, the title V 

program has successfully employed selfcertification since its inception. 

Therefore, we are requiring selfcertification, based on requirements in 

the title V program, in the final rule. 

While we agree that having annual 

reports readily available to the public is 

a desirable goal, we did not identify any 

reporting programs or electronic 

databases that may be used for this 

purpose without significant 

modification. Therefore, we are not 

requiring annual reports to be submitted 

electronically, but we will continue to 

evaluate this option in the future. 

2. Duplicative Recordkeeping and 

Reporting Requirements 

Comment: Multiple commenters state 

that the notification, recordkeeping, 

monitoring and annual reporting 

requirements in the proposed NSPS are 

duplicative and extremely burdensome 

for operators and for state regulators 

with limited resources. The commenters 

make both general and specific 

recommendations to revise the reporting 

requirements in the final rule to 

eliminate duplication and reduce 

burden or better inform the public and 

regulatory agencies about deviations. 

Some commenters would eliminate all 

or some reports, while others argue that 

reporting is an essential compliance and 

enforcement mechanism and that 

additional information should be 

provided. Some commenters feel that an 

owner or operator should maintain 

necessary records and have them 

available for review. 

Commenters want the compliance 

assurance requirements to be 

appropriate for the oil and gas industry 

and commensurate to the environmental 

benefit that will be generated. For 

example, some commenters feel that the 

EPA should exempt small sources 

regulated under this rule from the 

notification and reporting requirements. 

Response: We have considered these 

and other related comments presented 

in the response to comments regarding 

the proposed reporting requirements. 

The EPA agrees that certain notification, 

recordkeeping and reporting 

requirements are unduly burdensome 

and believes it is important to minimize 

the burden of reporting requirements. 

However, as noted in several comments, 

states and other enforcement entities are 

confronting limited resources and 

visiting sites is not always practical and 

is particularly challenging in this 

industry. For that reason, the EPA 

believes notifications and reporting 

requirements are vital to ensure 

compliance with our regulations. 

Therefore, the EPA has evaluated the 

proposed notification, recordkeeping 

and reporting requirements in an effort 

to streamline the requirements to reduce 

burden on both industry and 

enforcement at the same time, assuring 

compliance with the NSPS. In the final 

rule, the EPA has removed or otherwise 

revised proposed reporting 

requirements that the EPA believes to be 

duplicative or unnecessary, including, 

but not limited to, those raised in the 

comments. These changes will 

streamline the reporting process and 

reduce the reporting burden on sources, 

including small sources. For example, 

as previously discussed, well 

completions and continuous bleed 

natural gas controllers are exempt from 

the notifications required by 40 CFR 

60.7(a)(1), 40 CFR 60.7(a)(3) and 40 CFR 

60.7(a)(4). In addition, the EPA has 

revised the rule language such that only 

continuous bleed natural gas controllers 

installed, modified or replaced during 

the reporting period are reported in the 

annual report. In addition, the EPA has 

revised the 30-day individual 

notification requirement for well 

completions, as discussed above. 

3. Electronic Reporting of Emissions 

Data 

Comment: Commenters suggest a 

variety of ways in which electronic 

reporting could be structured and 

implemented, with attention to 

coordination with various CAA 

requirements and programs to avoid 

duplicative and potentially burdensome 

requirements. Several commenters 

support electronic reporting of 

emissions data from all sources to be 

stored on existing EPA databases, such 

as the Electronic Greenhouse Gas 

Reporting Tool (e-GGRT) or added to the 

Toxics Release Inventory, and available 

to the public. These commenters believe 

that communities must have access to 

air quality information in order to 

protect public health. One commenter 

objects to the use of e-GGRT as a 

reporting mechanism in place of a 

state’s own tracking system, where the 

state has enforcement responsibility for 

the emissions date and tracking of 

sources subject to the proposed rule. 

The commenters also suggested a 

variety of ways in which electronic 

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49528 Federal Register / Vol. 77, No. 159 / Thursday, August 16, 2012 / Rules and Regulations 

reporting could be structured and 

implemented. 

Several commenters oppose the 

implementation of electronic reporting 

at this time and are concerned that an 

ERT will result in numerous 

complications and undue additional 

burden. The commenters point out that 

the EPA’s experience with e-GGRT 

indicates that considerable time and 

resources are needed to develop and 

implement efficient systems and to 

ensure that electronic reporting 

enhances efficiency rather than 

incurring additional burden on affected 

sources. The commenters state that a 

potential disadvantage associated with 

an ERT is that new and/or alternative 

test methods would not be in the 

system. In addition, the commenters 

believe that an ERT could be 

complicated and burdensome for 

smaller companies that lack 

environmental personnel or experience 

with electronic reporting under other 

rules. The commenters suggest that if 

the EPA delegates authority to states to 

implement and enforce the standards, 

some states may be unable or unwilling 

to accept electronic reports. The 

commenters urge the EPA to consider 

other more simplified options to report 

only the needed information. 

Response: While the EPA supports 

and encourages electronic reporting, 

after further consideration of all the 

comments, we do not believe the eGGRT is the appropriate mechanism for 

electronic reporting under this rule, as 

recommended by some commenters. 

The e-GGRT is not designed to accept 

all of the types of information required 

to be reported under the final rule, and 

significant modification of the system 

would be required to make it 

operational for this rule. 

However, the final rule does include 

reporting of performance test data via 

the ERT. The EPA must have 

performance test data to conduct 

effective reviews of CAA sections 112 

and 129 standards, as well as for many 

other purposes, including compliance 

determinations, emission factor 

development and annual emission rate 

determinations. In conducting these 

required reviews, the EPA has found it 

ineffective and time consuming, not 

only for us, but also for regulatory 

agencies and source owners and 

operators, to locate, collect and submit 

performance test data because of varied 

locations for data storage and varied 

data storage methods. In recent years, 

though, stack testing firms have 

typically collected performance test data 

in electronic format, making it possible 

to move to an electronic data submittal 

system that would increase the ease and 

efficiency of data submittal and improve 

data accessibility. 

In the final rule, as a step to increase 

the ease and efficiency of data submittal 

and improve data accessibility, the EPA 

is requiring the electronic submittal of 

select performance test data. Data entry 

will be through an electronic emissions 

test report structure called the ERT. The 

ERT will generate an electronic report 

which will be submitted using the 

CEDRI. The submitted report is 

submitted through the EPA’s CDX 

network for storage in the WebFIRE 

database making submittal of data very 

straightforward and easy. Webfire is the 

EPA’s online emissions factor 

repository, retrieval and development 

tool. The WebFIRE database is open to 

the public and contains the EPA’s 

recommended emissions factors for 

criteria and HAP for industrial and nonindustrial processes. Emissions data 

collected from the oil and natural gas 

sector, as well as many other sectors, 

will be used to update our emissions 

factors. The data will also be used by 

the EPA’s rule writers to make better 

informed decisions and learn more 

detailed information about emissions 

from sources. The electronic reporting 

requirement in this rule (and other 

NSPS/NESHAP rules) is only for test 

methods that are supported by the ERT. 

One major advantage of submitting 

performance test data through the ERT 

is a standardized method to compile 

and store much of the documentation 

required to be reported by this rule. 

Another advantage is that the ERT 

clearly states what testing information 

would be required. Another important 

benefit of submitting these data to the 

EPA at the time the source test is 

conducted is that it should substantially 

reduce the effort involved in data 

collection activities in the future. 

State, local and tribal agencies can 

also benefit from a more streamlined 

and accurate review of electronic data 

submitted to them. The ERT allows for 

an electronic review process rather than 

a manual data assessment making 

review and evaluation of the data and 

calculations easier and more efficient. 

Finally, another benefit of submitting 

data to WebFIRE electronically is that 

these data will greatly improve the 

overall quality of the existing and new 

emission factors by supplementing the 

pool of emissions test data for 

establishing emissions factors and by 

ensuring that the factors are more 

representative of current industry 

operational procedures. A common 

complaint heard from industry and 

regulators is that emission factors are 

outdated or not representative of a 

particular source category. With timely 

receipt and incorporation of data from 

most performance tests, the EPA will be 

able to ensure that emission factors, 

when updated, represent the most 

current range of operational practices. 

X. Summary of Significant NESHAP 

Comments and Responses 

For purposes of this document, the 

text within the comment summaries was 

provided by the commenter(s) and 

represents their opinion(s), regardless of 

whether the summary specifically 

indicates that the statement is from a 

commenter(s) (e.g., ‘‘The commenter 

states’’ or ‘‘The commenters assert’’). 

The comment summaries do not 

represent the EPA’s opinion unless the 

response to the comment specifically 

agrees with all or a portion of the 

comment. 

A. Major Comments Concerning 

Previously Unregulated Sources 

Comment: One commenter asserts 

that, although the EPA’s original MACT 

analysis covered all storage vessels, it 

issued a MACT standard at that time 

that applied to storage vessels with the 

PFE only. The commenter states that, 

while they support the EPA’s effort to 

correct this omission, the initial analysis 

for the tanks that the agency did 

regulate in 1999 was seriously flawed, 

and the proposed rule provides no 

justification for continuing to rely on a 

13-year old analysis to propose a MACT 

standard for an entirely new universe of 

storage vessel sources. Thus, according 

to the commenter, the EPA’s failure to 

properly calculate the MACT floor in 

setting the MACT standard for storage 

vessels violates CAA section 112(d)(2) 

and (3). 

The commenter states that, because 

this method has been found to be 

unlawful and substantially more data 

are available at this time, the EPA must 

now recalculate the MACT floor and 

MACT limits for tanks with the PFE. 

Cement Kiln Recycling Coalition, et. al. 

v. U.S. EPA, 255 F.3d 855, 863–64 (D.C. 

Cir. 2001). The commenter asserts that, 

in addition and partly as a consequence 

of its unlawful reliance on the prior 

standards, the EPA also has failed to 

fulfill the beyond-the-floor requirement 

of CAA section 112(d)(2). The 

commenter opines that, absent an up-todate analysis based on current emission 

controls, an appropriate beyond-thefloor 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 

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27Memorandum 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 

Continued 

limit based on the best-performing 

sources that currently exist. 

One commenter recommends that the 

EPA base its MACT floor analyses on 

emissions data from a representative 

population of small dehydrators that 

characterize the population of affected 

sources within the category or 

subcategory. The commenter reports 

that more current data sources may be 

available, such as dehydrator emissions 

data reported to state agencies in annual 

emission reports or in permit 

applications. 

One commenter opines that the EPA’s 

proposal misses the opportunity and 

fails to fulfill the agency’s responsibility 

to properly calculate the MACT for all 

sources in this sector based on current, 

reliable and representative emission test 

data. The commenter believes that, by 

relying on an incomplete and outdated 

dataset to set MACT floors and limits, 

the EPA has ignored data demonstrating 

trends in practices, processes and 

technologies and the resulting improved 

performance that CAA section 112(d) 

mandates. The commenter asserts that 

the EPA ignores the potential HAP 

emissions that the control devices 

themselves emit by failing to collect 

such emissions data from facilities that 

have installed control devices. The 

commenter argues that the EPA must 

collect the appropriate emission test 

data needed in order to recalculate and 

set a proper MACT for glycol 

dehydrators, storage vessels and 

equipment leaks. 

One commenter states that section 

112 of the CAA requires the EPA to set 

a NESHAP for each category or 

subcategory of ‘‘major sources’’ of HAP 

emissions. 42 U.S.C. 7412(d)(1). The 

commenter asserts that the EPA must set 

CAA section 112(d) emission standards 

based on ‘‘maximum achievable control 

technology’’ or ‘‘MACT.’’ The 

commenter states that the EPA largely 

bases its MACT proposal for small 

glycol dehydrators on emissions data 

collected from the industry during the 

development of the original MACT 

standards. 76 FR 52768. The commenter 

contends that the data were collected 

prior to 1997 and did not adequately 

represent the emissions profile at that 

time, and do not reflect the significant 

changes in the industry and other 

technological developments that have 

occurred during the past 13 years. 

According to the commenter, the EPA 

has not provided a reasoned explanation 

of how those data could be 

representative of currently operating 

glycol dehydrators and associated 

emission reductions, and how proposals 

based on those data can currently meet 

the MACT requirements for new and 

existing sources. The commenter states 

that the dehydrator technology 

performance in 1997 was not accurately 

reflected in the legacy EPA dataset and 

has advanced significantly in the past 

13 years. Consequently, according to the 

commenter, the EPA has not provided a 

reasoned explanation of how those data 

could be representative of currently 

operating glycol dehydrators and 

associated emission reductions, and 

how proposals based on those data can 

currently meet the MACT requirements 

for new and existing sources. The 

commenter believes this is critical 

because the 2005 NEI data reveal that 

improvements in the environmental 

performance of the category have 

progressed such that there are far more 

units in service with lower emissions 

than reflected in the 1997 data. 

One commenter states that the EPA 

did not collect recent data regarding 

emissions of HAP, including BTEX, 

from small glycol dehydrators in either 

source sector in support of this 

rulemaking. Instead, according to the 

commenter, the EPA appears to have 

relied on data collected in the prior 

MACT rulemaking, going back to 1998 

or prior. The commenter believes that 

the EPA’s analysis is flawed and 

questionable because it simply relies on 

the best-performing sources that existed 

a decade ago and fails to identify the 

best controlled sources today. The 

commenter contends that it is unlikely 

that these MACT standards reflect either 

the current best controlled similar 

source emissions or the average of the 

top 12 percent of the currently best 

controlled sources. The commenter 

states that, while the EPA appropriately 

proposes to set a MACT limit for these 

sources for the first time, the EPA’s use 

of out-dated data fails to demonstrate 

that its proposed limit is stringent 

enough in light of significant 

developments in emission control 

technologies and practices that have 

occurred since 1998. 

Response: One commenter argues that 

EPA has not satisfied sections 112(d)(2) 

and (3) of the CAA, because the MACT 

standards set in the 1999 rule have not 

been re-calculated using current data. 

To the extent the commenter is arguing 

that CAA section 112(d)(6) requires that 

the EPA recalculate the MACT 

standards set in 1999, based on current 

emissions test data, the commenter is 

incorrect. In NRDC v. EPA, 529 F.3d 

1077, 1084 (D.C. Cir. 2008), the District 

of Columbia Circuit held that it ‘‘[did] 

not think the words ‘review, and revise 

as necessary’ can be construed 

reasonably as imposing any such 

obligation’’ to re-calculate the MACT 

floors. NRDC v. EPA, 529 F.3d 1077, 

1084 (D.C. Cir. 2008). 

Moreover, in this action, we did not 

re-open the MACT standards in 40 CFR 

part 63, subpart HH for large glycol 

dehydrators, storage vessels with the 

PFE and equipment leaks for or in 40 

CFR part 63, subpart HHH for large 

glycol dehydrators. As such, the 

commenter’s request that we 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 

have been developments for equipment 

leaks. See Technology Review for the 

Final Amendments to Standards for the 

Oil and Natural Gas Production and 

Natural Gas Transmission and Storage 

Source Categories and responses on 

section 112(d)(6) comments below. We 

also conducted a CAA section 112(d)(6) 

technology review for subpart HHH and 

determined that there have been no 

developments in practices, processes or 

control technologies for large glycol 

dehydrators. Id. 

The remaining comments focus on the 

data the agency used to set the proposed 

MACT standards for small glycol 

dehydrators, which were left 

unregulated in the 1999 rule. The 

commenters claim that the data the EPA 

used to set the BTEX MACT standards 

for the small glycol dehydrators 

subcategory are outdated and that the 

EPA must collect new data. However, 

CAA section 112(d)(3) specifically 

provides that the Agency is to determine 

the average emission limit achieved by 

the best performing 12 percent of 

existing sources ‘‘(for which the 

Administrator has emissions 

information).’’ Thus, the EPA is not 

required to collect information if it 

determines that the information it has is 

sufficient for it to calculate the MACT 

standards consistent with the 

requirements of CAA section 112. 

Although the available emissions 

information is over a decade old, the 

available controls for reducing BTEX 

emissions from small glycol dehydrators 

and their control efficiencies have 

remained the same during this period, 

and the commenters have not provided 

any data to the contrary.27 We, 

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49530 Federal Register / Vol. 77, No. 159 / Thursday, August 16, 2012 / Rules and Regulations 

Gas Transmission and Storage Source Categories. 

Dated April 17, 2012. 

28Even 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. 

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 well-controlled glycol 

dehydrator at a well site with high inlet 

HAP content may have higher HAP 

emissions than a totally uncontrolled 

glycol dehydrator at a well site with a 

low inlet HAP content. Natural gas 

throughput also affects a glycol 

dehydrator’s overall emissions (i.e., low 

throughput units will tend to have 

lower overall emissions, and vice versa). 

For the reasons stated above, in addition 

to emissions, we need to consider the 

inlet HAP content and gas throughput of 

the small glycol dehydrators in order to 

properly identify the best performing 

sources and establish the MACT 

standard for this subcategory. However, 

information on natural gas throughput 

and inlet HAP content is not included 

in the NEI or any other readily available 

data source. Therefore, we used the 

1997 data which included such 

information for the small dehydrators. 

Comment: One commenter supports 

the EPA’s regulation of previously 

unregulated sources in the oil and 

natural gas sector and the commenter 

asserts that CAA sections 112(c) and 

112(k) (Urban Air Toxics Strategy) 

support their position regarding the 

regulation of previously unregulated 

sources. The commenter asserts that 

historical regulation of emission sources 

within the sector leaves a large number 

of dehydrators, storage vessels and 

equipment at gas processing plants 

unregulated. Additionally, the 

commenter states that historical 

regulation has also not limited 

emissions from a number of other 

emission sources (i.e., wells, pneumatic 

devices, compressor seals, valves, or 

flanges or other production equipment 

located at oil and gas production 

facilities or natural gas storage 

transmission facilities). 

One commenter supports the EPA’s 

recognition of the need to control 

emissions from previously uncontrolled 

emission points and commends the EPA 

on addressing small glycol dehydration 

units and storage vessels without the 

PFE. The commenters request that the 

EPA address all of the uncontrolled 

HAP emission points of which it is 

aware. 

Response: This rule establishes MACT 

standards for major sources of small 

glycol dehydrators that were left 

unregulated in the 1999 MACT rule. As 

explained further below, in several 

recent rulemakings, we have chosen to 

fix certain underlying defects in existing 

MACT standards under CAA sections 

112(d)(2) and (3), which are the 

provisions that directly govern the 

initial promulgation of MACT standards 

(see National Emission Standards for 

Hazardous Air Pollutants From 

Petroleum Refineries, October 28, 2009, 

74 FR 55670; and National Emission 

Standards for Hazardous Air Pollutants: 

Group I Polymers and Resins; Marine 

Tank Vessel Loading Operations; 

Pharmaceuticals Production; and the 

Printing and Publishing Industry, April 

21, 2011, 76 FR 22566). We believe that 

this approach is reasonable because 

using those provisions ensures that the 

process and considerations are those 

associated with initially establishing a 

MACT standard, and it is reasonable to 

make corrections following the process 

that would have been followed if we 

had not made an error at the time of the 

original promulgation. We appreciate 

the commenter’s support for regulating 

small glycol dehydrators. 

Although the agency had proposed 

MACT standards under CAA sections 

112(d)(2) and (3) for the subcategory of 

storage vessels without the PFE, we are 

not finalizing those standards here. 

Based on our review of the comments, 

we believe that we need additional data 

in order to set an emission standard for 

these vessels. We intend to collect the 

appropriate data and propose a MACT 

emission standard under CAA sections 

112(d)(2) and (3) of the CAA. 

The commenter identifies certain 

emission sources, other than small 

glycol dehydrators and storage vessels 

without the PFE (e.g., wells), that it 

alleges are uncontrolled. CAA section 

112(n)(4)(A) prohibits aggregation of 

emissions from any oil and gas 

exploration or production wells (with 

their associated equipment) in 

determining major source status or for 

any purpose under CAA section 112. In 

light of this prohibition on aggregation, 

and the fact that the sources identified 

by the commenter likely would not, if 

viewed alone, qualify as a major source, 

it is not clear whether emissions from 

the sources identified by the commenter 

can be addressed by a major source 

NESHAP.28

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-in1 million based on MACT allowable 

emissions. The commenter notes that 

since the EPA determined that these 

facilities had a cancer MIR greater than 

100-in-1 million based on MACT 

allowable emissions, the EPA 

determined that the risks are 

unacceptable for the Oil and Natural 

Gas Production MACT source category 

and additional regulation was needed. 

However, the commenter believes these 

results are entirely incorrect due to 

fundamental errors in the EPA’s 

calculations of MACT allowable risk for 

these two facilities. In addition, even if 

the analysis had been correct, the 

commenter states there are significant 

issues associated with the data for both 

of these facilities, which the commenter 

discusses in detail, that the commenter 

believes are sufficient to invalidate the 

results and the EPA’s conclusion that 

risks from the Oil and Natural Gas 

Production source category are 

unacceptable. 

Response: We have reviewed our risk 

results for the Oil and Natural Gas 

Production source category and agree 

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Federal Register / Vol. 77, No. 159 / Thursday, August 16, 2012 / Rules and Regulations 49531 

with the commenter that a number of 

errors were made in our analysis, 

including those noted by the 

commenter. As explained in VII.A.2 of 

this preamble, we have revised the risk 

assessment for this major source 

category to correct certain mistakes 

made in the analysis supporting the 

proposed rule. 

Based on our revised risk assessment, 

in which we evaluated the risks that 

remain after promulgation of the 

original MACT standards, as well as the 

MACT standards for small glycol 

dehydrators established in this final 

rule, we have determined the risks for 

the Oil and Natural Gas Production 

major source category are acceptable 

and that the MACT standards (including 

those promulgated here for small glycol 

dehydrators) provide an ample margin 

of safety. Further, we are retaining the 

0.9 Mg/yr benzene compliance 

alternative, which we had proposed to 

remove based on our incorrect 

conclusion that this alternative was 

driving the risk for this major source 

category. 

Comment: One commenter states that 

the EPA bases the decision to eliminate 

the 0.9 Mg/yr benzene emission 

limitation for 40 CFR part 63, subpart 

HHH on two basic factors: (1) It would 

reduce the cancer MIR from 90-in-1 

million to 20-in-1 million, and (2) the 

cost effectiveness to comply with this 

option is reasonable. The commenter 

states that both of these conclusions are 

erroneous. 

First, the commenter states that 

removal of 0.9 Mg/yr benzene 

alternative does not reduce risk. The 

commenter states that the EPA’s own 

technical analysis indicates that 

removal of the 0.9 Mg/yr benzene 

alternative would have no effect on the 

MIR. 

Secondly, the commenter states that 

the EPA’s cost analysis is severely 

flawed. The commenter also states that 

the EPA noted at proposal, that the costeffectiveness associated with removing 

the 0.9 Mg/yr benzene compliance 

alternative for natural gas transmission 

and storage facilities was reasonable. 

However, the commenter explained that 

the cost estimates used by the EPA in 

the ample margin of safety 

determination are inadequate. 

According to the commenter, the EPA 

did not conduct any analysis using 

actual data. Rather, the commenter 

notes that the EPA used costs estimated 

for small dehydrators and made general 

assumptions to estimate an upper-end 

cost effectiveness for removing the 0.9 

Mg/yr benzene alternative limit for large 

dehydrators at natural gas transmission 

and storage facilities. The commenter 

believes that, in general, the emission 

reductions for dehydrators forced to 

switch from the 0.9 Mg/yr benzene 

alternative to 95-percent control would 

be considerably less than those achieved 

by small dehydrators. The commenter 

further notes that the cost-effectiveness 

calculated for small dehydrators is 

based on a 95-percent reduction from an 

uncontrolled baseline level. According 

to the commenter, if a large dehydrator 

has installed controls to meet the 0.9 

Mg/yr alternative benzene limitation, 

the cost effectiveness must be based on 

the incremental reduction between the 

existing controls and 95 percent. The 

commenter states that the EPA has 

provided no evidence that these 

incremental reductions would be greater 

than or equal to the 95-percent 

reductions that would be achieved for 

smaller dehydrators. In conclusion, the 

commenter states that the rationale used 

by the EPA in the preamble to support 

the removal of the 0.9 Mg/yr compliance 

alternative for dehydrators at natural gas 

transmission and storage facilities under 

section 112(f)(2) of the CAA is not 

supported by any of the background 

technical documentation and analyses. 

The commenter believes that the EPA 

has no basis under any other CAA 

authority for this action. 

Response: In response to comments, 

we re-examined our risk assessment for 

the Natural Gas Transmission and 

Storage source category and discovered 

a number of errors, which we have 

discussed in more detail in section 

VII.B.2 of this preamble. As explained 

in that section, we have revised the risk 

assessment for this major source 

category to correct the mistakes. Based 

on our revised risk assessment, in which 

we evaluated the risks that remain after 

promulgation of the original MACT 

standards, as well as the MACT 

standards for small glycol dehydrators 

in this final rule, we have determined 

that the risks for the Oil and Gas 

Transmission and Storage major source 

category are acceptable and that the 

MACT standards (including those 

promulgated here) provide an ample 

margin of safety. Further, we are 

retaining the 0.9 Mg/yr benzene 

compliance alternative, which we had 

proposed to remove based on our 

incorrect conclusion that it was driving 

the risk for this major source category. 

We agree with the commenter that 

removal of the 0.9 Mg/yr benzene 

compliance alternative does not reduce 

risks for this major source category. 

Because we are retaining this 

compliance alternative, we need not 

address the comment on the cost 

effectiveness of removing this 

alternative. 

C. Major Comments Concerning the 

Technology Review 

Comment: One commenter states that, 

in conducting an 8-year review, the EPA 

must ‘‘look back’’ at the earlier standard 

and ascertain whether: (1) The standard 

was adopted using procedures that 

comply with the law as it has come to 

be interpreted by the courts; (2) the EPA 

had sufficiently accurate and 

comprehensive data at the time of the 

initial standard setting respecting the 

emissions profile of the category and 

properly identified the best performing 

unit(s); and (3) the EPA had properly 

used the available data. 

The commenter states the EPA then 

must ‘‘look around’’ using currently 

available data and determine whether: 

(1) The emissions profile of the industry 

has changed in a way that would 

substantially affect the MACT floor 

calculations (the commenter adds that 

this includes consideration of any 

increase in the number of good 

performing units available for use in the 

existing source MACT floor calculation 

and in the performance of the best 

performing unit); (2) data gaps or 

uncertainties that affected the earlier 

decision have been resolved in the 

interim or can be resolved using new 

information available to the agency; (3) 

costs or other factors have changed in a 

way that would substantially affect the 

‘‘beyond-the-floor’’ determination; (4) 

the use of improved practices, processes 

or technologies (including 

improvements in the performance of 

existing technologies) has become more 

prevalent than at the time of the initial 

standard setting; or (5) whether newer 

regulatory requirements, work practices 

or emission limitations (including state 

and local jurisdiction air pollution 

standards and federal enforcement 

actions), which are more stringent than 

the existing CAA section 112(d) 

standard, have shown the achievement 

or achievability of greater emission 

reductions than the existing standard 

requires. 

Response: As explained in the 

preamble to the proposed rule, our 

technology review focused on the 

identification and evaluation of 

‘‘developments in practices, processes, 

and control technologies’’ since the 

promulgation of the MACT standards 

for the two oil and gas source categories 

at issue here. We first reviewed the 

available information. In this regard, we 

reviewed a variety of sources of data, 

including data obtained in subsequent 

air toxics rules to see if any practices, 

processes and control technologies 

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29See footnote 25. 

considered in these actions could be 

applied to emission sources in the 

source categories at issue here. We also 

consulted the EPA’s Reasonably 

Available Control Technology (RACT)/ 

Best Available Control Technology 

(BACT)/Lowest Achievable Emission 

Rate (LAER) Clearinghouse (RBLC) and 

the Natural Gas STAR program. At 

proposal, we explained that we consider 

any of the following to be a 

‘‘development’’: 

—Any add-on control technology or 

other equipment that was not 

identified and considered during 

MACT development; 

—Any improvements in add-on control 

technology or other equipment (that 

was identified and considered during 

MACT development) that could result 

in significant additional emission 

reduction; 

—Any work practice or operational 

procedure that was not identified and 

considered during MACT 

development; and 

—Any process change or pollution 

prevention alternative that could be 

broadly applied that was not 

identified and considered during 

MACT development. 

The commenter views CAA section 

112(d)(6) differently. It appears to argue 

that CAA section 112(d)(6) requires that 

the EPA recalculate the MACT based on 

current data and technology. The same 

argument was posed to the District of 

Columbia Circuit, and the Court ‘‘[did] 

not think that the words ‘review, and 

revise as necessary’ can be construed 

reasonably as imposing any such 

obligation.’’ NRDC v. EPA, 529 F.3d 

1077, 1084 (D.C. Cir. 2008). Thus, 

contrary to the commenter’s assertion, 

the EPA is not required pursuant to 

CAA section 112(d)(6) to re-calculate 

the floors it set in 1999. 

To the extent the commenter is 

arguing that CAA section 112(d)(6) 

mandates that the EPA correct any 

deficiency in an underlying MACT 

standard when it conducts the 

‘‘technology review’’ under that section, 

we disagree. We believe that CAA 

section 112 does not expressly address 

this issue, and the EPA has discretion in 

determining how to address a purported 

flaw in a promulgated standard. CAA 

section 112(d)(6) provides that the 

agency must review and revise ‘‘as 

necessary.’’ The ‘‘as necessary’’ 

language must be read in the context of 

the provision, which focuses on the 

review of developments that have 

occurred since the time of the original 

promulgation of the MACT standard 

and thus should not be read as a 

mandate to correct flaws that existed at 

the time of the original promulgation. 

In several recent rulemakings, we 

have chosen to fix underlying defects in 

existing MACT standards under CAA 

sections 112(d)(2) and (3), the 

provisions that directly govern the 

initial promulgation of MACT standards 

(see National Emission Standards for 

Hazardous Air Pollutants From 

Petroleum Refineries, October 28, 2009, 

74 FR 55670; and National Emission 

Standards for Hazardous Air Pollutants: 

Group I Polymers and Resins; Marine 

Tank Vessel Loading Operations; 

Pharmaceuticals Production; and the 

Printing and Publishing Industry, April 

21, 2011, 76 FR 22566). We believe that 

our approach is reasonable because 

using those provisions ensures that the 

process and considerations are those 

associated with initially establishing a 

MACT standard, and it is reasonable to 

make corrections following the process 

that would have been followed if we 

had not made an error at the time of the 

original promulgation. As explained 

elsewhere, we are not finalizing MACT 

standards for the subcategory of storage 

vessels without the PFE, which were 

unregulated in the 1999 rule, because 

after evaluating the available data and 

comments received, we believe that we 

need additional data in order to set an 

emission standard for these vessels. We 

are, however, finalizing MACT 

standards under CAA sections 112(d)(2) 

and (3) for the subcategory of small 

glycol dehydration units. 

With regard to our CAA section 

112(d)(6) review, we found no 

significant developments in practices, 

processes and control technologies for 

reducing emissions from large glycol 

dehydrators and storage vessels with 

PFE.29 Accordingly, we are not revising 

these standards under CAA section 

112(d)(6). 

The EPA also conducted a technology 

review evaluating various options for 

controlling HAP emissions from 

equipment leaks. As described in the 

proposed rule (76 FR 52784), we 

evaluated advancements in controlling 

this emissions source since the original 

standards were promulgated, including 

the emission reduction potential and 

associated cost-effectiveness of these 

advancements. As a result of our review, 

we revised the leak definition for valves 

at natural gas processing plants to 500 

ppm, thus, requiring the application of 

the LDAR requirement at this lower 

detection level. As discussed above, the 

commenter appears to be arguing that 

the EPA must redo the MACT floor and 

beyond-the-floor analysis under CAA 

sections 112(d)(2) and (3) within its 

CAA section 112(d)(6) technology 

review, which we disagree. 

Comment: One commenter states that 

the EPA’s technology review for storage 

vessel control technologies is limited 

and makes incorrect assumptions. The 

commenter contends that without 

further support, the public cannot 

understand and the EPA cannot justify 

its proposed decision; therefore, the 

EPA’s proposal is arbitrary and 

capricious. The commenter adds that 

the EPA must conduct an updated 

beyond-the-floor analysis for storage 

vessels, by determining the ‘‘maximum 

degree of reduction in emissions’’ that is 

achievable, as required under CAA 

section 112(d)(2). The commenter states 

that the proposed rule fails to provide 

any discussion of a beyond-the-floor 

determination for storage vessels. 

One commenter states that the EPA 

must examine advances in vapor 

recovery unit technology and reconsider 

floating roof technology for tanks 

containing liquids that do not have the 

PFE. The commenter contends that the 

EPA improperly rejected technology 

advances and developments in 

pollution prevention systems found in 

its own RBLC database and employed 

by its own Natural Gas STAR partners. 

Specifically, according to the 

commenter, the EPA failed to evaluate 

the performance achieved by systems 

that use thermal or catalytic oxidizers, 

either alone or in combination with 

condensers. According to the 

commenter, the EPA’s RBLC review 

identified a BACT determination for 

dehydrator efficiency of 98 percent. The 

commenter also urges the EPA to 

evaluate the use of combustion devices 

and vapor recovery units that capture 

vent steam from the tank and turn it into 

a saleable product by recompressing the 

hydrocarbon vapors. The commenter 

contends that the EPA rejects 

technology advances by asserting that 

those technologies were considered in 

the 1999 rulemaking, but fails to 

provide support for its decision in either 

the record of the 1999 rulemaking or the 

current record. The commenter 

contends that the EPA must provide a 

basis for its decisions and conclusions. 

Response: For the reasons discussed 

in the prior response, the EPA disagrees 

with the commenter’s assertion that it 

must re-do the MACT floor calculations, 

including the beyond-the-floor 

determination, for the standards that the 

agency set in 1999. As to the 

technologies identified by the 

commenter, they were in existence and 

considered by the EPA at the time the 

EPA promulgated the original MACT 

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30See footnote 25. 

31See EPA Legacy Docket A–94–04 MACT floor 

memos II–A–006 and –007. 

32See footnote 25. 

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. 

standards for storage vessels.30 31 In 

addition, we are not finalizing control 

requirements for storage vessels without 

the PFE, as described in section VII.A of 

this preamble. The record does not 

support the assertion that the 

technologies identified by the 

commenter have advanced in terms of 

HAP emission reduction or have 

become significantly more cost effective. 

As explained in the preamble to the 

proposed rule (76 FR 52785), we 

examined technologies that were similar 

to the cover and route emissions to a 

control device that the MACT floor 

requires and, thus, would not result in 

reductions beyond the existing MACT 

requirements. Further, evaluation of 

technologies in the RBLC did not 

produce any applicable practices, 

processes or control technologies that 

were not considered during the original 

MACT for storage vessels with flash 

emissions.32

D. Major Comments Concerning 

Notification, Recordkeeping and 

Reporting Requirements 

1. Annual Reports 

Comment: One commenter requested 

that the EPA add a self-certification 

requirement to the annual report similar 

to that used in the title V program. The 

commenter recommended that the final 

rule require the annual report to include 

a statement signed by a senior official of 

the facility attesting to the truth, 

accuracy and completeness of the 

report. 

The commenter also requested that 

the EPA require that the annual reports 

be submitted electronically to facilitate 

making the reports publicly available. 

The commenter suggested using social 

media outlets, smart phone applications 

and other electronic means to make the 

annual reports readily available. 

Response: The EPA agrees that selfcertification is an important mechanism 

for assuring the public that the 

information submitted by each facility is 

accurate. In addition, the title V 

program has successfully employed selfcertification for since its inception. 

Therefore, we are requiring selfcertification, based on requirements in 

the title V program, in the final rule. 

While we agree that having annual 

reports readily available to the public is 

a desirable goal, we did not identify any 

reporting programs or electronic 

databases that may be used for this 

purpose without significant 

modification. Therefore, we are not 

requiring annual reports to be submitted 

electronically, but we will continue to 

evaluate this option in the future. 

2. Electronic Reporting of Emissions 

Data 

Several commenters raised similar 

issues regarding reporting of emissions 

data under the NESHAP as under the 

NSPS, described supra, and our 

responses there apply equally here. 

Please see comments and responses in 

section IX.F.3 of this preamble. 

XI. What are the cost, environmental 

and economic impacts of the final 

NESHAP and NSPS amendments? 

A. What are the air impacts? 

For the oil and natural gas sector 

NESHAP and NSPS, we estimated the 

emission reductions that will occur due 

to the implementation of the final 

emission limits. The EPA estimated 

emission reductions based on the 

control technologies selected by the 

engineering analysis. These emission 

reductions associated with the final 

amendments to 40 CFR part 63, subpart 

HH and 40 CFR part 63, subpart HHH 

are based on the estimated population 

in 2008. Under the finalized limits for 

glycol dehydration units, we have 

estimated that the HAP emissions 

reductions will be 670 tons for existing 

units subject to the final emissions 

limits. 

For the NSPS, we estimated the 

emission reductions that will occur due 

to the implementation of the final 

emission limits. The EPA estimated 

emission reductions based on the 

control technologies selected by the 

engineering analysis. These emission 

reductions are based on the estimated 

population in 2015. 

The primary baseline used for the 

impacts analysis of our NSPS for 

completions of hydraulically fractured 

natural gas wells takes into account REC 

conducted pursuant to state regulations 

covering these operations and estimates 

of REC performed voluntarily. To 

account for REC performed in regulated 

states, the EPA subsumed emissions 

reductions and compliance costs in 

states where these completion-related 

emissions are already controlled into 

the baseline. Additionally, based on 

public comments and reports to the 

EPA’s Natural Gas STAR program, the 

EPA recognizes that some producers 

conduct well completions using REC 

techniques voluntarily for economic 

and/or environmental objectives as a 

normal part of business. To account for 

emissions reductions and costs arising 

from voluntary implementation of 

pollution controls, the EPA used 

information on total emission 

reductions reported to the EPA by 

partners of the EPA Natural Gas STAR. 

This estimate of this voluntary REC 

activity in the absence of regulation is 

also included in the baseline.33 More 

detailed discussion on the derivation of 

the baseline is presented in a technical 

memorandum in the docket, as well as 

in the Regulatory Impact Analysis (RIA). 

Additionally, in the RIA, we provide 

summary-level estimates of emissions 

reductions and engineering compliance 

costs for a case where no voluntary REC 

are assumed to occur. This alternative 

case is presented in order to show 

impacts if conditions were such that 

REC were no longer performed on a 

voluntary basis, but, rather, were 

compelled by the regulation, and serves, 

in part, to capture the inherent 

uncertainty in projecting voluntary 

activity into the future. As such, this 

alternative case establishes the full 

universe of emissions reductions that 

are guaranteed by this NSPS (those that 

are required to occur under the rule, 

including those that would likely occur 

voluntarily). While the primary baseline 

may better represent actual costs (and 

emissions reductions) beyond those 

already expected under business as 

usual, the alternative case better 

captures the full amount of emissions 

reductions where the NSPS acts as a 

backstop to ensure that emission 

reduction practices occur (practices 

covered by this rule). 

Under the final NSPS, we have 

estimated that the emissions reductions 

to be about 190,000 tons VOC affected 

facilities subject to the NSPS. The NSPS 

is also expected to concurrently reduce 

1.0 million tons methane and 11,000 

tons HAP. We estimate that direct 

reductions in HAP, methane and VOC 

for the final rules combined total about 

12,000 tons, 1.0 million tons and 

190,000 tons, respectively. If voluntary 

action is not deducted from the NSPS 

baseline, the emissions reductions 

achieved by the final NSPS in HAP, 

methane and VOC are estimated at 

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49534 Federal Register / Vol. 77, No. 159 / Thursday, August 16, 2012 / Rules and Regulations 

about 19,000 tons, 1.7 million tons and 

290,000 tons, respectively. 

The EPA received several comments 

regarding the emission factor selected to 

calculate whole gas emissions (and the 

associated VOC emissions) from 

hydraulically fractured well 

completions. Comments focused on the 

data behind the emission factor, what 

the emission factor is intended to 

represent and the procedures used to 

develop the emission factor from the 

selected data sets. We reviewed all 

information received and have decided 

to retain the data set and the analysis 

conducted to develop the emission 

factor of 9,000 thousand cubic feet (Mcf) 

per completion. More detailed 

discussion is presented in a technical 

memorandum on this subject in the 

docket. 

B. What are the energy impacts? 

Energy impacts in this section are 

those energy requirements associated 

with the operation of emission control 

devices. Potential impacts on the 

national energy economy from the rule 

are discussed in the economic impacts 

section. There would be little national 

energy demand increase from the 

operation of any of the environmental 

controls analyzed under the final 

NESHAP amendments and final NSPS. 

The final NESHAP amendments and 

final NSPS encourage the use of 

emission controls that recover 

hydrocarbon products, such as methane 

and condensate that can be used on-site 

as fuel or reprocessed within the 

production process for sale. We 

estimated that the final standards will 

result in net annual costs savings of 

about $11 million (in 2008 dollars) due 

to the recovery of salable natural gas 

and condensate. Thus, the final 

standards have a positive impact 

associated with the recovery of 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. 

The estimated total capital cost to 

comply with the final NSPS is 

approximately $25 million in 2008 

dollars. The total estimated net annual 

cost to industry to comply with the final 

NSPS is estimated to be approximately 

$170 million in 2008 dollars. This 

annual cost estimate includes: (1) The 

cost of capital, (2) operating and 

maintenance costs and (3) the cost of 

MIRR. This estimated annual cost does 

not take into account any producer 

revenues associated with the recovery of 

salable natural gas and hydrocarbon 

condensates. 

When revenues from additional 

product recovery are considered, the 

final NSPS is estimated to result in a net 

annual engineering cost savings overall. 

When including the additional natural 

gas recovery in the engineering cost 

analysis, we assume that producers are 

paid $4/Mcf for the recovered gas at the 

wellhead. The engineering analysis cost 

analysis assumes the value of recovered 

condensate is $70 per barrel. Based on 

the engineering analysis, about 43 

million Mcf (43 billion cubic feet) of 

natural gas and 160,000 barrels of 

condensate are estimated to be 

recovered by control requirements in 

2015. Using the price assumptions, the 

estimated revenues from natural gas and 

condensate recovery are approximately 

$180 million in 2008 dollars. 

Using the engineering cost estimates, 

estimated natural gas product recovery 

and natural gas product price 

assumptions, the net annual engineering 

cost savings is estimated for the final 

NSPS to be about $15 million. Totals 

may not sum due to independent 

rounding. 

If voluntary action is not deducted 

from the baseline, capital costs for the 

NSPS are estimated at $25 million and 

annualized costs without revenues from 

product recovery for the NSPS are 

estimated at $330 million. In this 

scenario, given the assumptions about 

product prices, estimated revenues from 

product recovery are $350 million, 

yielding an estimated cost of savings of 

about $22 million. 

As the price assumption is very 

influential on estimated annualized 

engineering costs, we performed a 

simple sensitivity analysis of the 

influence of the assumed wellhead price 

paid to natural gas producers on the 

overall engineering annualized costs 

estimate of the final NSPS. At $4.22/ 

Mcf, the price forecast reported in the 

2011 Annual Energy Outlook in 2008 

dollars, the annualized cost savings for 

the final NSPS are estimated at about 

$24 million. As indicated by this 

difference, the EPA has chosen a 

relatively conservative assumption 

(leading to an estimate of few savings 

and higher net costs) for the engineering 

costs analysis. The natural gas price at 

which the final NSPS breaks-even from 

an estimated engineering costs 

perspective is around $3.66/Mcf. A $1/ 

Mcf change in the wellhead natural gas 

price leads to a $43 million change in 

the annualized engineering costs of the 

final NSPS. Consequently, annualized 

engineering costs estimates would 

increase to about $29 million under a 

$3/Mcf price or decrease to about ¥$58 

million under a $5/Mcf price. For 

further details on this sensitivity 

analysis, please refer the RIA for this 

rulemaking located in the docket. 

D. What are the economic impacts? 

The analysis of energy system impacts 

EPA performed using the United States 

Department of Energy’s (DOE) National 

Energy Modeling System (NEMS) shows 

that domestic natural gas production is 

not likely to change in 2015 as a result 

of the final rules, the year used in the 

RIA to analyze impacts. Average natural 

gas prices are also not estimated to 

change in response to the final rules. 

Domestic crude oil production is not 

expected to change, while average crude 

oil prices are estimated to decrease 

slightly (about $0.01/barrel or about 

0.01 percent at the wellhead for onshore 

production in the lower 48 states). All 

prices are in 2008 dollars. The NEMSbased analysis estimates in the year of 

analysis, 2015, that net imports of 

natural gas and crude oil will not 

change. 

E. What are the benefits of this final 

rule? 

The final Oil and Natural Gas NSPS 

and NESHAP amendments are expected 

to result in significant reductions in 

existing emissions and prevent new 

emissions from expansions of the 

industry. These final rules combined are 

anticipated to reduce 12,000 tons of 

HAP, 190,000 tons of VOC (a precursor 

to both PM (2.5 microns and less) 

(PM2.5) and ozone formation) and 1.0 

million tons of methane (a GHG and a 

precursor to global ozone formation). 

These pollutants are associated with 

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Federal Register / Vol. 77, No. 159 / Thursday, August 16, 2012 / Rules and Regulations 49535 

34Previous 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-perton estimates provide useful context for the breakeven analysis, the geographic distribution of VOC 

emissions from the oil and gas sector are not 

consistent with emissions modeled in Fann, 

Fulcher, and Hubbell (2009). In addition, the 

benefit-per-ton estimates for VOC emission 

reductions in that study are derived from total VOC 

emissions across all sectors. Coupled with the larger 

uncertainties about the relationship between VOC 

emissions and PM2.5 and the highly localized nature 

of air quality responses associated with HAP and 

VOC reductions, these factors lead us to conclude 

that the available VOC benefit-per-ton estimates are 

not appropriate to calculate monetized benefits of 

these rules, even as a bounding exercise. 

35U.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. 

36U.S. EPA. RIA. National Ambient Air Quality 

Standards for Ozone. Office of Air Quality Planning 

and Standards, Research Triangle Park, NC. January 

2010. Available on the Internet at http:// 

www.epa.gov/ttn/ecas/regdata/RIAs/s1- 

supplemental_analysis_full.pdf. 

37U.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. 

38U.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. 

39U.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. 

40U.S. EPA. Greenhouse Gas Equivalency 

Calculator available at: http://www.epa.gov/ 

cleanenergy/energy-resources/calculator.html, 

accessed 04/09/12. 

substantial health effects, welfare effects 

and climate effects. 

With the data available, we are not 

able to provide credible health benefit 

estimates for the reduction in exposure 

to HAP, ozone and PM2.5 for these rules, 

due to the differences in the locations of 

oil and natural gas emission points 

relative to existing information and the 

highly localized nature of air quality 

responses associated with HAP and 

VOC reductions. This is not to imply 

that there are no benefits of the rules; 

rather, it is a reflection of the difficulties 

in modeling the direct and indirect 

impacts of the reductions in emissions 

for this industrial sector with the data 

currently available.34 In addition to 

health improvements, there will be 

improvements in visibility effects, 

ecosystem effects and climate effects, as 

well as additional product recovery. 

Although we do not have sufficient 

information or modeling available to 

provide quantitative estimates for this 

rulemaking, we include a qualitative 

assessment of the health effects 

associated with exposure to HAP, ozone 

and PM2.5 in the RIA for this rule. These 

qualitative effects are briefly 

summarized below, but for more 

detailed information, please refer to the 

RIA, which is available in the docket. 

One of the HAP of concern from the oil 

and natural gas sector is benzene, which 

is a known human carcinogen. VOC 

emissions are precursors to both PM2.5

and ozone formation. As documented in 

previous analyses (U.S. EPA, 2006 35

and U.S. EPA, 2010 36), exposure to 

PM2.5 and ozone is associated with 

significant public health effects. PM2.5 is 

associated with health effects, including 

premature mortality for adults and 

infants, cardiovascular morbidity such 

as heart attacks, and respiratory 

morbidity such as asthma attacks, acute 

and chronic bronchitis, hospital 

admissions and emergency room visits, 

work loss days, restricted activity days 

and respiratory symptoms, as well as 

visibility impairment.37 Ozone is 

associated with health effects, including 

hospital and emergency department 

visits, school loss days and premature 

mortality, as well as injury to vegetation 

and climate effects.38

In addition to the improvements in air 

quality and resulting benefits to human 

health and non-climate welfare effects 

previously discussed, this rule is 

expected to result in significant climate 

co-benefits due to anticipated methane 

reductions. Methane is a potent GHG 

that, once emitted into the atmosphere, 

absorbs terrestrial infrared radiation, 

which contributes to increased global 

warming and continuing climate 

change. Methane reacts in the 

atmosphere to form ozone and ozone 

also impacts global temperatures. 

According to the Intergovernmental 

Panel on Climate Change (IPCC) 4th 

Assessment Report (2007), methane is 

the second leading long-lived climate 

forcer after CO2 globally. Total methane 

emissions from the oil and gas industry 

represent about 40 percent of the total 

methane emissions from all sources and 

account for about 5 percent of all CO2e 

emissions in the United States, with 

natural gas systems being the single 

largest contributor to United States 

anthropogenic methane emissions.39

Methane, in addition to other GHG 

emissions, contributes to warming of the 

atmosphere, which, over time, leads to 

increased air and ocean temperatures, 

changes in precipitation patterns, 

melting and thawing of global glaciers 

and ice, increasingly severe weather 

events, such as hurricanes of greater 

intensity and sea level rise, among other 

impacts. 

This rulemaking requires emission 

control technologies and regulatory 

alternatives that will significantly 

decrease HAP and VOC emissions from 

the oil and natural gas sector in the 

United States. As a co-benefit, the 

emission control measures the industry 

will use to reduce HAP and VOC 

emissions will also decrease methane 

emissions. The NESHAP Amendments 

and the NSPS combined are expected to 

reduce methane emissions annually by 

about 1.0 million short tons or about 19 

million metric tons CO2e. After 

considering the secondary impacts of 

this rule as previously discussed, such 

as increased CO2 emissions from well 

completion combustion and decreased 

CO2e emissions because of fuelswitching by consumers, the methane 

reductions become about 18 million 

metric tons CO2e. The methane 

reductions represent about 7 percent of 

the baseline methane emissions for this 

sector reported in the EPA’s U.S. 

Greenhouse Gas Inventory Report for 

2009 (251.55 million metric tons CO2e 

when petroleum refineries and 

petroleum transportation are excluded 

because these sources are not examined 

in this proposal). However, it is 

important to note that the emission 

reductions are based upon predicted 

activities in 2015; the EPA did not 

forecast sector-level emissions in 2015 

for this rulemaking. These emission 

reductions equate to the climate benefits 

of taking approximately 4 million 

typical passenger cars off the road or 

eliminating electricity use from about 2 

million typical homes each year.40

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 

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49536 Federal Register / Vol. 77, No. 159 / Thursday, August 16, 2012 / Rules and Regulations 

41 Interagency Working Group on Social Cost of 

Carbon (IWGSC). 2010. Technical Support 

Document: Social Cost of Carbon for Regulatory 

Impact Analysis Under Executive Order 12866. 

Docket ID EPA–HQ–OAR–2009–0472–114577. 

http://www.epa.gov/otaq/climate/regulations/scctsd.pdf, accessed 02/12/12. 

42The 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. 

43Marten 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. 

44Fann, 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. 

a given year (or from the alternative 

perspective, the benefit to society of 

reducing CO2 emissions by 1 ton). For 

more information about the social cost 

of carbon, see the Support Document: 

Social Cost of Carbon for Regulatory 

Impact Analysis Under Executive Order 

12866.41 Applying this approach to the 

methane reductions estimated for the 

NESHAP Amendments and NSPS, the 

2015 climate co-benefits vary by 

discount rate and range from about $100 

million to approximately $1.3 billion; 

the mean social cost of carbon at the 3- 

percent discount rate results in an 

estimate of about $440 million in 

2015.42

These co-benefits equate to a range of 

approximately $110 to $1,400 per short 

ton of methane reduced, depending 

upon the discount rate assumed with a 

per ton estimate of $480 at the 3-percent 

discount rate. These social cost of 

methane benefit estimates are not the 

same as would be derived from direct 

computations (using the integrated 

assessment models employed to develop 

the Interagency Social Cost of Carbon 

estimates) for a variety of reasons, 

including the shorter atmospheric 

lifetime of methane relative to CO2

(about 12 years compared to CO2 whose 

concentrations in the atmosphere decay 

on timescales of decades to millennia). 

The climate impacts also differ between 

the pollutants for reasons other than the 

radiative forcing profiles and 

atmospheric lifetimes of these gases. 

Methane is a precursor to ozone and 

ozone is a short-lived climate forcer that 

contributes to global warming. The use 

of the IPCC Second Assessment Report 

GWP to approximate co-benefits may 

underestimate the direct radiative 

forcing benefits of reduced ozone levels 

and does not capture any secondary 

climate co-benefits involved with 

ozone-ecosystem interactions. In 

addition, a recent the EPA National 

Center of Environmental Economics 

working paper suggests that this quick 

‘‘GWP approach’’ to benefits estimation 

will likely understate the climate 

benefits of methane reductions in most 

cases.43 This conclusion is reached 

using the 100-year GWP for methane of 

25 as put forth in the IPCC Fourth 

Assessment Report (AR 4), as opposed 

to the lower value of 21 used in this 

analysis. Using the higher GWP estimate 

of 25 would increase these reported 

methane climate co-benefit estimates by 

about 19 percent. Although the IPCC 

Assessment Report (AR4) suggested a 

GWP of 25 for methane, the EPA has 

used the GWP of 21 from the IPCC 

Second Assessment Report to estimate 

the methane climate co-benefits for this 

oil and gas rule. The EPA uses the 21 

GWP in order to provide estimates more 

consistent with global GHG inventories, 

which currently use GWP from the IPCC 

Second Assessment Report, and with 

the US GHG Reporting program. See the 

Regulatory Impact Analysis for further 

details. 

Due to the uncertainties involved 

with the ‘‘GWP approach’’ estimates 

presented and methane climate cobenefits estimates available in the 

literature, the EPA chooses not to 

compare these co-benefit estimates to 

the costs of the rule for this proposal. 

Rather, the EPA presents the ‘‘GWP 

approach’’ climate co-benefit estimates 

as an interim method to produce these 

estimates until the Interagency Social 

Cost of Carbon Work Group develops 

values for non-CO2 GHG. 

For the final NESHAP amendments, a 

break-even analysis suggests that HAP 

emissions would need to be valued at 

$5,200 per ton for the benefits to exceed 

the costs if the health, ecosystem and 

climate benefits from the reductions in 

VOC and methane emissions are 

assumed to be zero. Even though 

emission reductions of VOC and 

methane are co-benefits for the final 

NESHAP amendments, they are 

legitimate components of the total 

benefit-cost comparison. If we assume 

the health benefits from HAP emission 

reductions are zero, the VOC emissions 

would need to be valued at $2,900 per 

ton or the methane emissions would 

need to be valued at $8,300 per ton for 

the co-benefits to exceed the costs. All 

estimates are in 2008 dollars. For the 

final NSPS, the revenue from additional 

product recovery exceeds the costs, 

which renders a break-even analysis 

unnecessary when these revenues are 

included in the analysis. Based on the 

methodology from Fann, Fulcher, and 

Hubbell (2009),44 ranges of benefit-perton 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 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. 

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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 Benefits 2 ............. N/A ................................................ N/A ................................................ N/A. 

Total Costs 3 ................................... ¥$15 million ................................. $3.5 million ................................... ¥$11 million. 

Net Benefits ................................... N/A ................................................ N/A ................................................ N/A. 

Non-monetized Benefits 4 .............. 11,000 tons of HAP ...................... 670 tons of HAP ........................... 12,000 tons of HAP. 

190,000 tons of VOC .................... 1,200 tons of VOC ........................ 190,000 tons of VOC. 

1.0 million tons of methane .......... 420 tons of methane .................... 1.0 million tons of methane. 

Health effects of HAP exposure. 

Health effects of PM2.5 and ozone exposure. 

Visibility impairment. 

Vegetation effects. 

Climate effects. 

1 All estimates are for the implementation year (2015). 2 While we expect that these avoided emissions will result in improvements in air quality and reductions in health effects associated with HAP, 

ozone, and particulate matter (PM) as well as climate effects associated with methane, we have determined that quantification of those benefits 

and co-benefits cannot be accomplished for this rule in a defensible way. This is not to imply that there are no benefits or co-benefits of the 

rules; rather, it is a reflection of the difficulties in modeling the direct and indirect impacts of the reductions in emissions for this industrial sector 

with the data currently available. 3 The engineering compliance costs are annualized using a 7-percent discount rate. The negative cost for the final NSPS reflects the inclusion 

of revenues from additional natural gas and hydrocarbon condensate recovery that are estimated as a result of the NSPS. Possible explanations 

for why there appear to be negative cost control technologies are discussed in the engineering costs analysis section in the RIA. 4 For the NSPS, reduced exposure to HAP and climate effects are co-benefits. For the NESHAP, reduced VOC emissions, PM2.5 and ozone 

exposure, visibility and vegetation effects and climate effects are co-benefits. The specific control technologies for the final NSPS are anticipated 

to have minor secondary disbenefits, including an increase of 1.1 million tons of carbon dioxide (CO2), 550 tons of nitrogen oxides (NOX), 19 

tons of PM, 3,000 tons of CO and 1,100 tons of total hydrocarbons (THC), as well as emission reductions associated with the energy system impacts. The specific control technologies for the NESHAP are anticipated to have minor secondary disbenefits, but the EPA was unable to estimate these secondary disbenefits. The net CO2-equivalent emission reductions are 18 million metric tons. 

B. Paperwork Reduction Act 

The information collection 

requirements in this rule have been 

submitted for approval to the Office of 

Management and Budget (OMB) under 

the Paperwork Reduction Act, 44 U.S.C. 

3501, et seq. The information collection 

requirements are not enforceable until 

OMB approves them. 

The ICR documents prepared by the 

EPA have been assigned EPA ICR 

numbers 2437.01, 2438.01, 2439.01 and 

2440.01. The information requirements 

are based on notification, recordkeeping 

and reporting requirements in the 

NESHAP General Provisions (40 CFR 

part 63, subpart A), which are 

mandatory for all operators subject to 

national emission standards. These 

recordkeeping and reporting 

requirements are specifically authorized 

by CAA section 114 (42 U.S.C. 7414). 

All information submitted to the EPA 

pursuant to the recordkeeping and 

reporting requirements for which a 

claim of confidentiality is made is 

safeguarded according to Agency 

policies set forth in 40 CFR part 2, 

subpart B. This final rule requires 

maintenance inspections of the control 

devices but would not require any 

notifications or reports beyond those 

required by the General Provisions. The 

recordkeeping requirements require 

only the specific information needed to 

determine compliance. 

When a malfunction occurs, sources 

must report them according to the 

applicable reporting requirements of 40 

CFR part 63, subpart HH or 40 CFR part 

63, subpart HHH. An affirmative 

defense to civil penalties for 

exceedances of emission limits that are 

caused by malfunctions is available to a 

source if it can demonstrate that certain 

criteria and requirements are satisfied. 

The criteria ensure that the affirmative 

defense is available only where the 

event that causes an exceedance of the 

emission limit meets the narrow 

definition of malfunction in 40 CFR 63.2 

(sudden, infrequent, not reasonable 

preventable, and not caused by poor 

maintenance and/or careless operation) 

and where the source took necessary 

actions to minimize emissions. In 

addition, the source must meet certain 

notification and reporting requirements. 

For example, the source must prepare a 

written root cause analysis and submit 

a written report to the Administrator 

documenting that it has met the 

conditions and requirements for 

assertion of the affirmative defense. 

For this rule, the EPA is adding 

affirmative defense to the estimate of 

burden in the ICR. To provide the 

public with an estimate of the relative 

magnitude of the burden associated 

with an assertion of the affirmative 

defense position adopted by a source, 

the EPA has provided administrative 

adjustments to this ICR that shows what 

the notification, recordkeeping and 

reporting requirements associated with 

the assertion of the affirmative defense 

might entail. The EPA’s estimate for the 

required notification, reports, and 

records, including the root cause 

analysis, associated with a single 

incident totals approximately totals 

$3,141 and is based on the time and 

effort required of a source to review 

relevant data, interview plant 

employees, and document the events 

surrounding a malfunction that has 

caused an exceedance of an emission 

limit. The estimate also includes time to 

produce and retain the record and 

reports for submission to the EPA. The 

EPA provides this illustrative estimate 

of this burden, because these costs are 

only incurred if there has been a 

violation, and a source chooses to take 

advantage of the affirmative defense. 

The EPA provides this illustrative 

estimate of this burden because these 

costs are only incurred if there has been 

a violation and a source chooses to take 

advantage of the affirmative defense. 

Given the variety of circumstances 

under which malfunctions could occur, 

as well as differences among sources’ 

operation and maintenance practices, 

we cannot reliably predict the severity 

and frequency of malfunction-related 

excess emissions events for a particular 

source. It is important to note that the 

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EPA has no basis currently for 

estimating the number of malfunctions 

that would qualify for an affirmative 

defense. Current historical records 

would be an inappropriate basis, as 

source owners or operators previously 

operated their facilities in recognition 

that they were exempt from the 

requirement to comply with emissions 

standards during malfunctions. Of the 

number of excess emissions events 

reported by source operators, only a 

small number would be expected to 

result from a malfunction (based on the 

definition above), and only a subset of 

excess emissions caused by 

malfunctions would result in the source 

choosing to assert the affirmative 

defense. Thus, we believe the number of 

instances in which source operators 

might be expected to avail themselves of 

the affirmative defense will be 

extremely small. 

For this reason, we estimate a total of 

39 such occurrences for all sources 

subject to 40 CFR part 63, subpart HH, 

a total of three such occurrences for all 

sources subject to 40 CFR part 63, 

subpart HHH, and a total of 6 such 

occurrences for all sources subject to 40 

CFR part 60, subparts KKK and LLL 

over the 3-year period covered by this 

ICR. We expect to gather information on 

such events in the future, and will 

revise this estimate as better information 

becomes available. 

The annual monitoring, reporting, and 

recordkeeping burden for this collection 

(averaged over the first 3 years after the 

effective date of the standards) is 

estimated to be $20.1 million. This 

includes 384,866 labor hours per year at 

a total labor cost of $19.5 million per 

year, and annualized capital costs of 

$0.36 million, and annual operating and 

maintenance costs of $0.20 million. This 

estimate includes initial and annual 

performance tests, semiannual excess 

emission reports, developing a 

monitoring plan, notifications and 

recordkeeping. All burden estimates are 

in 2008 dollars and represent the most 

cost-effective monitoring approach for 

affected facilities. Burden is defined at 

5 CFR 1320.3(b). 

An agency may not conduct or 

sponsor, and a person is not required to 

respond to, a collection of information 

unless it displays a currently valid OMB 

control number. The OMB control 

numbers for the EPA’s regulations in 40 

CFR are listed in 40 CFR part 9. When 

these ICR are approved by OMB, the 

agency will publish a technical 

amendment to 40 CFR part 9 in the 

Federal Register to display the OMB 

control numbers for the approved 

information collection requirements 

contained in the final rule. 

C. Regulatory Flexibility Act 

The Regulatory Flexibility Act 

generally requires an agency to prepare 

a regulatory flexibility analysis of any 

rule subject to notice and comment 

rulemaking requirements under the 

Administrative Procedure Act or any 

other statute, unless the agency certifies 

that the rule will not have a significant 

economic impact on a substantial 

number of small entities (SISNOSE). 

Small entities include small businesses, 

small organizations, and small 

governmental jurisdictions. For 

purposes of assessing the impact of this 

rule on small entities, a small entity is 

defined as: (1) A small business as 

defined by NAICS codes 211111, 

211112, 221210, 486110 and 486210; 

whose parent company has no more 

than 500 employees (or revenues of less 

than $7 million for firms that transport 

natural gas via pipeline); (2) a small 

governmental jurisdiction that is a 

government of a city, county, town, 

school district, or special district with a 

population of less than 50,000; and (3) 

a small organization that is any not-forprofit enterprise which is independently 

owned and operated and is not 

dominant in its field. 

For the final NSPS, the EPA 

performed an analysis for impacts on a 

sample of expected affected small 

entities by comparing compliance costs 

to entity revenues. The baseline used in 

this analysis takes into account REC 

conducted pursuant to state regulations 

covering these operations and estimates 

of REC performed voluntarily. To 

account for REC performed in regulated 

states, the EPA subsumed emissions 

reductions and compliance costs in 

states where these completion-related 

emissions are already controlled into 

the baseline. Additionally, based on 

public comments and reports to the 

EPA’s Natural Gas STAR program, the 

EPA recognizes that some producers 

conduct well completions using REC 

techniques voluntarily for economic 

and/or environmental objectives as a 

normal part of business. To account for 

emissions reductions and costs arising 

from voluntary implementation of 

pollution controls, the EPA used 

information on total emission 

reductions reported to the EPA by 

partners of the EPA Natural Gas STAR. 

This estimate of this voluntary REC 

activity in the absence of regulation is 

also included in the baseline. More 

detailed discussion on the derivation of 

the baseline is presented in a technical 

memorandum in the docket, as well as 

in the RIA. 

Based upon the analysis in the RIA, 

which is in the Docket, when revenue 

from additional natural gas product 

recovered is not included, we estimate 

that 123 of the 127 small firms analyzed 

(97 percent) are likely to have impacts 

less than 1 percent in terms of the ratio 

of annualized compliance costs to 

revenues. Meanwhile, four firms (3 

percent) are likely to have impacts 

greater than 1 percent. Three of these 

four firms are likely to have impacts 

greater than 3 percent. However, when 

revenue from additional natural gas 

product recovery is included, we 

estimate that none of the analyzed firms 

will have an impact greater than 1 

percent. 

For the final NESHAP amendments, 

we estimate that 11 of the 35 firms (31 

percent) that own potentially affected 

facilities are small entities. The EPA 

performed an analysis for impacts on all 

expected affected small entities by 

comparing compliance costs to entity 

revenues. Among the small firms, none 

are likely to have impacts greater than 

1 percent in terms of the ratio of 

annualized compliance costs to 

revenues. 

After considering the economic 

impact of the combined NSPS and 

NESHAP amendments on small entities, 

I certify this action will not have a 

significant impact on a substantial 

number of small entities (SISNOSE). 

While both the NSPS and NESHAP 

amendment would individually result 

in a no SISNOSE finding, the EPA 

performed an additional analysis in 

order to certify the rule in its entirety. 

This analysis compared compliance 

costs to entity revenues for the total of 

all the entities affected by the NESHAP 

amendments and the sample of entities 

analyzed for the NSPS. When revenues 

from additional natural gas product 

sales are not included, 132 of the 136 

small firms (97 percent) in the sample 

are likely to have impacts of less than 

1 percent in terms of the ratio of 

annualized compliance costs to 

revenues. Meanwhile, four firms (3 

percent) are likely to have impacts 

greater than 1 percent. Three of these 

four firms are likely to have impacts 

greater than 3 percent. When revenues 

from additional natural gas product 

sales are included, none of the 136 

small firms (100 percent) are likely to 

have impacts greater than 1 percent. 

Our determination is informed by the 

fact that many affected firms are 

expected to receive revenues from the 

additional natural gas and condensate 

recovery engendered by the 

implementation of the controls 

evaluated in this RIA. As much of the 

additional natural gas recovery is 

estimated to arise from completionrelated activities, we expect the impact 

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on well-related compliance costs to be 

significantly mitigated. This conclusion 

is enhanced because the returns to REC 

activities occur without a significant 

time lag between implementing the 

control and obtaining the recovered 

product, unlike many control options 

where the emissions reductions 

accumulate over long periods of time; 

the reduced emission completions occur 

over a short span of time, during which 

the additional product recovery is also 

accomplished and payments for 

recovered products are settled. 

Although this final rule will not 

impact a substantial number of small 

entities, the EPA, nonetheless, has tried 

to reduce the impact of this rule on 

small entities by setting the final 

emissions limits at the MACT floor, the 

least stringent level allowed by law. 

D. Unfunded Mandates Reform Act 

This final action does not contain a 

federal mandate under the provisions of 

Title II of the Unfunded Mandates 

Reform Act of 1995 (UMRA), 2 U.S.C. 

1531–1538 for state, local, and tribal 

governments, in the aggregate, or to the 

private sector. The action would not 

result in expenditures of $100 million or 

more for state, local, and tribal 

governments, in the aggregate, or to the 

private sector in any 1 year. Thus, this 

final rule is not subject to the 

requirements of sections 202 or 205 of 

UMRA. 

This final rule is also not subject to 

the requirements of section 203 of 

UMRA because it contains no regulatory 

requirements that might significantly or 

uniquely affect small governments 

because it contains no requirements that 

apply to such governments nor does it 

impose obligations upon them. 

E. Executive Order 13132: Federalism 

This action does not have federalism 

implications. It will not have substantial 

direct effects on the states, on the 

relationship between the national 

government and the states, or on the 

distribution of power and 

responsibilities among the various 

levels of government, as specified in 

Executive Order 13132. These final 

rules primarily affect private industry, 

and do not impose significant economic 

costs on state or local governments. On 

the contrary, we believe the 

modification provisions discussed in 

section IX.A for well completions 

conducted at gas wells constructed on 

or before August 23, 2011, will reduce 

permitting burden borne by the States. 

These provisions will result in fewer 

sources becoming affected facilities 

under the NSPS while achieving 

emission reductions beginning October 

15, 2012 equal to those achieved by new 

sources beginning January 1, 2015. 

Thus, Executive Order 13132 does not 

apply to this action. 

F. Executive Order 13175: Consultation 

and Coordination With Indian Tribal 

Governments 

Subject to the Executive Order 13175 

(65 FR 67249, November 9, 2000) the 

EPA may not issue a regulation that has 

tribal implications, that imposes 

substantial direct compliance costs, and 

that is not required by statute, unless 

the Federal government provides the 

funds necessary to pay the direct 

compliance costs incurred by tribal 

governments, or the EPA consults with 

tribal officials early in the process of 

developing the proposed regulation and 

develops a tribal summary impact 

statement. 

The EPA has concluded that this 

action will not have tribal implications 

because it doesn’t impose a significant 

cost to the tribal government. However, 

there are significant tribal interests 

because of the growth of the oil and gas 

production industry in Indian country. 

The EPA initiated a consultation 

process with tribal officials early in the 

process of developing this regulation to 

permit them to have meaningful and 

timely input into its development. 

During the consultation process, the 

EPA conducted outreach and 

information meetings prior to the 

proposal in 2010. The EPA met with the 

Inter Tribal Environmental Council, 

which include many of the Region VI 

tribes, The Tribal leadership summit in 

Region X, and Tribal Energy Conference 

hosted by Ft. Belknap, and the National 

Tribal Forum. 

After the proposal was published, 

letters were sent to all tribal leaders 

offering to consult on a government-togovernment basis on the rule. As part of 

the consultation process and in 

response to these letters, an outreach 

call was held on October 12, 2011. 

Tribes that participated on this call 

were: Fond du Lac Band of Lake 

Superior Chippewa, Fort Belknap 

Indian Community, Forest County 

Potawatomi Community, Southern Ute 

Indian Tribe, and Pueblo of Santa Clara. 

In this meeting the tribes were 

presented the information in the 

proposal. The tribes asked general 

clarifying questions but did not provide 

specific comments. Comments on the 

proposal were received from an affiliate 

of the Southern Ute Indian Tribe. The 

commenter expressed concern about the 

impacts of the rule on natural gas and 

oil production operations on the 

Southern Ute Indian reservation and 

requested additional time to evaluate 

the impacts. In response to this and 

other requests, the comment period was 

extended. More specific comments can 

be found in the docket. 

G. Executive Order 13045: Protection of 

Children From Environmental Health 

Risks and Safety Risks 

This action is not subject to Executive 

Order 13045 (62 FR 19885, April 23, 

1997) because the Agency does not 

believe the environmental health risks 

or safety risks addressed by this action 

present a disproportionate risk to 

children. This action would not relax 

the control measures on existing 

regulated sources. The EPA’s risk 

assessments (included in the docket for 

this final rule) demonstrate that the 

existing regulations are associated with 

an acceptable level of risk and provide 

an ample margin of safety to protect 

public health. 

H. Executive Order 13211: Actions 

Concerning Regulations That 

Significantly Affect Energy Supply, 

Distribution, or Use 

This action is not a ‘‘significant 

energy action’’ as defined in Executive 

Order 13211 (66 FR 28355, May 22, 

2001), because it is not likely to have a 

significant adverse effect on the supply, 

distribution, or use of energy. These 

final rules will result in the addition of 

control equipment and monitoring 

systems for existing and new sources 

within the oil and natural gas industry. 

The final NESHAP amendments are 

unlikely to have a significant adverse 

effect on the supply, distribution, or use 

of energy. As such, the final NESHAP 

amendments are not ‘‘significant energy 

actions’’ as defined in Executive Order 

13211, (66 FR 28355, May 22, 2001). 

The final NSPS is also unlikely to have 

a significant adverse effect on the 

supply, distribution, or use of energy. 

As such, the final NSPS is not a 

‘‘significant energy action’’ as defined in 

Executive Order 13211 (66 FR 28355, 

May 22, 2001). 

The basis for these determinations is 

as follows. Emission controls for the 

NSPS capture VOC emissions that 

otherwise would be vented to the 

atmosphere. Since methane is coemitted 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 

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49540 Federal Register / Vol. 77, No. 159 / Thursday, August 16, 2012 / Rules and Regulations 

the United States energy system. The 

NEMS is a publically available model of 

the United States energy economy 

developed and maintained by the 

Energy Information Administration of 

the DOE and is used to produce the 

Annual Energy Outlook, a reference 

publication that provides detailed 

forecasts of the United States energy 

economy. 

Based on public comments and 

reports to EPA’s Natural Gas STAR 

program, the EPA recognizes that some 

producers conduct well completions 

using REC techniques, which are 

required by the final NSPS for certain 

completions of hydraulically fractured 

and refractured natural gas wells, 

voluntarily based upon economic and 

environmental objectives. The baseline 

used for the energy system impacts 

analysis takes into account REC 

conducted pursuant to state regulations 

covering these operations and estimates 

of REC performed voluntarily. To 

account for REC performed in regulated 

states, the EPA subsumed emissions 

reductions and compliance costs in 

states where these completion-related 

emissions are already controlled into 

the baseline. Additionally, based on 

public comments and reports to the 

EPA’s Natural Gas STAR program, the 

EPA recognizes that some producers 

conduct well completions using REC 

techniques voluntarily for economic 

and/or environmental objectives as a 

normal part of business. To account for 

emissions reductions and costs arising 

from voluntary implementation of 

pollution controls, the EPA used 

information on total emission 

reductions reported to the EPA by 

partners of the EPA Natural Gas STAR. 

This estimate of this voluntary REC 

activity in the absence of regulation is 

also included in the baseline. More 

detailed discussion on the derivation of 

the baseline is presented in a technical 

memorandum in the docket, as well as 

in the RIA. 

The analysis of energy system impacts 

for the final NSPS under the primary 

baseline shows that domestic natural 

gas production is not likely to change in 

2015, the year used in the RIA to 

analyze impacts. Average natural gas 

prices are also not estimated to change 

in response to the final rules. Domestic 

crude oil production is not expected to 

change, while average crude oil prices 

are estimated to decrease slightly (about 

$0.01/barrel or about 0.01 percent at the 

wellhead for onshore production in the 

lower 48 states). All prices are in 2008 

dollars. The NEMS-based analysis 

estimates in the year of analysis, 2015, 

that net imports of natural gas and crude 

oil will not change. 

Additionally, the NSPS establishes 

several performance standards that give 

regulated entities flexibility in 

determining how to best comply with 

the regulation. In an industry that is 

geographically and economically 

heterogeneous, this flexibility is an 

important factor in reducing regulatory 

burden. 

For more information on the 

estimated energy effects, please refer to 

the economic impact analysis for this 

final rule. The analysis is available in 

the RIA, which is in the public docket. 

I. National Technology Transfer and 

Advancement Act 

Section 12(d) of the National 

Technology Transfer and Advancement 

Act of 1995 (NTTAA), Public Law 104– 

113 (15 U.S.C. 272 note) directs the EPA 

to use voluntary consensus standards 

(VCS) in its regulatory activities, unless 

to do so would be inconsistent with 

applicable law or otherwise impractical. 

VCS are technical standards (e.g., 

materials specifications, test methods, 

sampling procedures and business 

practices) that are developed or adopted 

by VCS bodies. NTTAA directs the EPA 

to provide Congress, through OMB, 

explanations when the agency decides 

not to use available and applicable VCS. 

This final rulemaking involves 

technical standards. Three VCS were 

identified as applicable for the purpose 

of these rules. The VCS ASTM D6522– 

00 (2005), Standard Test Method for the 

Determination of Nitrogen Oxides, 

Carbon Monoxide, and Oxygen 

Concentrations in Emissions From 

Natural Gas-Fired Reciprocating 

Engines, Combustion Turbines, Boilers 

and Process Heaters Using Portable 

Analyzers, is an acceptable alternative 

to EPA Methods 3A and 10 for 

identifying nitrogen oxides, carbon 

monoxide, and oxygen concentrations 

when the fuel is natural gas. The VCS 

ASTM D6420–99 (2004), Test Method 

for Determination of Gaseous Organic 

Compounds by Direct Interface Gas 

Chromatography/Mass Spectrometry, is 

an acceptable alternative to EPA Method 

18. The VCS ANSI/ASME PTC 19.10– 

1981 (Part 10, Instruments and 

Apparatus), Flue and Exhaust Gas 

Analyses is an acceptable alternative to 

EPA Methods 3B and 16A manual 

portion only, not the instrumental 

portion. 

No potential VCS were identified for 

EPA Methods 1A, 2A, 2D, 21, and 22. 

During the search, if the title or 

abstract (if provided) of the VCS 

described technical sampling and 

analytical procedures that were similar 

to the EPA’s reference method, the EPA 

ordered a copy of the standard and 

reviewed it as a potential equivalent 

method. All potential standards were 

reviewed to determine the practicality 

of the VCS for this action. This review 

requires significant method validation 

data that meet the requirements of EPA 

Method 301 for accepting alternative 

methods or scientific, engineering and 

policy equivalence to procedures in the 

EPA reference methods. The EPA may 

reconsider determinations of 

impracticality when additional 

information is available for particular 

VCS. 

The search identified 18 other VCS 

that were potentially applicable for 

these rules in lieu of the EPA reference 

methods. After reviewing the available 

standards, the EPA determined that 18 

candidate VCS (ASTM D3154–00 

(2006), ASTM D3464–96 (2007), ASTM 

D3796–90 (2004), ISO 10780:1994, 

ASME B133.9–1994 (2001), ANSI/ 

ASME PTC 19.10–1981 Part 10, ASTM 

D5835–95 (2007), ISO 10396:1993, ISO 

12039:2001, ASTM D6522–00 (2005), 

CAN/CSA Z223.2–M86 (1999), CAN/ 

CSA Z223.21–M1978, ASTM D3162–94 

(2005), ASTM D4323–84 (2009), ASTM 

D6060–96 (2001), ISO 14965:2000(E), 

EN 12619 (1999), ASTM D4855–97 

(2002)) identified for measuring 

emissions of pollutants or their 

surrogates subject to emission standards 

in the rules would not be practical due 

to lack of equivalency, documentation, 

validation data and other important 

technical and policy considerations. 

Refer to the memorandum in the docket 

for further details on the EPA’s review 

of these VCS. 

J. Executive Order 12898: Federal 

Actions to Address Environmental 

Justice in Minority Populations and 

Low-Income Populations 

Executive Order 12898 (59 FR 7629, 

February 16, 1994) establishes Federal 

executive policy on environmental 

justice. Its main provision directs 

Federal agencies, to the greatest extent 

practicable and permitted by law, to 

make environmental justice part of their 

mission by identifying and addressing, 

as appropriate, disproportionately high 

and adverse human health or 

environmental effects of their programs, 

policies and activities on minority 

populations and low income 

populations in the United States. 

The EPA has determined that this 

final rule will not have 

disproportionately high and adverse 

human health or environmental effects 

on minority or low-income populations 

because it increases the level of 

environmental protection for all affected 

populations without having any 

disproportionately high and adverse 

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Federal Register / Vol. 77, No. 159 / Thursday, August 16, 2012 / Rules and Regulations 49541 

human health or environmental effects 

on any population, including any 

minority, low-income, or indigenous 

populations. 

To examine the potential for any 

environmental justice issues that might 

be associated with each source category, 

we evaluated the percentages of various 

social, demographic, and economic 

groups within the at-risk population 

living near the facilities where these 

source categories are located and 

compared them to national averages. 

The development of demographic 

analyses to inform the consideration of 

environmental justice issues in the EPA 

rulemakings is an evolving science. 

The EPA conducted a demographic 

analysis, focusing on populations 

within 50 km of any facility in each of 

the source categories that are estimated 

to have HAP exposures which result in 

cancer risks of 1-in-1 million or greater 

or non-cancer hazard indices of 1 or 

greater based on estimates of current 

HAP emissions. The results of this 

analysis are documented in the 

technical report: Risk and Technology 

Review—Analysis of Socio-Economic 

Factors for Populations Living Near Oil 

& Natural Gas Production Facilities, 

located in the docket for this 

rulemaking. 

As described in the preamble, our risk 

assessments demonstrate that the 

regulations for the oil and natural gas 

production and natural gas transmission 

and storage source categories, are 

associated with an acceptable level of 

risk and that the proposed additional 

requirements will provide an ample 

margin of safety to protect public health. 

Our analyses also show that, for these 

source categories, there is no potential 

for an adverse environmental effect or 

human health multi-pathway effects, 

and that acute and chronic non-cancer 

health impacts are unlikely. The EPA 

has determined that, although there may 

be an existing disparity in HAP risks 

from these sources between some 

demographic groups, no demographic 

group is exposed to an unacceptable 

level of risk. 

To promote meaningful involvement, 

the EPA conducted three public 

hearings on the proposal. The hearings 

were held in Pittsburgh, Pennsylvania, 

on September 27, 2011, Denver, 

Colorado, on September 28, 2011, and 

Arlington, Texas, on September 29, 

2011. A total of 261 people spoke at the 

three hearings and 735 people attended 

the hearings. The attendees at the 

hearings included private citizens, 

community-based and environmental 

organizations, industry representatives, 

associations representing industry and 

local and state government officials. 

K. Congressional Review Act 

The Congressional Review Act, 5 

U.S.C. 801, et seq., as added by the 

Small Business Regulatory Enforcement 

Fairness Act of 1996, generally provides 

that before a rule may take effect, the 

agency promulgating the rule must 

submit a rule report, which includes a 

copy of the rule, to each House of the 

Congress and to the Comptroller General 

of the United States. The EPA will 

submit a report containing this final rule 

and other required information to the 

United States Senate, the United States 

House of Representatives, and the 

Comptroller General of the United 

States prior to publication of the final 

rule in the Federal Register. A major 

rule cannot take effect until 60 days 

after it is published in the Federal 

Register. This action is a ‘‘major rule’’ 

as defined by 5 U.S.C. 804(2). The final 

rules will be effective on October 15, 

2012. 

List of Subjects 

40 CFR Part 60 

Environmental protection, Air 

pollution control, Incorporation by 

reference, Reporting and recordkeeping 

requirements, Volatile organic 

compounds. 

40 CFR Part 63 

Environmental protection, 

Administrative practice and procedures, 

Air pollution control, Hazardous 

substances, Incorporation by reference, 

Reporting and recordkeeping 

requirements, Volatile organic 

compounds. 

Dated: April 17, 2012. 

Lisa P. Jackson, 

Administrator. 

For the reasons set out in the 

preamble, title 40, chapter I of the Code 

of Federal Regulations is amended as 

follows: 

PART 60—[AMENDED] 

■ 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) introductory 

text, (a)(7), (a)(86), (a)(91), and (a)(92); 

■ b. Adding paragraphs (a)(95), (a)(96), 

(a)(97), and (a)(98); and 

■ c. Revising paragraph (h) introductory 

text and (h)(4) to read as follows: 

§ 60.17 Incorporations by reference. 

* * * * * 

(a) The following materials are 

available for purchase from at least one 

of the following addresses: American 

Society for Testing and Materials 

(ASTM), 100 Barr Harbor Drive, Post 

Office Box C700, West Conshohocken, 

PA 19428–2959, Telephone (610) 832– 

9585, and are also available at the 

following Web site: http:// 

www.astm.org; or ProQuest, 789 East 

Eisenhower Parkway, Ann Arbor, MI 

48106–1346, Telephone (734) 761–4700, 

and are also available at the following 

Web site: http://www.proquest.com. 

* * * * * 

(7) ASTM D86–96, Standard Test 

Method for Distillation of Petroleum 

Products (Approved April 10, 1996), 

IBR approved for §§ 60.562–2(d), 

60.593(d), 60.593a(d), 60.633(h) and 

60.5401(f). 

* * * * * 

(86) ASTM D6522–00 (Reapproved 

2005), Standard Test Method for 

Determination of Nitrogen Oxides, 

Carbon Monoxide, and Oxygen 

Concentrations in Emissions from 

Natural Gas-Fired Reciprocating 

Engines, Combustion Turbines, Boilers, 

and Process Heaters Using Portable 

Analyzers (Approved October 1, 2005), 

IBR approved for table 2 of subpart JJJJ 

of this part, and §§ 60.5413(b) and (d). 

* * * * * 

(91) ASTM E169–93, Standard 

Practices for General Techniques of 

Ultraviolet-Visible Quantitative 

Analysis (Approved May 15, 1993), IBR 

approved for §§ 60.485a(d), 60.593(b), 

60.593a(b), 60.632(f) and 60.5400(f). 

(92) ASTM E260–96, Standard 

Practice for Packed Column Gas 

Chromatography (Approved April 10, 

1996), IBR approved for §§ 60.485a(d), 

60.593(b), 60.593a(b), 60.632(f), 

60.5400(f) and 60.5406(b). 

* * * * * 

(95) ASTM D3588–98 (Reapproved 

2003) Standard Practice for Calculating 

Heat Value, Compressibility Factor, and 

Relative Density of Gaseous Fuels 

(Approved May 10, 2003), IBR approved 

for § 60.5413(d). 

(96) ASTM D4891–89 (Reapproved 

2006) Standard Test Method for Heating 

Value of Gases in Natural Gas Range by 

Stoichiometric Combustion (Approved 

June 1, 2006), IBR approved for 

§ 60.5413(d). 

(97) ASTM D1945–03 (Reapproved 

2010), Standard Test Method for 

Analysis of Natural Gas by Gas 

Chromatography (Approved January 1, 

2010), IBR approved for § 60.5413(d). 

(98) ASTM D5504–08, Standard Test 

Method for Determination of Sulfur 

Compounds in Natural Gas and Gaseous 

Fuels by Gas Chromatography and 

Chemiluminescence (Approved June 15, 

2008), IBR approved for § 60.5413(d). 

* * * * * 

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(h) The following material is available 

for purchase from the American Society 

of Mechanical Engineers (ASME), Three 

Park Avenue, New York, NY 10016– 

5990, Telephone (800) 843–2763, and 

are also available at the following Web 

site: http://www.asme.org. 

* * * * * 

(4) ANSI/ASME PTC 19.10–1981, 

Flue and Exhaust Gas Analyses [Part 10, 

Instruments and Apparatus] (Issued 

August 31, 1981), IBR approved for 

§§ 60.56c(b), 60.63(f), 60.106(e), 

60.104a(d), (h), (i) and (j), 60.105a(d), (f) 

and (g), 60.106a(a), 60.107a(a), (c) and 

(d), tables 1 and 3 of subpart EEEE, 

tables 2 and 4 of subpart FFFF, table 2 

of subpart JJJJ, §§ 60.4415(a), 60.2145(s) 

and (t), 60.2710(s), (t) and (w), 

60.2730(q), 60.4900(b) and 60.5220(b), 

tables 1 and 2 to subpart LLLL, tables 2 

and 3 to subpart MMMM, §§ 60.5406(c) 

and 60.5413(b). 

* * * * * 

Subpart KKK—Standards of 

Performance for Equipment Leaks of 

VOC From Onshore Natural Gas 

Processing Plants for Which 

Construction, Reconstruction, or 

Modification Commenced After 

January 20, 1984, and on or Before 

August 23, 2011 

■ 3. The heading for Subpart KKK is 

revised to read as set forth 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 forth above. 

■ 6. Section 60.640 is amended by 

revising paragraph (d) to read as 

follows: 

§ 60.640 Applicability and designation of 

affected facilities. 

* * * * * 

(d) The provisions of this subpart 

apply to each affected facility identified 

in paragraph (a) of this section which 

commences construction or 

modification after January 20, 1984, and 

on or before August 23, 2011. 

* * * * * 

■ 7. Add subpart OOOO, consisting of 

60.5360 through 60.5430, to part 60 to 

read as follows: 

Subpart OOOO—Standards of Performance 

for Crude Oil and Natural Gas Production, 

Transmission and Distribution 

Sec. 

60.5360 What is the purpose of this 

subpart? 

60.5365 Am I subject to this subpart? 

60.5370 When must I comply with this 

subpart? 

60.5375 What standards apply to gas well 

affected facilities? 

60.5380 What standards apply to 

centrifugal compressor affected 

facilities? 

60.5385 What standards apply to 

reciprocating compressor affected 

facilities? 

60.5390 What standards apply to pneumatic 

controller affected facilities? 

60.5395 What standards apply to storage 

vessel affected facilities? 

60.5400 What equipment leak standards 

apply to affected facilities at an onshore 

natural gas processing plant? 

60.5401 What are the exceptions to the 

equipment leak standards for affected 

facilities at onshore natural gas 

processing plants? 

60.5402 What are the alternative emission 

limitations for equipment leaks from 

onshore natural gas processing plants? 

60.5405 What standards apply to 

sweetening units at onshore natural gas 

processing plants? 

60.5406 What test methods and procedures 

must I use for my sweetening units 

affected facilities at onshore natural gas 

processing plants? 

60.5407 What are the requirements for 

monitoring of emissions and operations 

from my sweetening unit affected 

facilities at onshore natural gas 

processing plants? 

60.5408 What is an optional procedure for 

measuring hydrogen sulfide in acid gas— 

Tutwiler Procedure? 

60.5410 How do I demonstrate initial 

compliance with the standards for my 

gas well affected facility, my centrifugal 

compressor affected facility, my 

reciprocating compressor affected 

facility, my pneumatic controller 

affected facility, my storage vessel 

affected facility, and my equipment leaks 

and sweetening unit affected facilities at 

onshore natural gas processing plants? 

60.5411 What additional requirements must 

I meet to determine initial compliance 

for my closed vent systems routing 

emissions from storage vessels or 

centrifugal compressor wet seal fluid 

degassing systems? 

60.5412 What additional requirements must 

I meet for determining initial compliance 

with control devices used to comply 

with the emission standards for my 

storage vessel or centrifugal compressor 

affected facility? 

60.5413 What are the performance testing 

procedures for control devices used to 

demonstrate compliance at my storage 

vessel or centrifugal compressor affected 

facility? 

60.5415 How do I demonstrate continuous 

compliance with the standards for my 

gas well affected facility, my centrifugal 

compressor affected facility, my 

stationary reciprocating compressor 

affected facility, my pneumatic 

controller affected facility, my storage 

vessel affected facility, and my affected 

facilities at onshore natural gas 

processing plants? 

60.5416 What are the initial and continuous 

cover and closed vent system inspection 

and monitoring requirements for my 

storage vessel or centrifugal compressor 

affected facility? 

60.5417 What are the continuous control 

device monitoring requirements for my 

storage vessel or centrifugal compressor 

affected facility? 

60.5420 What are my notification, 

reporting, and recordkeeping 

requirements? 

60.5421 What are my additional 

recordkeeping requirements for my 

affected facility subject to VOC 

requirements for onshore natural gas 

processing plants? 

60.5422 What are my additional reporting 

requirements for my affected facility 

subject to VOC requirements for onshore 

natural gas processing plants? 

60.5423 What additional recordkeeping and 

reporting requirements apply to my 

sweetening unit affected facilities at 

onshore natural gas processing plants? 

60.5425 What parts of the General 

Provisions apply to me? 

60.5430 What definitions apply to this 

subpart? 

Table 1 to Subpart OOOO of Part 60— 

Required Minimum Initial SO2 Emission 

Reduction Efficiency (Zi) 

Table 2 to Subpart OOOO of Part 60— 

Required Minimum SO2 Emission 

Reduction Efficiency (Zc) 

Table 3 to Subpart OOOO of Part 60— 

Applicability of General Provisions to 

Subpart OOOO 

Subpart OOOO—Standards of 

Performance for Crude Oil and Natural 

Gas Production, Transmission and 

Distribution 

§ 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. 

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§ 60.5365 Am I subject to this subpart? 

You are subject to the applicable 

provisions of this subpart if you are the 

owner or operator of one or more of the 

onshore affected facilities listed in 

paragraphs (a) through (g) of this section 

for which you commence construction, 

modification or reconstruction after 

August 23, 2011. 

(a) Each gas well affected facility, 

which is a single natural gas well. 

(b) Each centrifugal compressor 

affected facility, which is a single 

centrifugal compressor using wet seals 

that is located between the wellhead 

and the point of custody transfer to the 

natural gas transmission and storage 

segment. A centrifugal compressor 

located at a well site, or an adjacent well 

site and servicing more than one well 

site, is not an affected facility under this 

subpart. 

(c) Each reciprocating compressor 

affected facility, which is a single 

reciprocating compressor located 

between the wellhead and the point of 

custody transfer to the natural gas 

transmission and storage segment. A 

reciprocating compressor located at a 

well site, or an adjacent well site and 

servicing more than one well site, is not 

an affected facility under this subpart. 

(d)(1) For the oil production segment 

(between the wellhead and the point of 

custody transfer to an oil pipeline), each 

pneumatic controller affected facility, 

which is a single continuous bleed 

natural gas-driven pneumatic controller 

operating at a natural gas bleed rate 

greater than 6 scfh. 

(2) For the natural gas production 

segment (between the wellhead and the 

point of custody transfer to the natural 

gas transmission and storage segment 

and not including natural gas processing 

plants), each pneumatic controller 

affected facility, which is a single 

continuous bleed natural gas-driven 

pneumatic controller operating at a 

natural gas bleed rate greater than 6 

scfh. 

(3) For natural gas processing plants, 

each pneumatic controller affected 

facility, which is a single continuous 

bleed natural gas-driven pneumatic 

controller. 

(e) Each storage vessel affected 

facility, which is a single storage vessel, 

located in the oil and natural gas 

production segment, natural gas 

processing segment or natural gas 

transmission and storage segment. 

(f) The group of all equipment, except 

compressors, within a process unit is an 

affected facility. 

(1) Addition or replacement of 

equipment for the purpose of process 

improvement that is accomplished 

without a capital expenditure shall not 

by itself be considered a modification 

under this subpart. 

(2) Equipment associated with a 

compressor station, dehydration unit, 

sweetening unit, underground storage 

vessel, field gas gathering system, or 

liquefied natural gas unit is covered by 

§§ 60.5400, 60.5401, 60.5402, 60.5421, 

and 60.5422 of this subpart if it is 

located at an onshore natural gas 

processing plant. Equipment not located 

at the onshore natural gas processing 

plant site is exempt from the provisions 

of §§ 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 §§ 60.5410(g) and 

60.5415(g) of this subpart. 

(4) Sweetening facilities producing 

acid gas that is completely reinjected 

into oil-or-gas-bearing geologic strata or 

that is otherwise not released to the 

atmosphere are not subject to §§ 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 October 15, 2012, must 

meet the requirements of § 60.5375(a)(1) 

through (4). 

(2) A well completion operation 

following hydraulic refracturing at a gas 

well facility not conducted pursuant to 

§ 60.5375 is a modification to the gas 

well affected facility. 

(3) Refracturing of a gas well facility 

does not affect the modification status of 

other equipment, process units, storage 

vessels, compressors, or pneumatic 

controllers located at the well site. 

(4) Sources initially constructed after 

August 23, 2011, are considered affected 

sources regardless of this provision. 

§ 60.5370 When must I comply with this 

subpart? 

(a) You must be in compliance with 

the standards of this subpart no later 

than October 15, 2012 or upon startup, 

whichever is later. 

(b) The provisions for exemption from 

compliance during periods of startup, 

shutdown and malfunctions provided 

for in 40 CFR 60.8(c) do not apply to 

this subpart. 

(c) You are exempt from the 

obligation to obtain a permit under 40 

CFR part 70 or 40 CFR part 71, provided 

you are not otherwise required by law 

to obtain a permit under 40 CFR 70.3(a) 

or 40 CFR 71.3(a). Notwithstanding the 

previous sentence, you must continue to 

comply with the provisions of this 

subpart. 

§ 60.5375 What standards apply to gas 

well affected facilities? 

If you are the owner or operator of a 

gas well affected facility, you must 

comply with paragraphs (a) through (f) 

of this section. 

(a) Except as provided in paragraph (f) 

of this section, for each well completion 

operation with hydraulic fracturing 

begun prior to January 1, 2015, you 

must comply with the requirements of 

paragraphs (a)(3) and (4) of this section 

unless a more stringent state or local 

emission control requirement is 

applicable; optionally, you may comply 

with the requirements of paragraphs 

(a)(1) through (4) of this section. For 

each new well completion operation 

with hydraulic fracturing begun on or 

after January 1, 2015, you must comply 

with the requirements in paragraphs 

(a)(1) through (4) of this section. 

(1) For the duration of flowback, route 

the recovered liquids into one or more 

storage vessels or re-inject the recovered 

liquids into the well or another well, 

and route the recovered gas into a gas 

flow line or collection system, re-inject 

the recovered gas into the well or 

another well, use the recovered gas as 

an on-site fuel source, or use the 

recovered gas for another useful purpose 

that a purchased fuel or raw material 

would serve, with no direct release to 

the atmosphere. If this is infeasible, 

follow the requirements in paragraph 

(a)(3) of this section. 

(2) All salable quality gas must be 

routed to the gas flow line as soon as 

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practicable. In cases where flowback 

emissions cannot be directed to the flow 

line, you must follow the requirements 

in paragraph (a)(3) of this section. 

(3) You must capture and direct 

flowback emissions to a completion 

combustion device, except in conditions 

that may result in a fire hazard or 

explosion, or where high heat emissions 

from a completion combustion device 

may negatively impact tundra, 

permafrost or waterways. Completion 

combustion devices must be equipped 

with a reliable continuous ignition 

source over the duration of flowback. 

(4) You have a general duty to safely 

maximize resource recovery and 

minimize releases to the atmosphere 

during flowback and subsequent 

recovery. 

(b) You must maintain a log for each 

well completion operation at each gas 

well affected facility. The log must be 

completed on a daily basis for the 

duration of the well completion 

operation and must contain the records 

specified in § 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)(i) 

and (ii) of this section, you must comply 

with the requirements of paragraphs 

(f)(2) and (3) of this section. 

(i) Each well completion operation 

with hydraulic fracturing at a gas well 

affected facility meeting the criteria for 

a wildcat or delineation well. 

(ii) Each well completion operation 

with hydraulic fracturing at a gas well 

affected facility meeting the criteria for 

a non-wildcat low pressure gas well or 

non-delineation low pressure gas well. 

(2) You must capture and direct 

flowback emissions to a completion 

combustion device, except in conditions 

that may result in a fire hazard or 

explosion, or where high heat emissions 

from a completion combustion device 

may negatively impact tundra, 

permafrost or waterways. Completion 

combustion devices must be equipped 

with a reliable continuous ignition 

source over the duration of flowback. 

You must also comply with paragraphs 

(a)(4) and (b) through (e) of this section. 

(3) You must maintain records 

specified in § 60.5420(c)(1)(iii) for 

wildcat, delineation and low pressure 

gas wells. 

§ 60.5380 What standards apply to 

centrifugal compressor affected facilities? 

You must comply with the standards 

in paragraphs (a) through (d) of this 

section for each centrifugal compressor 

affected facility. 

(a)(1) You must reduce VOC 

emissions from each centrifugal 

compressor wet seal fluid degassing 

system by 95.0 percent or greater. 

(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. 

(a) You must replace the reciprocating 

compressor rod packing according to 

either paragraph (a)(1) or (2) of this 

section. 

(1) Before the compressor has 

operated for 26,000 hours. The number 

of hours of operation must be 

continuously monitored beginning upon 

initial startup of your reciprocating 

compressor affected facility, or October 

15, 2012, or the date of the most recent 

reciprocating compressor rod packing 

replacement, whichever is later. 

(2) Prior to 36 months from the date 

of the most recent rod packing 

replacement, or 36 months from the date 

of startup for a new reciprocating 

compressor for which the rod packing 

has not yet been replaced. 

(b) You must demonstrate initial 

compliance with standards that apply to 

reciprocating compressor affected 

facilities as required by § 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. 

§ 60.5390 What standards apply to 

pneumatic controller affected facilities? 

For each pneumatic controller 

affected facility you must comply with 

the VOC standards, based on natural gas 

as a surrogate for VOC, in either 

paragraph (b) or (c) of this section, as 

applicable. Pneumatic controllers 

meeting the conditions in paragraph (a) 

of this section are exempt from this 

requirement. 

(a) The requirements of paragraph (b) 

or (c) of this section are not required if 

you determine that the use of a 

pneumatic controller affected facility 

with a bleed rate greater than 6 standard 

cubic feet per hour is required based on 

functional needs, including but not 

limited to response time, safety and 

positive actuation. 

(b)(1) Each pneumatic controller 

affected facility at a natural gas 

processing plant must have a bleed rate 

of zero. 

(2) Each pneumatic controller affected 

facility at a natural gas processing plant 

must be tagged with the month and year 

of installation, reconstruction or 

modification, and identification 

information that allows traceability to 

the records for that pneumatic controller 

as required in § 60.5420(c)(4)(iv). 

(c)(1) Each pneumatic controller 

affected facility constructed, modified 

or reconstructed on or after October 15, 

2013 at a location between the wellhead 

and a natural gas processing plant must 

have a bleed rate less than or equal to 

6 standard cubic feet per hour. 

(2) Each pneumatic controller affected 

facility at a location between the 

wellhead and a natural gas processing 

plant must be tagged with the month 

and year of installation, reconstruction 

or modification, and identification 

information that allows traceability to 

the records for that controller as 

required in § 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? 

Except as provided in paragraph (d) of 

this section, you must comply with the 

standards in this section no later than 

October 15, 2013 for each storage vessel 

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affected facility constructed, modified 

or reconstructed after August 23, 2011, 

with VOC emissions equal to or greater 

than 6 tpy, as determined in paragraph 

(a) of this section. 

(a) Emissions determination—(1) Well 

sites with no other wells in production. 

For each storage vessel constructed, 

modified or reconstructed at a well site 

with no other wells in production, you 

must determine the VOC emission rate 

for each storage vessel affected facility 

using any generally accepted model or 

calculation methodology within 30 days 

after startup, and minimize emissions to 

the extent practicable during the 30-day 

period using good engineering practices. 

For each storage vessel affected facility 

emitting more than 6 tpy VOC, you must 

reduce VOC emissions by 95.0 percent 

or greater within 60 days after startup. 

(2) Well sites with one or more wells 

already in production. For each storage 

vessel constructed, modified or 

reconstructed at a well site with one or 

more wells already in production, you 

must determine the VOC emission rate 

for each storage vessel affected facility 

using any generally accepted model or 

calculation methodology upon startup. 

For each storage vessel affected facility 

emitting more than 6 tpy VOC, you must 

reduce VOC emissions by 95.0 percent 

or greater upon startup. 

(b) Control requirements. (1) If you 

use a control device (such as an 

enclosed combustion device or vapor 

recovery device) to reduce emissions, 

you must equip the storage vessel with 

a cover that meets the requirements of 

§ 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. 

(d) Exemptions. This section does not 

apply to storage vessels subject to and 

controlled in accordance with the 

requirements for storage vessels in 40 

CFR part 60, subpart Kb, or 40 CFR part 

63, subparts G, CC, HH, WW, or HHH. 

§ 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. 

(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– 

93, E168–92, or E260–96 (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) 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 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 150 °C (302 °F) 

as determined by ASTM Method D86– 

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 150 °C (302 

°F) as determined by ASTM Method 

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D86–96 (incorporated by reference as 

specified in § 60.17). 

(g) An owner or operator may use the 

following provisions instead of 

§ 60.485a(b)(2): 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 re-monitored. 

§ 60.5402 What are the alternative 

emission limitations for equipment leaks 

from onshore natural gas processing 

plants? 

(a) If, in the Administrator’s 

judgment, an alternative means of 

emission limitation will achieve a 

reduction in VOC emissions at least 

equivalent to the reduction in VOC 

emissions achieved under any design, 

equipment, work practice or operational 

standard, the Administrator will 

publish, in the Federal Register, a 

notice permitting the use of that 

alternative means for the purpose of 

compliance with that standard. The 

notice may condition permission on 

requirements related to the operation 

and maintenance of the alternative 

means. 

(b) Any notice under paragraph (a) of 

this section must be published only 

after notice and an opportunity for a 

public hearing. 

(c) The Administrator will consider 

applications under this section from 

either owners or operators of affected 

facilities, or manufacturers of control 

equipment. 

(d) The Administrator will treat 

applications under this section 

according to the following criteria, 

except in cases where the Administrator 

concludes that other criteria are 

appropriate: 

(1) The applicant must collect, verify 

and submit test data, covering a period 

of at least 12 months, necessary to 

support the finding in paragraph (a) of 

this section. 

(2) If the applicant is an owner or 

operator of an affected facility, the 

applicant must commit in writing to 

operate and maintain the alternative 

means so as to achieve a reduction in 

VOC emissions at least equivalent to the 

reduction in VOC emissions achieved 

under the design, equipment, work 

practice or operational standard. 

§ 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. 

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/kgmole)(1000 kg S/Mg)). 

= 1.331 × 10¥3Mg/dscm, for metric units. 

= (32 lb S/lb-mole)/((385.36 dscf/lbmole)(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. 

(3) You must use the Tutwiler 

procedure in § 60.5408 or a 

chromatographic procedure following 

ASTM E260–96 (incorporated by 

reference as specified in § 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 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). 


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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 cross-sectional 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 

concentration must be multiplied by 0.5 

× 10¥3 to convert the results to sulfur 

equivalent. 

(ii) You must use Method 15 of 

appendix A to part 60 of this chapter to 

determine the TRS concentration from 

reduction-type devices or where the 

oxygen content of the effluent gas is less 

than 1.0 percent by volume. The 

sampling rate must be at least 3 liters/ 

min (0.1 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 or ANSI/ASME PTC 19.10– 

1981, Part 10 (manual portion only) 

(incorporated by reference as specified 

in § 60.17) to determine the reduced 

sulfur concentration from oxidationtype 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 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 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 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 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 

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performance test to ensure the sulfur 

compound oxidation criteria are met. 

Operation at lower average temperatures 

may be considered by the Administrator 

to be unacceptable operation and 

maintenance of the affected facility. You 

may request that the minimum 

incinerator temperature be reestablished 

by conducting new performance tests 

under § 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 promulgation of a 

performance specification for 

continuous monitoring systems for total 

reduced sulfur compounds at sulfur 

recovery plants. 

(d) For those sources required to 

comply with paragraph (b) or (c) of this 

section, you must calculate the average 

sulfur emission reduction efficiency 

achieved (R) for each 24-hour clock 

interval. The 24-hour interval may begin 

and end at any selected clock time, but 

must be consistent. You must compute 

the 24-hour average reduction efficiency 

(R) based on the 24-hour average sulfur 

production rate (S) and sulfur emission 

rate (E), using the equation in 

§ 60.5406(c)(1). 

(1) You must use data obtained from 

the sulfur production rate monitoring 

device specified in paragraph (a) of this 

section to determine S. 

(2) You must use data obtained from 

the sulfur emission rate monitoring 

systems specified in paragraphs (b) or 

(c) of this section to calculate a 24-hour 

average for the sulfur emission rate (E). 

The monitoring system must provide at 

least one data point in each successive 

15-minute interval. You must use at 

least two data points to calculate each 

1-hour average. You must use a 

minimum of 18 1-hour averages to 

compute each 24-hour average. 

(e) In lieu of complying with 

paragraphs (b) or (c) of this section, 

those sources with a design capacity of 

less than 152 Mg/D (150 LT/D) of H2S 

expressed as sulfur may calculate the 

sulfur emission reduction efficiency 

achieved for each 24-hour period by: 

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. 

§ 60.5408 What is an optional procedure 

for measuring hydrogen sulfide in acid 

gas—Tutwiler Procedure? 

The Tutwiler procedure may be found 

in the Gas Engineers Handbook, Fuel 

Gas Engineering practices, The 

Industrial Press, 93 Worth Street, New 

York, NY, 1966, First Edition, Second 

Printing, page 6/25 (Docket A–80–20–A, 

Entry II–I–67). 

(a) When an instantaneous sample is 

desired and H2S concentration is ten 

grains per 1000 cubic foot or more, a 

100 ml Tutwiler burette is used. For 

concentrations less than ten grains, a 

500 ml Tutwiler burette and more dilute 

solutions are used. In principle, this 

method consists of titrating hydrogen 

sulfide in a gas sample directly with a 

standard solution of iodine. 

(b) Apparatus. (See Figure 1 of this 

subpart) A 100 or 500 ml capacity 

Tutwiler burette, with two-way glass 

stopcock at bottom and three-way 

stopcock at top which connect either 

with inlet tubulature or glass-stoppered 

cylinder, 10 ml capacity, graduated in 

0.1 ml subdivision; rubber tubing 

connecting burette with leveling bottle. 

(c) Reagents. (1) Iodine stock solution, 

0.1N. Weight 12.7 g iodine, and 20 to 25 

g cp potassium iodide for each liter of 

solution. Dissolve KI in as little water as 

necessary; dissolve iodine in 

concentrated KI solution, make up to 

proper volume, and store in glassstoppered brown glass bottle. 

(2) Standard iodine solution, 1 

ml=0.001771 g I. Transfer 33.7 ml of 

above 0.1N stock solution into a 250 ml 

volumetric flask; add water to mark and 

mix well. Then, for 100 ml sample of 

gas, 1 ml of standard iodine solution is 

equivalent to 100 grains H2S per cubic 

feet of gas. 

(3) Starch solution. Rub into a thin 

paste about one teaspoonful of wheat 

starch with a little water; pour into 

about a pint of boiling water; stir; let 

cool and decant off clear solution. Make 

fresh solution every few days. 

(d) Procedure. Fill leveling bulb with 

starch solution. Raise (L), open cock (G), 

open (F) to (A), and close (F) when 

solutions starts to run out of gas inlet. 

Close (G). Purge gas sampling line and 

connect with (A). Lower (L) and open 

(F) and (G). When liquid level is several 

ml past the 100 ml mark, close (G) and 

(F), and disconnect sampling tube. Open 

(G) and bring starch solution to 100 ml 

mark by raising (L); then close (G). Open 

(F) momentarily, to bring gas in burette 

to atmospheric pressure, and close (F). 

Open (G), bring liquid level down to 10 

ml mark by lowering (L). Close (G), 

clamp rubber tubing near (E) and 

disconnect it from burette. Rinse 

graduated cylinder with a standard 

iodine solution (0.00171 g I per ml); fill 

cylinder and record reading. Introduce 

successive small amounts of iodine thru 

(F); shake well after each addition; 

continue until a faint permanent blue 

color is obtained. Record reading; 

subtract from previous reading, and call 

difference D. 

(e) With every fresh stock of starch 

solution perform a blank test as follows: 

Introduce fresh starch solution into 

burette up to 100 ml mark. Close (F) and 

(G). Lower (L) and open (G). When 

liquid level reaches the 10 ml mark, 

close (G). With air in burette, titrate as 

during a test and up to same end point. 

Call ml of iodine used C. Then, Grains 

H2S per 100 cubic foot of gas = 100(D– 

C) 


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(f) Greater sensitivity can be attained 

if a 500 ml capacity Tutwiler burette is 

used with a more dilute (0.001N) iodine 

solution. Concentrations less than 1.0 

grains per 100 cubic foot can be 

determined in this way. Usually, the 

starch-iodine end point is much less 

distinct, and a blank determination of 

end point, with H2S-free gas or air, is 

required. 

BILLING CODE 6560–50–P 


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49550 Federal Register / Vol. 77, No. 159 / Thursday, August 16, 2012 / Rules and Regulations 

BILLING CODE 6560–50–C 

§ 60.5410 How do I demonstrate initial 

compliance with the standards for my gas 

well affected facility, my centrifugal 

compressor affected facility, my 

reciprocating compressor affected facility, 

my pneumatic controller affected facility, 

my storage vessel affected facility, and my 

equipment leaks and sweetening unit 

affected facilities at onshore natural gas 

processing plants? 

You must determine initial 

compliance with the standards for each 

affected facility using the requirements 

in paragraphs (a) through (g) of this 

section. The initial compliance period 

begins on October 15, 2012 or upon 

initial startup, whichever is later, and 

ends no later than one year after the 

initial startup date for your affected 

facility or no later than one year after 

October 15, 2012. The initial 

compliance period may be less than one 

full year. 

(a) To achieve initial compliance with 

the standards for each well completion 

operation conducted at your gas well 

affected facility you must comply with 

paragraphs (a)(1) through (a)(4) of this 

section. 

(1) You must submit the notification 

required in § 60.5420(a)(2). 

(2) You must submit the initial annual 

report for your well affected facility as 

required in § 60.5420(b). 

(3) You must maintain a log of records 

as specified in § 60.5420(c)(1) for each 

well completion operation conducted 

during the initial compliance period. 

(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 

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 October 15, 2012, 

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), (3), and (4). 

(7) You must submit the initial annual 

report for your centrifugal compressor 

affected facility as required in 

§ 60.5420(b) for each centrifugal 

compressor affected facility 

(8) You must maintain the records as 

specified in § 60.5420(c)(3). 

(c) To achieve initial compliance with 

the standards for each reciprocating 

compressor affected facility you must 

comply with paragraphs (c)(1) through 

(4) of this section. 

(1) During the initial compliance 

period, you must continuously monitor 

the number of hours of operation or 

track the number of months since the 

last rod packing replacement. 

(2) You must submit the notifications 

required in 60.7(a)(1), (3), and (4). 

(3) You must submit the initial annual 

report for your reciprocating compressor 

as required in § 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 (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 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 (3) of this section 

in the initial annual report submitted for 

your pneumatic controller affected 

facilities constructed, modified or 

reconstructed during the period covered 

by the annual report according to the 

requirements of § 60.5420(b). 

(6) You must maintain the records as 

specified in § 60.5420(c)(4) for each 

pneumatic controller affected facility. 

(e) To achieve initial compliance with 

the 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 within 60 days after startup 

for storage vessels constructed, modified 

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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 October 

15, 2013, 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 (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. 

(g) For sweetening unit affected 

facilities at onshore natural gas 

processing plants, initial compliance is 

demonstrated according to paragraphs 

(g)(1) through (3) of this section. 

(1) To determine compliance with the 

standards for SO2 specified in 

§ 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 (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 (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 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 (ii) 

of this section if the closed vent system 

contains one or more bypass devices 

that could be used to divert all or a 

portion of the gases, vapors, or fumes 

from entering the control device. 

(i) Except as provided in paragraph 

(a)(3)(ii) of this section, you must 

comply with either paragraph 

(a)(3)(i)(A) or (B) of this section for each 

bypass device. 

(A) You must properly install, 

calibrate, maintain, and operate a flow 

indicator at the inlet to the bypass 

device that could divert the stream away 

from the control device to the 

atmosphere that is capable of taking 

periodic readings as specified in 

§ 60.5416(a)(4) and sounds an alarm 

when the bypass device is open such 

that the stream is being, or could be, 

diverted away from the control device to 

the atmosphere. 

(B) You must secure the bypass device 

valve installed at the inlet to the bypass 

device in the non-diverting position 

using a car-seal or a lock-and-key type 

configuration. 

(ii) Low leg drains, high point bleeds, 

analyzer vents, open-ended valves or 

lines, and safety devices are not subject 

to the requirements of paragraph (a)(3)(i) 

of this section. 

(b) Cover requirements. (1) The cover 

and all openings on the cover (e.g., 

access hatches, sampling ports, and 

gauge wells) shall form a continuous 

barrier over the entire surface area of the 

liquid in the storage vessel or wet seal 

fluid degassing system. 

(2) Each cover opening shall be 

secured in a closed, sealed position 

(e.g., covered by a gasketed lid or cap) 

whenever material is in the unit on 

which the cover is installed except 

during those times when it is necessary 

to use an opening as follows: 

(i) To add material to, or remove 

material from the unit (this includes 

openings necessary to equalize or 

balance the internal pressure of the unit 

following changes in the level of the 

material in the unit); 

(ii) To inspect or sample the material 

in the unit; 

(iii) To inspect, maintain, repair, or 

replace equipment located inside the 

unit; or 

(iv) To vent liquids, gases, or fumes 

from the unit through a closed-vent 

system to a control device designed and 

operated in accordance with the 

requirements of paragraph (a) of this 

section. 

§ 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 (2) for 

your storage vessel, you must use one of 

the control devices specified in 

paragraphs (a)(1) through (3) of this 

section. You must demonstrate that the 

control device achieves the performance 

requirements using the performance test 

methods and procedures specified in 

§ 60.5413. 

(1) You must design and operate an 

enclosed combustion device (e.g., 

thermal vapor incinerator, catalytic 

vapor incinerator, boiler, or process 

heater) in accordance with one of the 

performance requirements specified in 

paragraphs (a)(1)(i) through (iv) of this 

section. 

(i) You must reduce the mass content 

of VOC in the gases vented to the device 

by 95.0 percent by weight or greater as 

determined in accordance with the 

requirements of § 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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49552 Federal Register / Vol. 77, No. 159 / Thursday, August 16, 2012 / Rules and Regulations 

(2) You must design and operate a 

vapor recovery device (e.g., carbon 

adsorption system or condenser) or 

other non-destructive control device to 

reduce the mass content of VOC in the 

gases vented to the device by 95.0 

percent by weight or greater as 

determined in accordance with the 

requirements of § 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 (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. 

(c) For each carbon adsorption system 

used as a control device to meet the 

requirements of paragraph (a)(2) of this 

section, you must manage the carbon in 

accordance with the requirements 

specified in paragraphs (c)(1) or (2) of 

this section. 

(1) Following the initial startup of the 

control device, you must replace all 

carbon in the control device with fresh 

carbon on a regular, predetermined time 

interval that is no longer than the 

carbon service life established according 

to § 60.5413(c)(2) or (3) for the carbon 

adsorption system. You must maintain 

records identifying the schedule for 

replacement and records of each carbon 

replacement as required in 

§ 60.5420(c)(6). 

(2) You must either regenerate, 

reactivate, or burn the spent carbon 

removed from the carbon adsorption 

system in one of the units specified in 

paragraphs (c)(2)(i) through (vii) of this 

section. 

(i) Regenerate or reactivate the spent 

carbon in a thermal treatment unit for 

which you have been issued a final 

permit under 40 CFR part 270 that 

implements the requirements of 40 CFR 

part 264, subpart X. 

(ii) Regenerate or reactivate the spent 

carbon in a thermal treatment unit 

equipped with and operating air 

emission controls in accordance with 

this section. 

(iii) Regenerate or reactivate the spent 

carbon in a thermal treatment unit 

equipped with and operating organic air 

emission controls in accordance with an 

emissions standard for VOC under 

another subpart in 40 CFR part 60 or 

this part. 

(iv) Burn the spent carbon in a 

hazardous waste incinerator for which 

the owner or operator has been issued 

a final permit under 40 CFR part 270 

that implements the requirements of 40 

CFR part 264, subpart O. 

(v) Burn the spent carbon in a 

hazardous waste incinerator which you 

have designed and operated in 

accordance with the requirements of 40 

CFR part 265, subpart O. 

(vi) Burn the spent carbon in a boiler 

or industrial furnace for which you have 

been issued a final permit under 40 CFR 

part 270 that implements the 

requirements of 40 CFR part 266, 

subpart H. 

(vii) Burn the spent carbon in a boiler 

or industrial furnace that you have 

designed and operated in accordance 

with the interim status requirements of 

40 CFR part 266, subpart H. 

§ 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. 

(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 (5) of this section, as 

applicable, for each performance test 

conducted to demonstrate that a control 

device meets the requirements of 

§ 60.5412(a). You must conduct the 

initial and periodic performance tests 

according to the schedule specified in 

paragraph (b)(5) of this section. 

(1) You must use Method 1 or 1A at 

40 CFR part 60, appendix A–1, as 

appropriate, to select the sampling sites 

specified in paragraphs (b)(1)(i) and (ii) 

of this section. Any references to 

particulate mentioned in Methods 1 and 

1A do not apply to this section. 

(i) Sampling sites must be located at 

the inlet of the first control device, and 

at the outlet of the final control device, 

to determine compliance with the 

control device percent reduction 

requirement specified in 

§ 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) 

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Federal Register / Vol. 77, No. 159 / Thursday, August 16, 2012 / Rules and Regulations 49553 

through (iv) of this section to calculate 

percent reduction efficiency. 

(i) For each run, you must take either 

an integrated sample or a minimum of 

four grab samples per hour. If grab 

sampling is used, then the samples must 

be taken at approximately equal 

intervals in time, such as 15-minute 

intervals during the run. 

(ii) You must compute the mass rate 

of TOC (minus methane and ethane) 

using the equations and procedures 

specified in paragraphs (b)(3)(ii)(A) and 

(B) of this section. 

(A) You must use the following 

equations: 

Where: 

Ei, Eo = Mass rate of TOC (minus methane 

and ethane) at the inlet and outlet of the 

control device, respectively, dry basis, 

kilogram per hour. 

K2 = Constant, 2.494 × 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. 

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 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 (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: 

Where: 

CTOC = Concentration of total organic 

compounds minus methane and ethane, 

dry basis, parts per million by volume. 

Cji = Concentration of sample component j of 

sample i, dry basis, parts per million by 

volume. 

n = Number of components in the sample. 

x = Number of samples in the sample run. 

(iii) You must correct the TOC 

concentration to 3 percent oxygen as 

specified in paragraphs (b)(4)(iii)(A) and 

(B) of this section. 

(A) You must use the emission rate 

correction factor for excess air, 

integrated sampling and analysis 

procedures of Method 3A or 3B at 40 

CFR part 60, appendix A, ASTM 

D6522–00 (Reapproved 2005), or ANSI/ 

ASME PTC 19.10–1981, Part 10 (manual 

portion only) (incorporated by reference 

as specified in § 60.17) to determine the 

oxygen concentration. The samples 

must be taken during the same time that 

the samples are taken for determining 

TOC concentration. 

(B) You must correct the TOC 

concentration for percent oxygen as 

follows: 

Where: 

Cc = TOC concentration corrected to 3 

percent oxygen, dry basis, parts per 

million by volume. 

Cm = TOC concentration, dry basis, parts per 

million by volume. 

%O2d = Concentration of oxygen, dry basis, 

percent by volume. 

(5) You must conduct performance 

tests according to the schedule specified 

in paragraphs (b)(5)(i) and (ii) of this 

section. 

(i) You must conduct an initial 

performance test within 180 days after 

initial startup for your affected facility. 

You must submit the performance test 

results as required in § 60.5420(b)(7). 

(ii) You must conduct periodic 

performance tests for all control devices 

required to conduct initial performance 

tests except as specified in paragraphs 

(b)(5)(ii)(A) and (B) of this section. You 

must conduct the first periodic 

performance test no later than 60 

months after the initial performance test 

required in paragraph (b)(5)(i) of this 

section. You must conduct subsequent 

periodic performance tests at intervals 

no longer than 60 months following the 

previous periodic performance test or 

whenever you desire to establish a new 

operating limit. You must submit the 

periodic performance test results as 

specified in § 60.5420(b)(7). Combustion 

control devices meeting the criteria in 

either paragraph (b)(5)(ii)(A) or (B) of 

this section are not required to conduct 

periodic performance tests. 

(A) A control device whose model is 

tested under, and meets the criteria of 

paragraph (d) of this section. 

(B) A combustion control device 

tested under paragraph (b) of this 

section that meets the outlet TOC 

performance level specified in 

§ 60.5412(a)(1)(ii) and that establishes a 

correlation between firebox or 

combustion chamber temperature and 

the TOC performance level. 

(c) Control device design analysis to 

meet the requirements of § 60.5412(a). 

(1) For a condenser, the design analysis 

must include an analysis of the vent 

stream composition, constituent 

concentrations, flowrate, relative 

humidity, and temperature, and must 

establish the design outlet organic 

compound concentration level, design 

average temperature of the condenser 

exhaust vent stream, and the design 


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average temperatures of the coolant 

fluid at the condenser inlet and outlet. 

(2) For a regenerable carbon 

adsorption system, the design analysis 

shall include the vent stream 

composition, constituent 

concentrations, flowrate, relative 

humidity, and temperature, and shall 

establish the design exhaust vent stream 

organic compound concentration level, 

adsorption cycle time, number and 

capacity of carbon beds, type and 

working capacity of activated carbon 

used for the carbon beds, design total 

regeneration stream flow over the period 

of each complete carbon bed 

regeneration cycle, design carbon bed 

temperature after regeneration, design 

carbon bed regeneration time, and 

design service life of the carbon. 

(3) For a nonregenerable carbon 

adsorption system, such as a carbon 

canister, the design analysis shall 

include the vent stream composition, 

constituent concentrations, flowrate, 

relative humidity, and temperature, and 

shall establish the design exhaust vent 

stream organic compound concentration 

level, capacity of the carbon bed, type 

and working capacity of activated 

carbon used for the carbon bed, and 

design carbon replacement interval 

based on the total carbon working 

capacity of the control device and 

source operating schedule. In addition, 

these systems will incorporate dual 

carbon canisters in case of emission 

breakthrough occurring in one canister. 

(4) If you and the Administrator do 

not agree on a demonstration of control 

device performance using a design 

analysis, then you must perform a 

performance test in accordance with the 

requirements of paragraph (b) of this 

section to resolve the disagreement. The 

Administrator may choose to have an 

authorized representative observe the 

performance test. 

(d) Performance testing for 

combustion control devices— 

manufacturers’ performance test. The 

manufacturer must demonstrate that a 

specific model of combustion control 

device achieves the performance 

requirements in paragraph (d)(1) of this 

section by conducting a performance 

test as specified in paragraphs (d)(2) 

through (8) of this section. You must 

submit a test report for each combustion 

control device in accordance with the 

requirements in paragraphs (d)(9) of this 

section. 

(1) The manufacturer must meet the 

performance test criteria in paragraphs 

(d)(1)(i) through (iii) of this section. 

(i) The control device model tested 

must meet the emission levels in 

paragraphs (d)(1)(i)(A) through (C) of 

this section. 

(A) Method 22 at 40 CFR part 60, 

appendix A–7, results under paragraph 

(d)(6)(iv) of this section with no 

indication of visible emissions. 

(B) Average Method 25A at 40 CFR 

part 60, appendix A–7, results under 

paragraph (d)(8) of this section equal to 

or less than 10.0 parts per million by 

volume-wet THC as propane corrected 

to 3.0 percent carbon dioxide, and 

(C) Average carbon monoxide 

emissions determined under paragraph 

(d)(6)(iii) of this section equal to or less 

than 10 parts per million by volumedry, corrected to 3.0 percent carbon 

dioxide. 

(ii) The manufacturer must determine 

a maximum inlet gas flow rate, which 

must not be exceeded for each control 

device model to achieve the criteria in 

paragraph (d)(1)(i) of this section. 

(iii) A control device meeting the 

emission levels in paragraph (d)(1)(i)(A) 

through (C) of this section must 

demonstrate a minimum destruction 

efficiency of 95.0 percent for VOC 

regulated under this subpart. 

(2) Performance testing must consist 

of three one-hour (or longer) test runs 

for each of the four firing rate settings 

in paragraphs (d)(2)(i) through (iv) of 

this section, making a total of 12 test 

runs per test. The manufacturer must 

use propene (propylene) gas for the 

testing fuel. An independent third-party 

laboratory (not affiliated with the 

control device manufacturer or fuel 

supplier) must perform all fuel analyses. 

(i) 90–100 percent of maximum 

design rate (fixed rate). 

(ii) 70–100–70 percent (ramp up, 

ramp down). Begin the test at 70 percent 

of the maximum design rate. Within the 

first 5 minutes, ramp up the firing rate 

to 100 percent of the maximum design 

rate. Hold at 100 percent for 5 minutes. 

In the 10–15 minute time range, ramp 

back down to 70 percent of the 

maximum design rate. Repeat three 

more times for a total of 60 minutes of 

sampling. 

(iii) 30–70–30 percent (ramp up, ramp 

down). Begin the test at 30 percent of 

the maximum design rate. Within the 

first 5 minutes, ramp up the firing rate 

to 70 percent of the maximum design 

rate. Hold at 70 percent for 5 minutes. 

In the 10–15 minute time range, ramp 

back down to 30 percent of the 

maximum design rate. Repeat three 

more times for a total of 60 minutes of 

sampling. 

(iv) 0–30–0 percent (ramp up, ramp 

down). Begin the test at 0 percent of the 

maximum design rate. Within the first 5 

minutes, ramp up the firing rate to 100 

percent of the maximum design rate. 

Hold at 30 percent for 5 minutes. In the 

10–15 minute time range, ramp back 

down to 0 percent of the maximum 

design rate. Repeat three more times for 

a total of 60 minutes of sampling. 

(3) The manufacturer must test all 

models employing multiple enclosures 

simultaneously and with all burners 

operational. The manufacturer must 

report results for each enclosure 

individually and for the average of the 

emissions from all interconnected 

combustion enclosures/chambers. 

Control device operating data must be 

collected continuously throughout the 

performance test using an electronic 

Data Acquisition System and strip chart. 

The manufacturer must submit data 

with the test report in accordance with 

paragraph (d)(9) of this section. 

(4) The manufacturer must conduct 

inlet testing as specified in paragraphs 

(d)(4)(i) through (iii) of this section. 

(i) The fuel flow metering system 

must be located in accordance with 

Method 2A at 40 CFR part 60, appendix 

A–1, (or other approved procedure) to 

measure fuel flow rate at the control 

device inlet location. You must position 

the fitting for filling fuel sample 

containers a minimum of eight pipe 

diameters upstream of any inlet fuel 

flow monitoring meter. 

(ii) The manufacturer must determine 

the inlet flow rate using Method 2A at 

40 CFR part 60, appendix A–1. Record 

the start and stop reading for each 60- 

minute THC test. Record the gas 

pressure and temperature at 5-minute 

intervals throughout each 60-minute 

THC test. 

(iii) The manufacturer must conduct 

inlet fuel sampling in accordance with 

the criteria in paragraph (d)(5) of this 

section. 

(5) The manufacturer must conduct 

inlet fuel sampling as specified in 

paragraphs (d)(5)(i) and (ii) of this 

section. 

(i) At the inlet fuel sampling location, 

the manufacturer must securely connect 

a Silonite-coated stainless steel 

evacuated canister fitted with a flow 

controller sufficient to fill the canister 

over a 1 hour period. Filling must be 

conducted as specified in paragraphs 

(d)(5)(i)(A) through (C) of this section. 

(A) Open the canister sampling valve 

at the beginning of the total 

hydrocarbon test, and close the canister 

at the end of the total hydrocarbon test. 

(B) Fill one canister for each total 

hydrocarbon test run. 

(C) Label the canisters individually 

and record on a chain of custody form. 

(ii) The manufacturer must analyze 

each fuel sample using the methods in 

paragraphs (d)(5)(ii)(A) through (D) of 

this section. You must include the 

results in the test report in paragraph 

(d)(9) of this section. 

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(A) Hydrocarbon compounds 

containing between one and five atoms 

of carbon plus benzene using ASTM 

D1945–03 (Reapproved 2010) 

(incorporated by reference as specified 

in § 60.17). 

(B) Hydrogen (H2), carbon monoxide 

(CO), carbon dioxide (CO2), nitrogen 

(N2), oxygen (O2) using ASTM D1945– 

03 (Reapproved 2010) (incorporated by 

reference as specified in § 60.17). 

(C) Carbonyl sulfide, carbon disulfide 

plus mercaptans using ASTM D5504–08 

(incorporated by reference as specified 

in § 60.17). 

(D) Higher heating value using ASTM 

D3588–98 (Reapproved 2003) or ASTM 

D4891–89 (Reapproved 2006) 

(incorporated by reference as specified 

in § 60.17). 

(6) The manufacturer must conduct 

outlet testing in accordance with the 

criteria in paragraphs (d)(6)(i) through 

(iv) and (d)(7) of this section. 

(i) The manufacturer must sample and 

measure flowrate in accordance with the 

following: 

(A) The manufacturer must position 

the outlet sampling location a minimum 

of four equivalent stack diameters 

downstream from the highest peak 

flame or any other flow disturbance, and 

a minimum of one equivalent stack 

diameter upstream of the exit or any 

other flow disturbance. A minimum of 

two sample ports must be used. 

(B) The manufacturer must measure 

flow rate using Method 1 at 40 CFR part 

60, appendix A–1 for determining flow 

measurement traverse point location, 

and Method 2 at 40 CFR part 60, 

appendix A–1 for measuring duct 

velocity. If low flow conditions are 

encountered (i.e., velocity pressure 

differentials less than 0.05 inches of 

water) during the performance test, a 

more sensitive manometer must be used 

to obtain an accurate flow profile. 

(ii) The manufacturer must determine 

molecular weight as specified in 

paragraph (d)(7) of this section. 

(iii) The manufacturer must determine 

carbon monoxide using Method 10 at 40 

CFR part 60, appendix A–4 or ASTM 

D6522–00 (Reapproved 2005) 

(incorporated by reference as specified 

in § 60.17). The manufacturer must run 

the test at the same time and with the 

sample points used for the Method 25A 

at 40 CFR part 60, appendix A–7, 

testing. An instrument range of 0–10 

parts per million by volume-dry 

(ppmvd) must be used. 

(iv) The manufacturer must determine 

visible emissions using Method 22 at 40 

CFR part 60, appendix A–7. The test 

must be performed continuously during 

each test run. A digital color photograph 

of the exhaust point, taken from the 

position of the observer and annotated 

with date and time, will be taken once 

per test run and the four photos 

included in the test report. 

(7) The manufacturer must determine 

molecular weight as specified in 

paragraphs (d)(7)(i) and (ii) of this 

section. 

(i) The manufacturer must collect an 

integrated bag sample during the 

Method 4 at 40 CFR part 60, appendix 

A–3, moisture test. The manufacturer 

must analyze the bag sample using a gas 

chromatograph-thermal conductivity 

detector (GC–TCD) analysis meeting the 

criteria in paragraphs (d)(7)(i)(A) 

through (D) of this section. 

(A) Collect the integrated sample 

throughout the entire test, and collect 

representative volumes from each 

traverse location. 

(B) Purge the sampling line with stack 

gas before opening the valve and 

beginning to fill the bag. 

(C) Knead or otherwise vigorously 

mix the bag contents prior to the gas 

chromatograph analysis. 

(D) Modify the gas chromatographthermal 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 

(vii) of this section. 

(i) Conduct THC sampling using 

Method 25A at 40 CFR part 60, 

appendix A–7, except the option for 

locating the probe in the center 10 

percent of the stack is not allowed. The 

THC probe must be traversed to 16.7 

percent, 50 percent, and 83.3 percent of 

the stack diameter during the testing. 

(ii) A valid test must consist of three 

Method 25A at 40 CFR part 60, 

appendix A–7, tests, each no less than 

60 minutes in duration. 

(iii) A 0–10 parts per million by 

volume-wet (ppmvw) (as propane) 

measurement range is preferred; as an 

alternative a 0–30 ppmvw (as carbon) 

measurement range may be used. 

(iv) Calibration gases will be propane 

in air and be certified through EPA 

Protocol 1—‘‘EPA Traceability Protocol 

for Assay and Certification of Gaseous 

Calibration Standards,’’ September 

1997, as amended August 25, 1999, 

EPA–600/R–97/121. 

(v) THC measurements must be 

reported in terms of ppmvw as propane. 

(vi) THC results must be corrected to 

3 percent CO2, as measured by Method 

3C at 40 CFR part 60, appendix A–2. 

(vii) Subtraction of methane/ethane 

from the THC data is not allowed in 

determining results. 

(9) For each combustion control 

device model tested by the 

manufacturer under this section, you 

must maintain records of the 

information listed in paragraphs (d)(9)(i) 

through (vi) of this section. 

(i) A full schematic of the control 

device and dimensions of the device 

components. 

(ii) The design net heating value 

(minimum and maximum) of the device. 

(iii) The test fuel gas flow range (in 

both mass and volume). Include the 

minimum and maximum allowable inlet 

gas flow rate. 

(iv) The air/stream injection/assist 

ranges, if used. 

(v) The test parameter ranges listed in 

paragraphs (d)(9)(v)(A) through (O) of 

this section, as applicable for the tested 

model. 

(A) Fuel gas delivery pressure and 

temperature. 

(B) Fuel gas moisture range. 

(C) Purge gas usage range. 

(D) Condensate (liquid fuel) 

separation range. 

(E) Combustion zone temperature 

range. This is required for all devices 

that measure this parameter. 

(F) Excess combustion air range. 

(G) Flame arrestor(s). 

(H) Burner manifold pressure. 

(I) Pilot flame sensor. 

(J) Pilot flame design fuel and fuel 

usage. 

(K) Tip velocity range. 

(L) Momentum flux ratio. 

(M) Exit temperature range. 

(N) Exit flow rate. 

(O) Wind velocity and direction. 

(vi) You must include all calibration 

quality assurance/quality control data, 

calibration gas values, gas cylinder 

certification, and strip charts annotated 

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49556 Federal Register / Vol. 77, No. 159 / Thursday, August 16, 2012 / Rules and Regulations 

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 (2) of this section. 

(1) You must reduce VOC emissions 

from the wet seal fluid degassing system 

by 95.0 percent or greater. 

(2) If you use a control device to 

reduce emissions, you must 

demonstrate continuous compliance 

according to paragraph (e)(2) of this 

section. 

(3) You must submit the annual report 

required by 60.5420(b) and maintain the 

records as specified in § 60.5420(c)(2). 

(c) For each reciprocating compressor 

affected facility, you must demonstrate 

continuous compliance according to 

paragraphs (c)(1) through (3) of this 

section. 

(1) You must continuously monitor 

the number of hours of operation for 

each reciprocating compressor affected 

facility or track the number of months 

since initial startup, or October 15, 

2012, or the date of the most recent 

reciprocating compressor rod packing 

replacement, whichever is later. 

(2) You must submit the annual report 

as required in § 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. 

(d) For each pneumatic controller 

affected facility, you must demonstrate 

continuous compliance according to 

paragraphs (d)(1) through (3) of this 

section. 

(1) You must continuously operate the 

pneumatic controllers as required in 

§ 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 (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 

(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) through (vii) of this 

section and compliance with paragraph 

(e)(2)(viii) of this section only after at 

least 1 year of operation in compliance 

with the selected approach. You must 

provide notification of such a change in 

the compliance method in the next 

Annual Report, as required in 

§ 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 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. 

(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 (D) of 

this section. 

(A) The inlet gas flow rate must meet 

the range specified by the manufacturer. 

You must measure the flow rate as 

specified in § 60.5417(d)(1)(viii)(A). 

(B) A pilot flame must be present at 

all times of operation. You must 

monitor the pilot flame in accordance 

with § 60.5417(d)(1)(viii)(B). 

(C) You must operate the combustion 

control device with no visible 

emissions, except for periods not to 

exceed a total of 5 minutes during any 

2 consecutive hours. You must perform 

a visible emissions test using Method 22 

at 40 CFR part 60, appendix A–7 

monthly. The observation period must 

be 2 hours and must follow Method 22. 

(D) Compliance with the operating 

parameter limit is achieved when the 

criteria in paragraphs (e)(2)(vii)(D)(1) 

through (5) are met. 

(1) The inlet gas flow rate monitored 

under paragraph (e)(2)(vii)(A) of this 

section is equal to or below the 

maximum established by the 

manufacturer. 

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(2) The pilot flame is present at all 

times; and 

(3) During the visible emissions test 

performed under paragraph (e)(2)(vii)(C) 

of this section, the duration of visible 

emissions does not exceed a total of 5 

minutes during the observation period. 

Devices failing the visible emissions test 

must follow the requirements in 

paragraphs (e)(2)(vii)(D)(4) and (5) of 

this section. 

(4) Following the first failure, you 

must replace the fuel nozzle(s) and 

burner tubes. 

(5) If, following replacement of the 

fuel nozzle(s) and burner tubes as 

specified in paragraph (e)(2)(vii)(D)(4) of 

this section, the visible emissions test is 

not passed in the next scheduled test, 

you must either conduct a performance 

test as specified in § 60.5413, or replace 

the device with another control device 

whose model was tested and meets the 

requirements in § 60.5413(d). 

(viii) If you use a condenser as the 

control device to achieve the percent 

reduction performance requirements 

specified in § 60.5412(a)(2), you must 

demonstrate compliance using the 

procedures in paragraphs (e)(2)(viii)(A) 

through (E) of this section. 

(A) You must establish a site-specific 

condenser performance curve according 

to § 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 (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 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. 

(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 (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. 

(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 prevent loss of life, 

personal injury, or severe property 

damage; and 

(v) All possible steps were taken to 

minimize the impact of the violation on 

ambient air quality, the environment 

and human health; and 

(vi) All emissions monitoring and 

control systems were kept in operation 

if at all possible, consistent with safety 

and good air pollution control practices; 

and 

(vii) All of the actions in response to 

the violation were documented by 

properly signed, contemporaneous 

operating logs; and 

(viii) At all times, the affected source 

was operated in a manner consistent 

with good practices for minimizing 

emissions; and 

(ix) A written root cause analysis has 

been prepared, the purpose of which is 

to determine, correct, and eliminate the 

primary causes of the malfunction and 

the violation resulting from the 

malfunction event at issue. The analysis 

shall also specify, using best monitoring 

methods and engineering judgment, the 

amount of any emissions that were the 

result of the malfunction. 

(2) Report. The owner or operator 

seeking to assert an affirmative defense 

shall submit a written report to the 

Administrator with all necessary 

supporting documentation, that it has 

met the requirements set forth in 

paragraph (h)(1) of this section. This 

affirmative defense report shall be 

included in the first periodic 

compliance, deviation report or excess 

emission report otherwise required after 

the initial occurrence of the violation of 

the relevant standard (which may be the 

end of any applicable averaging period). 

If such compliance, deviation report or 

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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 (a)(1) 

and (2) of this section, inspect each 

cover according to the procedures and 

schedule specified in paragraph (a)(3) of 

this section, and inspect each bypass 

device according to the procedures of 

paragraph (a)(4) of this section. 

(1) For each closed vent system joint, 

seam, or other connection that is 

permanently or semi-permanently 

sealed (e.g., a welded joint between two 

sections of hard piping or a bolted and 

gasketed ducting flange), you must meet 

the requirements specified in 

paragraphs (a)(1)(i) and (ii) of this 

section. 

(i) Conduct an initial inspection 

according to the test methods and 

procedures specified in paragraph (b) of 

this section to demonstrate that the 

closed vent system operates with no 

detectable emissions. You must 

maintain records of the inspection 

results as specified in § 60.5420(c)(6). 

(ii) Conduct annual visual inspections 

for defects that could result in air 

emissions. Defects include, but are not 

limited to, visible cracks, holes, or gaps 

in piping; loose connections; or broken 

or missing caps or other closure devices. 

You must monitor a component or 

connection using the test methods and 

procedures in paragraph (b) of this 

section to demonstrate that it operates 

with no detectable emissions following 

any time the component is repaired or 

replaced or the connection is unsealed. 

You must maintain records of the 

inspection results as specified in 

§ 60.5420(c)(6). 

(2) For closed vent system 

components other than those specified 

in paragraph (a)(1) of this section, you 

must meet the requirements of 

paragraphs (a)(2)(i) through (iii) of this 

section. 

(i) Conduct an initial inspection 

according to the test methods and 

procedures specified in paragraph (b) of 

this section to demonstrate that the 

closed vent system operates with no 

detectable emissions. You must 

maintain records of the inspection 

results as specified in § 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). 

(3) For each cover, you must meet the 

requirements in paragraphs (a)(3)(i) and 

(ii) of this section. 

(i) Conduct visual inspections for 

defects that could result in air 

emissions. Defects include, but are not 

limited to, visible cracks, holes, or gaps 

in the cover, or between the cover and 

the separator wall; broken, cracked, or 

otherwise damaged seals or gaskets on 

closure devices; and broken or missing 

hatches, access covers, caps, or other 

closure devices. In the case where the 

storage vessel is buried partially or 

entirely underground, you must inspect 

only those portions of the cover that 

extend to or above the ground surface, 

and those connections that are on such 

portions of the cover (e.g., fill ports, 

access hatches, gauge wells, etc.) and 

can be opened to the atmosphere. 

(ii) You must initially conduct the 

inspections specified in paragraph 

(a)(3)(i) of this section following the 

installation of the cover. Thereafter, you 

must perform the inspection at least 

once every calendar year, except as 

provided in paragraphs (e) and (f) of this 

section. You must maintain records of 

the inspection results as specified in 

§ 60.5420(c)(7). 

(4) For each bypass device, except as 

provided for in § 60.5411, you must 

meet the requirements of paragraphs 

(a)(4)(i) or (ii) of this section. 

(i) Set the flow indicator to take a 

reading at least once every 15 minutes 

at the inlet to the bypass device that 

could divert the steam away from the 

control device to the atmosphere. 

(ii) If the bypass device valve installed 

at the inlet to the bypass device is 

secured in the non-diverting position 

using a car-seal or a lock-and-key type 

configuration, visually inspect the seal 

or closure mechanism at least once 

every month to verify that the valve is 

maintained in the non-diverting 

position and the vent stream is not 

diverted through the bypass device. You 

must maintain records of the 

inspections according to § 60.5420(c)(8). 

(b) No detectable emissions test 

methods and procedures. If you are 

required to conduct an inspection of a 

closed vent system or cover at your 

storage vessel or centrifugal compressor 

affected facility as specified in 

paragraphs (a)(1), (2), or (3) of this 

section, you must meet the requirements 

of paragraphs (b)(1) through (13) of this 

section. 

(1) You must conduct the no 

detectable emissions test procedure in 

accordance with Method 21 at 40 CFR 

part 60, appendix A–7. 

(2) The detection instrument must 

meet the performance criteria of Method 

21 at 40 CFR part 60, appendix A–7, 

except that the instrument response 

factor criteria in section 3.1.2(a) of 

Method 21 must be for the average 

composition of the fluid and not for 

each individual organic compound in 

the stream. 

(3) You must calibrate the detection 

instrument before use on each day of its 

use by the procedures specified in 

Method 21 at 40 CFR part 60, appendix 

A–7. 

(4) Calibration gases must be as 

specified in paragraphs (b)(4)(i) and (ii) 

of this section. 

(i) Zero air (less than 10 parts per 

million by volume hydrocarbon in air). 

(ii) A mixture of methane in air at a 

concentration less than 10,000 parts per 

million by volume. 

(5) You may choose to adjust or not 

adjust the detection instrument readings 

to account for the background organic 

concentration level. If you choose to 

adjust the instrument readings for the 

background level, you must determine 

the background level value according to 

the procedures in Method 21 at 40 CFR 

part 60, appendix A–7. 

(6) Your detection instrument must 

meet the performance criteria specified 

in paragraphs (b)(6)(i) and (ii) of this 

section. 

(i) Except as provided in paragraph 

(b)(6)(ii) of this section, the detection 

instrument must meet the performance 

criteria of Method 21 at 40 CFR part 60, 

appendix A–7, except the instrument 

response factor criteria in section 

3.1.2(a) of Method 21 must be for the 

average composition of the process 

fluid, not each individual volatile 

organic compound in the stream. For 

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process streams that contain nitrogen, 

air, or other inerts that are not organic 

hazardous air pollutants or volatile 

organic compounds, you must calculate 

the average stream response factor on an 

inert-free basis. 

(ii) If no instrument is available that 

will meet the performance criteria 

specified in paragraph (b)(6)(i) of this 

section, you may adjust the instrument 

readings by multiplying by the average 

response factor of the process fluid, 

calculated on an inert-free basis, as 

described in paragraph (b)(6)(i) of this 

section. 

(7) You must determine if a potential 

leak interface operates with no 

detectable emissions using the 

applicable procedure specified in 

paragraph (b)(7)(i) or (ii) of this section. 

(i) If you choose not to adjust the 

detection instrument readings for the 

background organic concentration level, 

then you must directly compare the 

maximum organic concentration value 

measured by the detection instrument to 

the applicable value for the potential 

leak interface as specified in paragraph 

(b)(8) of this section. 

(ii) If you choose to adjust the 

detection instrument readings for the 

background organic concentration level, 

you must compare the value of the 

arithmetic difference between the 

maximum organic concentration value 

measured by the instrument and the 

background organic concentration value 

as determined in paragraph (b)(5) of this 

section with the applicable value for the 

potential leak interface as specified in 

paragraph (b)(8) of this section. 

(8) A potential leak interface is 

determined to operate with no 

detectable organic emissions if the 

organic concentration value determined 

in paragraph (b)(7) of this section is less 

than 500 parts per million by volume. 

(9) Repairs. In the event that a leak or 

defect is detected, you must repair the 

leak or defect as soon as practicable 

according to the requirements of 

paragraphs (b)(9)(i) and (ii) of this 

section, except as provided in paragraph 

(d) of this section. 

(i) A first attempt at repair must be 

made no later than 5 calendar days after 

the leak is detected. 

(ii) Repair must be completed no later 

than 15 calendar days after the leak is 

detected. 

(10) Delay of repair. Delay of repair of 

a closed vent system or cover for which 

leaks or defects have been detected is 

allowed if the repair is technically 

infeasible without a shutdown, or if you 

determine that emissions resulting from 

immediate repair would be greater than 

the fugitive emissions likely to result 

from delay of repair. You must complete 

repair of such equipment by the end of 

the next shutdown. 

(11) Unsafe to inspect requirements. 

You may designate any parts of the 

closed vent system or cover as unsafe to 

inspect if the requirements in 

paragraphs (e)(1) and (2) of this section 

are met. Unsafe to inspect parts are 

exempt from the inspection 

requirements of paragraphs (a)(1) 

through (3) of this section. 

(A) You determine that the equipment 

is unsafe to inspect because inspecting 

personnel would be exposed to an 

imminent or potential danger as a 

consequence of complying with 

paragraphs (a)(1), (2), or (3) of this 

section. 

(B) You have a written plan that 

requires inspection of the equipment as 

frequently as practicable during safe-toinspect times. 

(12) Difficult to inspect requirements. 

You may designate any parts of the 

closed vent system or cover as difficult 

to inspect, if the requirements in 

paragraphs (b)(12)(i) and (ii) of this 

section are met. Difficult to inspect parts 

are exempt from the inspection 

requirements of paragraphs (a)(1) 

through (3) of this section. 

(i) You determine that the equipment 

cannot be inspected without elevating 

the inspecting personnel more than 2 

meters above a support surface. 

(ii) You have a written plan that 

requires inspection of the equipment at 

least once every 5 years. 

(13) Records. Records shall be 

maintained as specified in this section 

and in § 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 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 (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 (4) of this section. 

(1) Each continuous parameter 

monitoring system must measure data 

values at least once every hour and 

record the parameters in paragraphs 

(c)(1)(i) or (ii) of this section. 

(i) Each measured data value. 

(ii) Each block average value for each 

1-hour period or shorter periods 

calculated from all measured data 

values during each period. If values are 

measured more frequently than once per 

minute, a single value for each minute 

may be used to calculate the hourly (or 

shorter period) block average instead of 

all measured values. 

(2) You must prepare a site-specific 

monitoring plan that addresses the 

monitoring system design, data 

collection, and the quality assurance 

and quality control elements outlined in 

paragraphs (c)(2)(i) through (v) of this 

section. You must install, calibrate, 

operate, and maintain each continuous 

parameter monitoring system in 

accordance with the procedures in your 

approved site-specific monitoring plan. 

(i) The performance criteria and 

design specifications for the monitoring 

system equipment, including the sample 

interface, detector signal analyzer, and 

data acquisition and calculations. 

(ii) Sampling interface (e.g., 

thermocouple) location such that the 

monitoring system will provide 

representative measurements. 

(iii) Equipment performance checks, 

system accuracy audits, or other audit 

procedures. 

(iv) Ongoing operation and 

maintenance procedures in accordance 

with provisions in § 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 

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accordance with the site-specific 

monitoring plan. 

(d) You must install, calibrate, 

operate, and maintain a device 

equipped with a continuous recorder to 

measure the values of operating 

parameters appropriate for the control 

device as specified in either paragraph 

(d)(1), (2), or (3) of this section. 

(1) A continuous monitoring system 

that measures the operating parameters 

in paragraphs (d)(1)(i) through (viii) of 

this section, as applicable. 

(i) For a thermal vapor incinerator 

that demonstrates during the 

performance test conducted under 

§ 60.5413 that combustion zone 

temperature is an accurate indicator of 

performance, a temperature monitoring 

device equipped with a continuous 

recorder. The monitoring device must 

have a minimum accuracy of ±1 percent 

of the temperature being monitored in 

°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 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 (B) of this section. 

(A) The continuous parameter 

monitoring system must measure and 

record the average total regeneration 

stream mass flow or volumetric flow 

during each carbon bed regeneration 

cycle. The flow sensor must have a 

measurement sensitivity of 5 percent of 

the flow rate or 10 cubic feet per 

minute, whichever is greater. You must 

check the mechanical connections for 

leakage at least every month, and you 

must perform a visual inspection at least 

every 3 months of all components of the 

flow continuous parameter monitoring 

system for physical and operational 

integrity and all electrical connections 

for oxidation and galvanic corrosion if 

your flow continuous parameter 

monitoring system is not equipped with 

a redundant flow sensor; and 

(B) The continuous parameter 

monitoring system must measure and 

record the average carbon bed 

temperature for the duration of the 

carbon bed steaming cycle and measure 

the actual carbon bed temperature after 

regeneration and within 15 minutes of 

completing the cooling cycle. The 

temperature monitoring device must 

have a minimum accuracy of ±1 percent 

of the temperature being monitored in 

°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 (B) of this 

section. 

(A) The continuous monitoring 

system must measure gas flow rate at 

the inlet to the control device. The 

monitoring instrument must have an 

accuracy of ±2 percent or better. 

(B) A heat sensing monitoring device 

equipped with a continuous recorder 

that indicates the continuous ignition of 

the pilot flame. 

(2) A continuous monitoring system 

that measures the concentration level of 

organic compounds in the exhaust vent 

stream from the control device using an 

organic monitoring device equipped 

with a continuous recorder. The 

monitor must meet the requirements of 

Performance Specification 8 or 9 of 40 

CFR part 60, appendix B. You must 

install, calibrate, and maintain the 

monitor according to the manufacturer’s 

specifications. 

(3) A continuous monitoring system 

that measures operating parameters 

other than those specified in paragraph 

(d)(1) or (2) of this section, upon 

approval of the Administrator as 

specified in § 60.13(i). 

(e) You must calculate the daily 

average value for each monitored 

operating parameter for each operating 

day, using the data recorded by the 

monitoring system, except for inlet gas 

flow rate. If the emissions unit operation 

is continuous, the operating day is a 24- 

hour period. If the emissions unit 

operation is not continuous, the 

operating day is the total number of 

hours of control device operation per 

24-hour period. Valid data points must 

be available for 75 percent of the 

operating hours in an operating day to 

compute the daily average. 

(f) For each operating parameter 

monitor installed in accordance with 

the requirements of paragraph (d) of this 

section, you must comply with 

paragraph (f)(1) of this section for all 

control devices. When condensers are 

installed, you must also comply with 

paragraph (f)(2) of this section. 

(1) You must establish a minimum 

operating parameter value or a 

maximum operating parameter value, as 

appropriate for the control device, to 

define the conditions at which the 

control device must be operated to 

continuously achieve the applicable 

performance requirements of 

§ 60.5412(a). You must establish each 

minimum or maximum operating 

parameter value as specified in 

paragraphs (f)(1)(i) through (iii) of this 

section. 

(i) If you conduct performance tests in 

accordance with the requirements of 

§ 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 control device 

achieves the applicable performance 

requirements specified in § 60.5412(a), 

then you must establish the minimum 

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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 

(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 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 (6) of this 

section, then a single excursion is 

determined to have occurred for the 

control device for that operating day. 

(1) A deviation occurs when the daily 

average value of a monitored operating 

parameter is less than the minimum 

operating parameter limit (or, if 

applicable, greater than the maximum 

operating parameter limit) established 

in paragraph (f)(1) of this section. 

(2) If you meet § 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 (ii) of this section are met. 

(i) For each bypass line subject to 

§ 60.5411(a)(3)(i)(A), the flow indicator 

indicates that flow has been detected 

and that the stream has been diverted 

away from the control device to the 

atmosphere. 

(ii) For each bypass line subject to 

§ 60.5411(a)(3)(i)(B), if the seal or 

closure mechanism has been broken, the 

bypass 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 

(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 (4), and 

according to paragraphs (a)(1) and (2) of 

this section, if you own or operate one 

or more of the affected facilities 

specified in § 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), (3), and (4). 

(2)(i) If you own or operate a gas well 

affected facility, you must submit a 

notification to the Administrator no 

later than 2 days prior to the 

commencement of each well completion 

operation listing the anticipated date of 

the well completion operation. The 

notification shall include contact 

information for the owner or operator; 

the API well number, the latitude and 

longitude coordinates for each well in 

decimal degrees to an accuracy and 

precision of five (5) decimals of a degree 

using the North American Datum of 

1983; and the planned date of the 

beginning of flowback. You may submit 

the notification in writing or in 

electronic format. 

(ii) If you are subject to state 

regulations that require advance 

notification of well completions and 

you have met those notification 

requirements, then you are considered 

to have met the advance notification 

requirements of paragraph (a)(2)(i) of 

this section. 

(b) Reporting requirements. You must 

submit annual reports containing the 

information specified in paragraphs 

(b)(1) through (6) of this section to the 

Administrator and performance test 

reports as specified in paragraph (b)(7) 

of this section. The initial annual report 

is due 30 days after the end of the initial 

compliance period as determined 

according to § 60.5410. Subsequent 

annual reports are due on the same date 

each year as the initial annual report. If 

you own or operate more than one 

affected facility, you may submit one 

report for multiple affected facilities 

provided the report contains all of the 

information required as specified in 

paragraphs (b)(1) through (6) of this 

section. Annual reports may coincide 

with title V reports as long as all the 

required elements of the annual report 

are included. You may arrange with the 

Administrator a common schedule on 

which reports required by this part may 

be submitted as long as the schedule 

does not extend the reporting period. 

(1) The general information specified 

in paragraphs (b)(1)(i) through (iv) of 

this section. 

(i) The company name and address of 

the affected facility. 

(ii) An identification of each affected 

facility being included in the annual 

report. 

(iii) Beginning and ending dates of the 

reporting period. 

(iv) A certification by a responsible 

official of truth, accuracy, and 

completeness. This certification shall 

state that, based on information and 

belief formed after reasonable inquiry, 

the statements and information in the 

document are true, accurate, and 

complete. 

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(2) For each gas well affected facility, 

the information in paragraphs (b)(2)(i) 

through (ii) of this section. 

(i) Records of each well completion 

operation as specified in paragraph 

(c)(1)(i) through (iv) of this section for 

each gas well affected facility conducted 

during the reporting period. In lieu of 

submitting the records specified in 

paragraph (c)(1)(i) through (iv), the 

owner or operator may submit a list of 

the well completions with hydraulic 

fracturing completed during the 

reporting period and the records 

required by paragraph (c)(1)(v) of this 

section for each well completion. 

(ii) Records of deviations specified in 

paragraph (c)(1)(ii) of this section that 

occurred during the reporting period. 

(3) For each centrifugal compressor 

affected facility, the information 

specified in paragraphs (b)(3)(i) and (ii) 

of this section. 

(i) An identification of each 

centrifugal compressor using a wet seal 

system constructed, modified or 

reconstructed during the reporting 

period. 

(ii) Records of deviations specified in 

paragraph (c)(2) of this section that 

occurred during the reporting period. 

(iii) If required to comply with 

§ 60.5380(a)(1), the records of closed 

vent system and cover inspections 

specified in paragraph (c)(6) of this 

section. 

(4) For each reciprocating compressor 

affected facility, the information 

specified in paragraphs (b)(4)(i) through 

(ii) of this section. 

(i) The cumulative number of hours or 

operation or the number of months 

since initial startup, October 15, 2012, 

or since the previous reciprocating 

compressor rod packing replacement, 

whichever is later. 

(ii) Records of deviations specified in 

paragraph (c)(3)(iii) of this section that 

occurred during the reporting period. 

(5) For each pneumatic controller 

affected facility, the information 

specified in paragraphs (b)(5)(i) through 

(v) of this section. 

(i) An identification of each 

pneumatic controller constructed, 

modified or reconstructed during the 

reporting period, including the 

identification information specified in 

§ 60.5390(c)(2). 

(ii) If applicable, documentation that 

the use of pneumatic controller affected 

facilities with a natural gas bleed rate 

greater than 6 standard cubic feet per 

hour are required and the reasons why. 

(iii) Records of deviations specified in 

paragraph (c)(4)(v) of this section that 

occurred during the reporting period. 

(6) For each storage vessel affected 

facility, the information in paragraphs 

(b)(6)(i) through (iii) of this section. 

(i) An identification of each storage 

vessel with VOC emissions greater than 

6 tpy constructed, modified or 

reconstructed during the reporting 

period. 

(ii) Documentation that the VOC 

emission rate is less than 6 tpy for 

meeting the requirements in 

§ 60.5395(a). 

(iii) Records of deviations specified in 

paragraph (c)(5)(iii) of this section that 

occurred during the reporting period. 

(7)(i) Within 60 days after the date of 

completing each performance test (see 

§ 60.8 of this part) as required by this 

subpart you must submit the results of 

the performance tests required by this 

subpart to EPA’s WebFIRE database by 

using the Compliance and Emissions 

Data Reporting Interface (CEDRI) that is 

accessed through EPA’s Central Data 

Exchange (CDX) (www.epa.gov/cdx). 

Performance test data must be submitted 

in the file format generated through use 

of EPA’s Electronic Reporting Tool 

(ERT) (see http://www.epa.gov/ttn/chief/ 

ert/index.html). Only data collected 

using test methods on the ERT Web site 

are subject to this requirement for 

submitting reports electronically to 

WebFIRE. Owners or operators who 

claim that some of the information being 

submitted for performance tests is 

confidential business information (CBI) 

must submit a complete ERT file 

including information claimed to be CBI 

on a compact disk or other commonly 

used electronic storage media 

(including, but not limited to, flash 

drives) to EPA. The electronic media 

must be clearly marked as CBI and 

mailed to U.S. EPA/OAPQS/CORE CBI 

Office, Attention: WebFIRE 

Administrator, MD C404–02, 4930 Old 

Page Rd., Durham, NC 27703. The same 

ERT file with the CBI omitted must be 

submitted to EPA via CDX as described 

earlier in this paragraph. At the 

discretion of the delegated authority, 

you must also submit these reports, 

including the confidential business 

information, to the delegated authority 

in the format specified by the delegated 

authority. 

(ii) All reports required by this 

subpart not subject to the requirements 

in paragraph (a)(2)(i) of this section 

must be sent to the Administrator at the 

appropriate address listed in § 63.13 of 

this part. The Administrator or the 

delegated authority may request a report 

in any form suitable for the specific case 

(e.g., by commonly used electronic 

media such as Excel spreadsheet, on CD 

or hard copy). The Administrator retains 

the right to require submittal of reports 

subject to paragraph (a)(2)(i) and (ii) of 

this section in paper format. 

(c) Recordkeeping requirements. You 

must maintain the records identified as 

specified in § 60.7(f) and in paragraphs 

(c)(1) through (10) of this section. All 

records must be maintained for at least 

5 years. 

(1) The records for each gas well 

affected facility as specified in 

paragraphs (c)(1)(i) through (v) of this 

section. 

(i) Records identifying each well 

completion operation for each gas well 

affected facility; 

(ii) Records of deviations in cases 

where well completion operations with 

hydraulic fracturing were not performed 

in compliance with the requirements 

specified in § 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 (B) of this section. 

(A) For each gas well affected facility 

required to comply with the 

requirements of § 60.5375(a), you must 

record: The location of the well; the API 

well number; the duration of flowback; 

duration of recovery to the flow line; 

duration of combustion; duration of 

venting; 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 (3), records of the 

digital photograph as specified in 

§ 60.5410(a)(4). 

(2) For each centrifugal compressor 

affected facility, you must maintain 

records of deviations in cases where the 

centrifugal compressor was not operated 

in compliance with the requirements 

specified in § 60.5380. 

(3) For each reciprocating 

compressors affected facility, you must 

maintain the records in paragraphs 

(c)(3)(i) through (iii) of this section. 

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Federal Register / Vol. 77, No. 159 / Thursday, August 16, 2012 / Rules and Regulations 49563 

(i) Records of the cumulative number 

of hours of operation or number of 

months since initial startup or October 

15, 2012, or the previous replacement of 

the reciprocating compressor rod 

packing, whichever is later. 

(ii) Records of the date and time of 

each reciprocating compressor rod 

packing replacement. 

(iii) Records of deviations in cases 

where the reciprocating compressor was 

not operated in compliance with the 

requirements specified in § 60.5385. 

(4) For each pneumatic controller 

affected facility, you must maintain the 

records identified in paragraphs (c)(4)(i) 

through (v) of this section. 

(i) Records of the date, location and 

manufacturer specifications for each 

pneumatic controller constructed, 

modified or reconstructed. 

(ii) Records of the demonstration that 

the use of pneumatic controller affected 

facilities with a natural gas bleed rate 

greater than 6 standard cubic feet per 

hour are required and the reasons why. 

(iii) If the pneumatic controller is not 

located at a natural gas processing plant, 

records of the manufacturer’s 

specifications indicating that the 

controller is designed such that natural 

gas bleed rate is less than or equal to 6 

standard cubic feet per hour. 

(iv) If the pneumatic controller is 

located at a natural gas processing plant, 

records of the documentation that the 

natural gas bleed rate is zero. 

(v) Records of deviations in cases 

where the pneumatic controller was not 

operated in compliance with the 

requirements specified in § 60.5390. 

(5) For each storage vessel affected 

facility, you must maintain the records 

identified in paragraphs (c)(5)(i) through 

(iv) of this section. 

(i) If required to reduce emissions by 

complying with § 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. 

(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. 

(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 (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 

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. 

(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 § 60.482–4a(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): 

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49564 Federal Register / Vol. 77, No. 159 / Thursday, August 16, 2012 / Rules and Regulations 

(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: 

(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 

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. 

Alaskan North Slope means the 

approximately 69,000 square-mile area 

extending from the Brooks Range to the 

Arctic Ocean. 

API Gravity means the weight per unit 

volume of hydrocarbon liquids as 

measured by a system recommended by 

the American Petroleum Institute (API) 

and is expressed in degrees. 

Bleed rate means the rate in standard 

cubic feet per hour at which natural gas 

is continuously vented (bleeds) from a 

pneumatic controller. 

Centrifugal compressor means any 

machine for raising the pressure of a 

natural gas by drawing in low pressure 

natural gas and discharging significantly 

higher pressure natural gas by means of 

mechanical rotating vanes or impellers. 

Screw, sliding vane, and liquid ring 

compressors are not centrifugal 

compressors for the purposes of this 

subpart. 

City gate means the delivery point at 

which natural gas is transferred from a 

transmission pipeline to the local gas 

utility. 

Completion combustion device means 

any ignition device, installed 

horizontally or vertically, used in 

exploration and production operations 

to combust otherwise vented emissions 

from completions. 

Compressor station means any 

permanent combination of one or more 

compressors that move natural gas at 

increased pressure from fields, in 

transmission pipelines, or into storage. 

Continuous bleed means a continuous 

flow of pneumatic supply natural gas to 

the process control device (e.g., level 

control, temperature control, pressure 

control) where the supply gas pressure 

is modulated by the process condition, 

and then flows to the valve controller 

where the signal is compared with the 

process set-point to adjust gas pressure 

in the valve actuator. 

Custody transfer means the transfer of 

natural gas after processing and/or 

treatment in the producing operations, 

or from storage vessels or automatic 

transfer facilities or other such 

equipment, including product loading 

racks, to pipelines or any other forms of 

transportation. 

Dehydrator means a device in which 

an absorbent directly contacts a natural 

gas stream and absorbs water in a 

contact tower or absorption column 

(absorber). 

Deviation means any instance in 

which an affected source subject to this 

subpart, or an owner or operator of such 

a source: 

(1) Fails to meet any requirement or 

obligation established by this subpart 

including, but not limited to, any 

emission limit, operating limit, or work 

practice standard; 

(2) Fails to meet any term or condition 

that is adopted to implement an 

applicable requirement in this subpart 

and that is included in the operating 

permit for any affected source required 

to obtain such a permit; or 

(3) Fails to meet any emission limit, 

operating limit, or work practice 

standard in this subpart during startup, 

shutdown, or malfunction, regardless of 

whether or not such failure is permitted 

by this subpart. 

Delineation well means a well drilled 

in order to determine the boundary of a 

field or producing reservoir. 

Equipment means each pump, 

pressure relief device, open-ended valve 

or line, valve, and flange or other 

connector that is in VOC service or in 

wet gas service, and any device or 

system required by this subpart. 

Field gas means feedstock gas 

entering the natural gas processing 

plant. 

Field gas gathering means the system 

used transport field gas from a field to 

the main pipeline in the area. 

Flare means a thermal oxidation 

system using an open (without 

enclosure) flame. Completion 

combustion devices as defined in this 

section are not considered flares. 

Flow line means a pipeline used to 

transport oil and/or gas from the well to 

a processing facility, a mainline 

pipeline, re-injection, or other useful 

purpose. 

Flowback means the process of 

allowing fluids to flow from a natural 

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gas well following a treatment, either in 

preparation for a subsequent phase of 

treatment or in preparation for cleanup 

and returning the well to production. 

The flowback period begins when 

material introduced into the well during 

the treatment returns to the surface 

immediately following hydraulic 

fracturing or refracturing. The flowback 

period ends with either well shut in or 

when the well is producing 

continuously to the flow line or to a 

storage vessel for collection, whichever 

occurs first. 

Gas processing plant process unit 

means equipment assembled for the 

extraction of natural gas liquids from 

field gas, the fractionation of the liquids 

into natural gas products, or other 

operations associated with the 

processing of natural gas products. A 

process unit can operate independently 

if supplied with sufficient feed or raw 

materials and sufficient storage facilities 

for the products. 

Gas well or natural gas well means an 

onshore well drilled principally for 

production of natural gas. 

Hydraulic fracturing or refracturing 

means the process of directing 

pressurized fluids containing any 

combination of water, proppant, and 

any added chemicals to penetrate tight 

formations, such as shale or coal 

formations, that subsequently require 

high rate, extended flowback to expel 

fracture fluids and solids during 

completions. 

Hydraulic refracturing means 

conducting a subsequent hydraulic 

fracturing operation at a well that has 

previously undergone a hydraulic 

fracturing operation. 

In light liquid service means that the 

piece of equipment contains a liquid 

that meets the conditions specified in 

§ 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, noncorrosive and non-toxic. 

Low pressure gas well means a well 

with reservoir pressure and vertical well 

depth such that 0.445 times the 

reservoir pressure (in psia) minus 0.038 

times the vertical well depth (in feet) 

minus 67.578 psia is less than the flow 

line pressure at the sales meter. 

Natural gas-driven pneumatic 

controller means a pneumatic controller 

powered by pressurized natural gas. 

Natural gas liquids means the 

hydrocarbons, such as ethane, propane, 

butane, and pentane that are extracted 

from field gas. 

Natural gas processing plant (gas 

plant) means any processing site 

engaged in the extraction of natural gas 

liquids from field gas, fractionation of 

mixed natural gas liquids to natural gas 

products, or both. A Joule-Thompson 

valve, a dew point depression valve, or 

an isolated or standalone 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 system, storage area, or other 

wholesale source of gas to one or more 

distribution area(s). 

Nonfractionating plant means any gas 

plant that does not fractionate mixed 

natural gas liquids into natural gas 

products. 

Non-natural gas-driven pneumatic 

controller means an instrument that is 

actuated using other sources of power 

than pressurized natural gas; examples 

include solar, electric, and instrument 

air. 

Onshore means all facilities except 

those that are located in the territorial 

seas or on the outer continental shelf. 

Pneumatic controller means an 

automated instrument used for 

maintaining a process condition such as 

liquid level, pressure, delta-pressure 

and temperature. 

Pressure vessel means a storage vessel 

that is used to store liquids or gases and 

is designed not to vent to the 

atmosphere as a result of compression of 

the vapor headspace in the pressure 

vessel during filling of the pressure 

vessel to its design capacity. 

Process unit means components 

assembled for the extraction of natural 

gas liquids from field gas, the 

fractionation of the liquids into natural 

gas products, or other operations 

associated with the processing of 

natural gas products. A process unit can 

operate independently if supplied with 

sufficient feed or raw materials and 

sufficient storage facilities for the 

products. 

Reciprocating compressor means a 

piece of equipment that increases the 

pressure of a process gas by positive 

displacement, employing linear 

movement of the driveshaft. 

Reciprocating compressor rod packing 

means a series of flexible rings in 

machined metal cups that fit around the 

reciprocating compressor piston rod to 

create a seal limiting the amount of 

compressed natural gas that escapes to 

the atmosphere. 

Reduced emissions completion means 

a well completion following fracturing 

or refracturing where gas flowback that 

is otherwise vented is captured, 

cleaned, and routed to the flow line or 

collection system, re-injected into the 

well or another well, used as an on-site 

fuel source, or used for other useful 

purpose that a purchased fuel or raw 

material would serve, with no direct 

release to the atmosphere. 

Reduced sulfur compounds means 

H2S, carbonyl sulfide (COS), and carbon 

disulfide (CS2). 

Responsible official means one of the 

following: 

(1) For a corporation: A president, 

secretary, treasurer, or vice-president of 

the corporation in charge of a principal 

business function, or any other person 

who performs similar policy or 

decision-making functions for the 

corporation, or a duly authorized 

representative of such person if the 

representative is responsible for the 

overall operation of one or more 

manufacturing, production, or operating 

facilities applying for or subject to a 

permit and either: 

(i) The facilities employ more than 

250 persons or have gross annual sales 

or expenditures exceeding $25 million 

(in second quarter 1980 dollars); or 

(ii) The delegation of authority to 

such representatives is approved in 

advance by the permitting authority; 

(2) For a partnership or sole 

proprietorship: A general partner or the 

proprietor, respectively; 

(3) For a municipality, State, Federal, 

or other public agency: Either a 

principal executive officer or ranking 

elected official. For the purposes of this 

part, a principal executive officer of a 

Federal agency includes the chief 

executive officer having responsibility 

for the overall operations of a principal 

geographic unit of the agency (e.g., a 

Regional Administrator of EPA); or 

(4) For affected facilities: 

(i) The designated representative in so 

far as actions, standards, requirements, 

or prohibitions under title IV of the 

Clean Air Act or the regulations 

promulgated thereunder are concerned; 

or 

(ii) The designated representative for 

any other purposes under part 60. 

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Routed to a process or route to a 

process means the emissions are 

conveyed via a closed vent system to 

any enclosed portion of a process unit 

where the emissions are predominantly 

recycled and/or consumed in the same 

manner as a material that fulfills the 

same function in the process and/or 

transformed by chemical reaction into 

materials that are not regulated 

materials and/or incorporated into a 

product; and/or recovered. 

Salable quality gas means natural gas 

that meets the composition, moisture, or 

other limits set by the purchaser of the 

natural gas, regardless of whether such 

gas is sold. 

Storage vessel means a unit that is 

constructed primarily of nonearthen 

materials (such as wood, concrete, steel, 

fiberglass, or plastic) which provides 

structural support and is designed to 

contain an accumulation of liquids or 

other materials. The following are not 

considered storage vessels: 

(1) Vessels that are skid-mounted or 

permanently attached to something that 

is mobile (such as trucks, railcars, 

barges or ships), and are intended to be 

located at a site for less than 180 

consecutive days. If you do not keep or 

are not able to produce records, as 

required by § 60.5420(c)(5)(iv), showing 

that the vessel has been located at a site 

for less than 180 consecutive days, the 

vessel described herein is considered to 

be a storage vessel since the original 

vessel was first located at the site. 

(2) Process vessels such as surge 

control vessels, bottoms receivers or 

knockout vessels. 

(3) Pressure vessels designed to 

operate in excess of 204.9 kilopascals 

and without emissions to the 

atmosphere. 

Sulfur production rate means the rate 

of liquid sulfur accumulation from the 

sulfur recovery unit. 

Sulfur recovery unit means a process 

device that recovers element sulfur from 

acid gas. 

Surface site means any combination 

of one or more graded pad sites, gravel 

pad sites, foundations, platforms, or the 

immediate physical location upon 

which equipment is physically affixed. 

Sweetening unit means a process 

device that removes hydrogen sulfide 

and/or carbon dioxide from the sour 

natural gas stream. 

Total Reduced Sulfur (TRS) means the 

sum of the sulfur compounds hydrogen 

sulfide, methyl mercaptan, dimethyl 

sulfide, and dimethyl disulfide as 

measured by Method 16 of appendix A 

to part 60 of this chapter. 

Total SO2 equivalents means the sum 

of volumetric or mass concentrations of 

the sulfur compounds obtained by 

adding the quantity existing as SO2 to 

the quantity of SO2 that would be 

obtained if all reduced sulfur 

compounds were converted to SO2

(ppmv or kg/dscm (lb/dscf)). 

Underground storage vessel means a 

storage vessel stored below ground. 

Well means an oil or gas well, a hole 

drilled for the purpose of producing oil 

or gas, or a well into which fluids are 

injected. 

Well completion means the process 

that allows for the flowback of 

petroleum or natural gas from newly 

drilled wells to expel drilling and 

reservoir fluids and tests the reservoir 

flow characteristics, which may vent 

produced hydrocarbons to the 

atmosphere via an open pit or tank. 

Well completion operation means any 

well completion with hydraulic 

fracturing or refracturing occurring at a 

gas well affected facility. 

Well site means one or more areas that 

are directly disturbed during the drilling 

and subsequent operation of, or affected 

by, production facilities directly 

associated with any oil well, gas well, 

or injection well and its associated well 

pad. 

Wellhead means the piping, casing, 

tubing and connected valves protruding 

above the earth’s surface for an oil and/ 

or natural gas well. The wellhead ends 

where the flow line connects to a 

wellhead valve. The wellhead does not 

include other equipment at the well site 

except for any conveyance through 

which gas is vented to the atmosphere. 

Wildcat well means a well outside 

known fields or the first well drilled in 

an oil or gas field where no other oil and 

gas production exists. 

TABLE 1 TO SUBPART OOOO OF PART 60—REQUIRED MINIMUM INITIAL SO2 EMISSION REDUCTION EFFICIENCY (Zi) 

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) 

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 

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. 

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X = The sulfur feed rate from the sweetening unit (i.e., the H2S in the acid gas), expressed as sulfur, Mg/D(LT/D), rounded to one decimal 

place. 

Y = The sulfur content of the acid gas from the sweetening unit, expressed as mole percent H2S (dry basis) rounded to one decimal place. 

Z = The minimum required sulfur dioxide (SO2) emission reduction efficiency, expressed as percent carried to one decimal place. Zi refers to 

the reduction efficiency required at the initial performance test. Zc refers to the reduction efficiency required on a continuous basis after compliance with Zi has been demonstrated. 

As stated in § 60.5425, you must 

comply with the following applicable 

General Provisions: 

TABLE 3 TO SUBPART OOOO OF PART 60—APPLICABILITY OF GENERAL PROVISIONS TO SUBPART OOOO 

General 

provisions 

citation 

Subject of citation Applies to 

subpart? Explanation 

§ 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. 

§ 60.19 .............. General notification and reporting requirement ........ Yes. 

PART 63—NATIONAL EMISSION 

STANDARDS FOR HAZARDOUS AIR 

POLLUTANTS FOR SOURCE 

CATEGORIES 

■ 8. The authority citation for part 63 

continues to read as follows: 

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

■ 9. Section 63.14 is amended by: 

■ a. Revising paragraphs (b) 

introductory text, (b)(28), and (b)(64); 

■ b. Adding paragraphs (b)(73), (74), 

and (75); and 

■ c. Revising paragraphs (i) introductory 

text and (i)(1) to read as follows: 

§ 63.14 Incorporations by reference. 

* * * * * 

(b) The following materials are 

available for purchase from at least one 

of the following addresses: American 

Society for Testing and Materials 

(ASTM), 100 Barr Harbor Drive, Post 

Office Box C700, West Conshohocken, 

PA 19428–2959, Telephone (610) 832– 

9585, and are also available at the 

following Web site: http:// 

www.astm.org; or ProQuest, 789 East 

Eisenhower Parkway, Ann Arbor, MI 

48106–1346, Telephone (734) 761–4700, 

and are also available at the following 

Web site: http://www.proquest.com. 

* * * * * 

(28) ASTM D6420–99 (Reapproved 

2004), Standard Test Method for 

Determination of Gaseous Organic 

Compounds by Direct Interface Gas 

Chromatography-Mass Spectrometry 

(Approved October 1, 2004), IBR 

approved for §§ 60.485(g), 60.485a(g), 

63.772(a), 63.772(e), 63.1282(a), 

63.1282(d), 63.2351(b), 63.2354(b) and 

table 8 to subpart HHHHHHH of this 

part. 

* * * * * 

(64) ASTM D6522–00 (Reapproved 

2005), Standard Test Method for 

Determination of Nitrogen Oxides, 

Carbon Monoxide, and Oxygen 

Concentrations in Emissions from 

Natural Gas Fired Reciprocating 

Engines, Combustion Turbines, Boilers, 

and Process Heaters Using Portable 

Analyzers, approved October 1, 2005, 

IBR approved for table 4 to subpart 

ZZZZ of this part, table 5 to subpart 

DDDDD of this part, table 4 to subpart 

JJJJJJ of this part and §§ 63.772(e), 

63.772(h), 63.1282(d) and 63.1282(g). 

* * * * * 

(73) ASTM D1945–03 (Reapproved 

2010) Standard Test Method for 

Analysis of Natural Gas by Gas 

Chromatography (Approved January 1, 

2010), IBR approved for §§ 63.772(h) 

and 63.1282(g). 

(74) ASTM D3588–98 (Reapproved 

2003) Standard Practice for Calculating 

Heat Value, Compressibility Factor, and 

Relative Density of Gaseous Fuels 

(Approved May 10, 2003), IBR approved 

for §§ 63.772(h) and 63.1282(g). 

(75) ASTM D4891–89 (Reapproved 

2006) Standard Test Method for Heating 

Value of Gases in Natural Gas Range by 

Stoichiometric Combustion (Approved 

June 1, 2006), IBR approved for 

§§ 63.772(h) and 63.1282(g). 

* * * * * 

(i) The following material is available 

for purchase from at least one of the 

following addresses: American Society 

of Mechanical Engineers (ASME), Three 

Park Avenue, New York, NY 10016– 

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5990, Telephone (800) 843–2763, and 

are also available at the following Web 

site: http://www.asme.org; or HIS, 

Incorporated, 15 Inverness Way East, 

Englewood, CO 80112, Telephone (877) 

413–5184, and are also available at the 

following Web site: http:// 

global.ihs.com. 

(1) ANSI/ASME PTC 19.10–1981, 

Flue and Exhaust Gas Analyses [Part 10, 

Instruments and Apparatus], issued 

August 31, 1981 IBR approved for 

§§ 63.309(k), 63.772(e), 63.772(h), 

63.865(b), 63.1282(d), 63.1282(g), 

63.3166(a), 63.3360(e), 63.3545(a), 

63.3555(a), 63.4166(a), 63.4362(a), 

63.4766(a), 63.4965(a), 63.5160(d), 

63.9307(c), 63.9323(a), 63.11148(e), 

63.11155(e), 63.11162(f), 63.11163(g), 

63.11410(j), 63.11551(a) and 

63.11646(a), 63.11945, table 5 to subpart 

DDDDD of this part, table 4 to subpart 

JJJJJ of this part, table 5 to subpart 

UUUUU of this part and table 1 to 

subpart ZZZZZ of this part. 

* * * * * 

Subpart HH—[Amended] 

■ 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). 

The revisions and additions 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 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 October 15, 2012, the owner or 

operator shall calculate the maximum 

natural gas or hydrocarbon liquid 

throughput used to determine maximum 

potential emissions according to the 

requirements specified in paragraph 

(a)(1)(i)(A) of this section. In all other 

circumstances, the owner or operator 

shall calculate the maximum 

throughput used to determine whether a 

facility is a major source in accordance 

with the requirements specified in 

paragraph (a)(1)(i)(B) of this section. 

(A) The maximum natural gas or 

hydrocarbon liquid throughput is the 

average of the annual natural gas or 

hydrocarbon liquid throughput for the 3 

years prior to October 15, 2012, 

multiplied by a factor of 1.2. 

(B) The maximum natural gas or 

hydrocarbon liquid throughput is the 

highest annual natural gas or 

hydrocarbon liquid throughput over the 

5 years prior to October 15, 2012, 

multiplied by a factor of 1.2. 

* * * * * 

(iii) The owner or operator shall 

determine the maximum values for 

other parameters used to calculate 

emissions as the maximum for the 

period over which the maximum natural 

gas or hydrocarbon liquid throughput is 

determined in accordance with 

paragraph (a)(1)(i)(A) or (B) of this 

section. Parameters, other than glycol 

circulation rate, shall be based on either 

highest measured values or annual 

average. For estimating maximum 

potential emissions from glycol 

dehydration units, the glycol circulation 

rate used in the calculation shall be the 

unit’s maximum rate under its physical 

and operational design consistent with 

the definition of potential to emit in 

§ 63.2. 

(2) Facilities that process, upgrade, or 

store hydrocarbon liquids. 

* * * * * 

(b) * * * 

(1) * * * 

(i) Each glycol dehydration unit as 

specified in paragraphs (b)(1)(i)(A) 

through (C) of this section. 

(A) Each large glycol dehydration 

unit; 

(B) Each small glycol dehydration 

unit for which construction commenced 

on or before August 23, 2011, is an 

existing small glycol dehydration unit; 

and 

(C) Each small glycol dehydration 

unit for which construction commenced 

after August 23, 2011, is a new small 

glycol dehydration unit. 

* * * * * 

(c) Any source that determines it is 

not a major source but has actual 

emissions of 5 tons per year or more of 

a single HAP, or 12.5 tons per year or 

more of a combination of HAP (i.e., 50 

percent of the major source thresholds), 

shall update its major source 

determination within 1 year of the prior 

determination or October 15, 2012, 

whichever is later, and each year 

thereafter, using gas composition data 

measured during the preceding 12 

months. 

* * * * * 

(f) The owner or operator of an 

affected major source shall achieve 

compliance with the provisions of this 

subpart by the dates specified in 

paragraphs (f)(1), (2), and (f)(7) through 

(9) of this section. The owner or 

operator of an affected area source shall 

achieve compliance with the provisions 

of this subpart by the dates specified in 

paragraphs (f)(3) through (6) of this 

section. 

(1) Except as specified in paragraphs 

(f)(7) through (9) of this section, the 

owner or operator of an affected major 

source, the construction or 

reconstruction of which commenced 

before February 6, 1998, shall achieve 

compliance with the applicable 

provisions of this subpart no later than 

June 17, 2002, except as provided for in 

§ 63.6(i). The owner or operator of an 

area source, the construction or 

reconstruction of which commenced 

before February 6, 1998, that increases 

its emissions of (or its potential to emit) 

HAP such that the source becomes a 

major source that is subject to this 

subpart shall comply with this subpart 

3 years after becoming a major source. 

(2) Except as specified in paragraphs 

(f)(7) through (9) of this section, the 

owner or operator of an affected major 

source, the construction or 

reconstruction of which commences on 

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Federal Register / Vol. 77, No. 159 / Thursday, August 16, 2012 / Rules and Regulations 49569 

or after February 6, 1998, shall achieve 

compliance with the applicable 

provisions of this subpart immediately 

upon initial startup or June 17, 1999, 

whichever date is later. Area sources, 

other than production field facilities 

identified in (f)(9) of this section, the 

construction or reconstruction of which 

commences on or after February 6, 1998, 

that become major sources shall comply 

with the provisions of this standard 

immediately upon becoming a major 

source. 

* * * * * 

(7) Each affected existing small glycol 

dehydration unit, as defined in § 63.761, 

located at a major source, that 

commenced construction before August 

23, 2011, must achieve compliance no 

later than October 15, 2015, except as 

provided in § 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 October 15, 2012, 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 

October 15, 2012 must achieve 

compliance no later than October 15, 

2015, except as provided in § 63.6(i). 

* * * * * 

■ 11. Section 63.761 is amended by: 

■ a. Adding, in alphabetical order, 

definitions for the terms ‘‘affirmative 

defense,’’ ‘‘BTEX,’’ ‘‘flare,’’ ‘‘large glycol 

dehydration unit,’’ ‘‘responsible 

official’’ and ‘‘small glycol dehydration 

unit’’; 

■ 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: 

§ 63.761 Definitions. 

* * * * * 

Affirmative defense means, in the 

context of an enforcement proceeding, a 

response or defense put forward by a 

defendant, regarding which the 

defendant has the burden of proof, and 

the merits of which are independently 

and objectively evaluated in a judicial 

or administrative proceeding. 

* * * * * 

Associated equipment, as used in this 

subpart and as referred to in section 

112(n)(4) of the Act, means equipment 

associated with an oil or natural gas 

exploration or production well, and 

includes all equipment from the 

wellbore to the point of custody 

transfer, except glycol dehydration units 

and storage vessels. 

* * * * * 

BTEX means benzene, toluene, ethyl 

benzene and xylene. 

* * * * * 

Flare means a thermal oxidation 

system using an open flame (i.e., 

without enclosure). 

* * * * * 

Glycol dehydration unit baseline 

operations means operations 

representative of the large glycol 

dehydration unit operations as of June 

17, 1999 and the small glycol 

dehydrator unit operations as of August 

23, 2011. For the purposes of this 

subpart, for determining the percentage 

of overall HAP emission reduction 

attributable to process modifications, 

baseline operations shall be parameter 

values (including, but not limited to, 

glycol circulation rate or glycol-HAP 

absorbency) that represent actual longterm 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 

emissions from all HAP emission units 

shall be aggregated for a major source 

determination. 

* * * * * 

Responsible official means one of the 

following: 

(1) For a corporation: A president, 

secretary, treasurer, or vice-president of 

the corporation in charge of a principal 

business function, or any other person 

who performs similar policy or 

decision-making functions for the 

corporation, or a duly authorized 

representative of such person if the 

representative is responsible for the 

overall operation of one or more 

manufacturing, production, or operating 

facilities applying for or subject to a 

permit and either: 

(i) The facilities employ more than 

250 persons or have gross annual sales 

or expenditures exceeding $25 million 

(in second quarter 1980 dollars); or 

(ii) The delegation of authority to 

such representatives is approved in 

advance by the permitting authority; 

(2) For a partnership or sole 

proprietorship: a general partner or the 

proprietor, respectively; 

(3) For a municipality, State, Federal, 

or other public agency: Either a 

principal executive officer or ranking 

elected official. For the purposes of this 

part, a principal executive officer of a 

Federal agency includes the chief 

executive officer having responsibility 

for the overall operations of a principal 

geographic unit of the agency (e.g., a 

Regional Administrator of EPA); or 

(4) For affected sources: 

(i) The designated representative in so 

far as actions, standards, requirements, 

or prohibitions under title IV of the Act 

or the regulations promulgated 

thereunder are concerned; and 

(ii) The designated representative for 

any other purposes under part 70. 

* * * * * 

Small glycol dehydration unit means 

a glycol dehydration unit, located at a 

major source, with an actual annual 

average natural gas flowrate less than 85 

thousand standard cubic meters per day 

or actual annual average benzene 

emissions less than 0.90 Mg/yr, 

determined according to § 63.772(b). 

* * * * * 

Storage vessel means a tank or other 

vessel that is designed to contain an 

accumulation of crude oil, condensate, 

intermediate hydrocarbon liquids, or 

produced water and that is constructed 

primarily of non-earthen materials (e.g., 

wood, concrete, steel, plastic) that 

provide structural support. The 

following process units are not 

considered storage vessels: Surge 

control vessels and knockout vessels. 

* * * * * 

■ 12. Section 63.762 is revised to read 

as follows: 

§ 63.762 Affirmative defense for violations 

of emission 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 

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49570 Federal Register / Vol. 77, No. 159 / Thursday, August 16, 2012 / Rules and Regulations 

a claim for civil penalties for violations 

of such standards that are caused by 

malfunction, as defined in 40 CFR 63.2. 

Appropriate penalties may be assessed; 

however, if you fail to meet your burden 

of proving all of the requirements in the 

affirmative defense, the affirmative 

defense shall not be available for claims 

for injunctive relief. 

(1) To establish the affirmative 

defense in any action to enforce such a 

standard, you must timely meet the 

reporting requirements in paragraph 

(d)(2) of this section, and must prove by 

a preponderance of evidence that: 

(i) The violation: 

(A) Was caused by a sudden, 

infrequent, and unavoidable failure of 

air pollution control equipment, process 

equipment, or a process to operate in a 

normal or usual manner; and 

(B) Could not have been prevented 

through careful planning, proper design 

or better operation and maintenance 

practices; and 

(C) Did not stem from any activity or 

event that could have been foreseen and 

avoided, or planned for; and 

(D) Was not part of a recurring pattern 

indicative of inadequate design, 

operation, or maintenance; and 

(ii) Repairs were made as 

expeditiously as possible when a 

violation occurred. Off-shift and 

overtime labor were used, to the extent 

practicable to make these repairs; and 

(iii) The frequency, amount and 

duration of the violation (including any 

bypass) were minimized to the 

maximum extent practicable; and 

(iv) If the violation resulted from a 

bypass of control equipment or a 

process, then the bypass was 

unavoidable to prevent loss of life, 

personal injury, or severe property 

damage; and 

(v) All possible steps were taken to 

minimize the impact of the violation on 

ambient air quality, the environment, 

and human health; and 

(vi) All emissions monitoring and 

control systems were kept in operation 

if at all possible, consistent with safety 

and good air pollution control practices; 

and 

(vii) All of the actions in response to 

the violation were documented by 

properly signed, contemporaneous 

operating logs; and 

(viii) At all times, the affected source 

was operated in a manner consistent 

with good practices for minimizing 

emissions; and 

(ix) A written root cause analysis has 

been prepared, the purpose of which is 

to determine, correct, and eliminate the 

primary causes of the malfunction and 

the violation resulting from the 

malfunction event at issue. The analysis 

shall also specify, using best monitoring 

methods and engineering judgment, the 

amount of any emissions that were the 

result of the malfunction. 

(2) Report. The owner or operator 

seeking to assert an affirmative defense 

shall submit a written report to the 

Administrator with all necessary 

supporting documentation, that it has 

met the requirements set forth in 

paragraph (d)(1) of this section. This 

affirmative defense report shall be 

included in the first periodic 

compliance, deviation report or excess 

emission report otherwise required after 

the initial occurrence of the violation of 

the relevant standard (which may be the 

end of any applicable averaging period). 

If such compliance, deviation report or 

excess emission report is due less than 

45 days after the initial occurrence of 

the violation, the affirmative defense 

report may be included in the second 

compliance, deviation report or excess 

emission report due after the initial 

occurrence of the violation of the 

relevant standard. 

■ 13. Section 63.764 is amended by: 

■ a. Revising paragraph (e)(1) 

introductory text; 

■ b. Revising paragraph (i); and 

■ c. Adding paragraph (j). 

The revisions and addition 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 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). 

The revisions read as follows: 

§ 63.765 Glycol dehydration unit process 

vent standards. 

(a) This section applies to each glycol 

dehydration unit subject to this subpart 

that must be controlled for air emissions 

as specified in either paragraph (c)(1)(i) 

or paragraph (d)(1)(i) of § 63.764. 

(b) * * * 

(1) For each glycol dehydration unit 

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 

§ 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 

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with one of the alternatives specified in paragraphs (b)(1)(iii)(A) through (D) of 

this section. 

Equation 1 

Where: 

ELBTEX = Unit-specific BTEX emission limit, 

megagrams per year; 

3.28 × 10¥4 = BTEX emission limit, grams 

BTEX/standard cubic meter-ppmv; 

Throughput = Annual average daily natural 

gas throughput, standard cubic meters 

per day. 

Ci,BTEX = average annual BTEX concentration 

of the natural gas at the inlet to the 

glycol dehydration unit, ppmv. 

Where: 

ELBTEX = Unit-specific BTEX emission limit, 

megagrams per year; 

4.66 × 10¥6 = BTEX emission limit, grams 

BTEX/standard cubic meter-ppmv; 

Throughput = Annual average daily natural 

gas throughput, standard cubic meters 

per day. 

Ci,BTEX = average annual BTEX concentration 

of the natural gas at the inlet to the 

glycol dehydration unit, ppmv. 

(A) Connect the process vent to a 

control device or combination of control 

devices through a closed-vent system. 

The closed vent system shall be 

designed and operated in accordance 

with the requirements of § 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). 

* * * * * 

(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. 

(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 

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). 

The revisions 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 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 October 15, 2013, whichever is later. 

A leak detected from a valve at a source 

constructed after August 23, 2011 shall 

be repaired in accordance with the 

schedule in § 61.242–7(d), or by October 

15, 2012, whichever is later. 

* * * * * 


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(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); 

■ 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; 

■ k. Revising paragraph (e)(3)(ii); and 

■ l. Adding paragraph (f). 

The revisions and additions 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 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 

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 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 (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 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). 

(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. 

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(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); 

■ 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 paragraphs (f)(2) and (3); 

■ r. Adding paragraphs (f)(4) through 

(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). 

The revisions and additions read as 

follows: 

§ 63.772 Test methods, compliance 

procedures, and compliance 

demonstrations. 

* * * * * 

(b) Determination of glycol 

dehydration unit flowrate, benzene 

emissions, or BTEX emissions. The 

procedures of this paragraph shall be 

used by an owner or operator to 

determine glycol dehydration unit 

natural gas flowrate, benzene emissions, 

or BTEX emissions. 

(1) * * * 

(ii) The owner or operator shall 

document, to the Administrator’s 

satisfaction, the actual annual average 

natural gas flowrate to the glycol 

dehydration unit. 

(2) The determination of actual 

average benzene or BTEX emissions 

from a glycol dehydration unit shall be 

made using the procedures of either 

paragraph (b)(2)(i) or (ii) of this section. 

Emissions shall be determined either 

uncontrolled, or with federally 

enforceable controls in place. 

(i) The owner or operator shall 

determine actual average benzene or 

BTEX emissions using the model GRI– 

GLYCalcTM, Version 3.0 or higher, and 

the procedures presented in the 

associated GRI–GLYCalcTM Technical 

Reference Manual. Inputs to the model 

shall be representative of actual 

operating conditions of the glycol 

dehydration unit and may be 

determined using the procedures 

documented in the Gas Research 

Institute (GRI) report entitled 

‘‘Atmospheric Rich/Lean Method for 

Determining Glycol Dehydrator 

Emissions’’ (GRI–95/0368.1); or 

(ii) The owner or operator shall 

determine an average mass rate of 

benzene or BTEX emissions in 

kilograms per hour through direct 

measurement using the methods in 

§ 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. 

* * * * * 

(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. 

(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 

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 

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49574 Federal Register / Vol. 77, No. 159 / Thursday, August 16, 2012 / Rules and Regulations 

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 

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), (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, ASTM 

D6522–00 (Reapproved 2005), or ANSI/ 

ASME PTC 19.10–1981, Part 10 (manual 

portion only) (incorporated by reference 

as specified in § 63.14) shall be used to 

determine the oxygen concentration. 

The samples shall be taken during the 

same time that the samples are taken for 

determining TOC concentration or total 

HAP concentration. 

* * * * * 

(v) To determine compliance with the 

BTEX emission limit specified in 

§ 63.765(b)(1)(iii) the owner or operator 

shall use one of the following methods: 

Method 18, 40 CFR part 60, appendix A; 

ASTM D6420–99 (Reapproved 2004), as 

specified in § 63.772(a)(1)(ii) 

(incorporated by reference as specified 

in § 63.14); or any other method or data 

that have been validated according to 

the applicable procedures in Method 

301, 40 CFR part 63, appendix A. The 

following procedures shall be used to 

calculate BTEX emissions: 

(A) The minimum sampling time for 

each run shall be 1 hour in which either 

an integrated sample or a minimum of 

four grab samples shall be taken. If grab 

sampling is used, then the samples shall 

be taken at approximately equal 

intervals in time, such as 15-minute 

intervals during the run. 

(B) The mass rate of BTEX (Eo) shall 

be computed using the equations and 

procedures specified in paragraphs 

(e)(3)(v)(B)(1) and (2) of this section. 

(1) The following equation shall be 

used: 

Where: 

Eo = Mass rate of BTEX at the outlet of the 

control device, dry basis, kilogram per 

hour. 

Coj = Concentration of sample component j of 

the gas stream at the outlet of the control 

device, dry basis, parts per million by 

volume. 

Moj = Molecular weight of sample component 

j of the gas stream at the outlet of the 

control device, gram/gram-mole. 

Qo = Flowrate of gas stream at the outlet of 

the control device, dry standard cubic 

meter per minute. 

K2 = Constant, 2.494 × 10¥6 (parts per 

million) (gram-mole per standard cubic 

meter) (kilogram/gram) (minute/hour), 

where standard temperature (gram-mole 

per standard cubic meter) is 20 degrees 

C. 

n = Number of components in sample. 

(2) When the BTEX mass rate is 

calculated, only BTEX compounds 

measured by Method 18, 40 CFR part 

60, appendix A, or ASTM D6420–99 

(Reapproved 2004) (incorporated by 

reference as specified in § 63.14) 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 October 15, 

2015. If the owner or operator of an 

existing combustion control device at a 

major source chooses to replace such 

device with a control device whose 

model is tested under § 63.772(h), then 

the newly installed device shall comply 

with all provisions of this subpart no 

later than October 15, 2015. The 

performance test results shall be 

submitted in the Notification of 

Compliance Status Report as required in 

§ 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) 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 


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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 (ii) of this section. 

Documentation of the design analysis 

shall be submitted as a part of the 

Notification of Compliance Status 

Report as required in § 63.775(d)(1)(i). 

(i) The condenser design analysis 

shall include an analysis of the vent 

stream composition, constituent 

concentrations, flowrate, relative 

humidity, and temperature, and shall 

establish the design outlet organic 

compound concentration level, design 

average temperature of the condenser 

exhaust vent stream, and the design 

average temperatures of the coolant 

fluid at the condenser inlet and outlet. 

As an alternative to the condenser 

design analysis, an owner or operator 

may elect to use the procedures 

specified in paragraph (e)(5) of this 

section. 

* * * * * 

(5) As an alternative to the procedures 

in paragraph (e)(4)(i) of this section, an 

owner or operator may elect to use the 

procedures documented in the GRI 

report entitled, ‘‘Atmospheric Rich/Lean 

Method for 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 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(e), as 

applicable. 

(4) Except for periods of monitoring 

system malfunctions, repairs associated 

with monitoring system malfunctions, 

and required monitoring system quality 

assurance or quality control activities 

(including, as applicable, system 

accuracy audits and required zero and 

span adjustments), the CMS required in 

§ 63.773(d) must be operated at all times 

the affected source is operating. A 

monitoring system malfunction is any 

sudden, infrequent, not reasonably 

preventable failure of the monitoring 

system to provide valid data. 

Monitoring system failures that are 

caused in part by poor maintenance or 

careless operation are not malfunctions. 

Monitoring system repairs are required 

to be completed in response to 

monitoring system malfunctions and to 

return the monitoring system to 

operation as expeditiously as 

practicable. 

(5) Data recorded during monitoring 

system malfunctions, repairs associated 

with monitoring system malfunctions, 

or required monitoring system quality 

assurance or control activities may not 

be used in calculations used to report 

emissions or operating levels. All the 

data collected during all other required 

data collection periods must be used in 

assessing the operation of the control 

device and associated control system. 

(6) Except for periods of monitoring 

system malfunctions, repairs associated 

with monitoring system malfunctions, 

and required quality monitoring system 

quality assurance or quality control 

activities (including, as applicable, 

system accuracy audits and required 

zero and span adjustments), failure to 

collect required data is a deviation of 

the monitoring requirements. 

(g) Compliance demonstration with 

percent reduction or emission limit 

performance requirements—condensers. 

This paragraph applies to the 

demonstration of compliance with the 

performance requirements specified in 

§ 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 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 

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49576 Federal Register / Vol. 77, No. 159 / Thursday, August 16, 2012 / Rules and Regulations 

§ 63.760(f), the owner or operator shall 

calculate the average HAP emission 

reduction as the HAP emission 

reduction averaged over the number of 

days between the current day and the 

applicable compliance date. For sources 

required to meet the overall 95.0- 

percent reduction requirement, 

compliance with the performance 

requirements is achieved if the average 

HAP emission reduction is equal to or 

greater than 90.0 percent. For sources 

required to meet the BTEX limit under 

§ 63.765(b)(1)(iii), compliance is 

achieved if the average BTEX emission 

reduction is at least 95.0 percent of the 

required 365-day value 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. 

(h) Performance testing for 

combustion control devices— 

manufacturers’ performance test. (1) 

This paragraph applies to the 

performance testing of a combustion 

control device conducted by the device 

manufacturer. The manufacturer shall 

demonstrate that a specific model of 

control device achieves the performance 

requirements in paragraph (h)(7) of this 

section by conducting a performance 

test as specified in paragraphs (h)(2) 

through (6) of this section. 

(2) Performance testing shall consist 

of three one-hour (or longer) test runs 

for each of the four following firing rate 

settings making a total of 12 test runs 

per test. Propene (propylene) gas shall 

be used for the testing fuel. All fuel 

analyses shall be performed by an 

independent third-party laboratory (not 

affiliated with the control device 

manufacturer or fuel supplier). 

(i) 90–100 percent of maximum 

design rate (fixed rate). 

(ii) 70–100–70 percent (ramp up, 

ramp down). Begin the test at 70 percent 

of the maximum design rate. During the 

first 5 minutes, incrementally ramp the 

firing rate to 100 percent of the 

maximum design rate. Hold at 100 

percent for 5 minutes. In the 10–15 

minute time range, incrementally ramp 

back down to 70 percent of the 

maximum design rate. Repeat three 

more times for a total of 60 minutes of 

sampling. 

(iii) 30–70–30 percent (ramp up, ramp 

down). Begin the test at 30 percent of 

the maximum design rate. During the 

first 5 minutes, incrementally ramp the 

firing rate to 70 percent of the maximum 

design rate. Hold at 70 percent for 5 

minutes. In the 10–15 minute time 

range, incrementally ramp back down to 

30 percent of the maximum design rate. 

Repeat three more times for a total of 60 

minutes of sampling. 

(iv) 0–30–0 percent (ramp up, ramp 

down). Begin the test at 0 percent of the 

maximum design rate. During the first 5 

minutes, incrementally ramp the firing 

rate to 30 percent of the maximum 

design rate. Hold at 30 percent for 5 

minutes. In the 10–15 minute time 

range, incrementally ramp back down to 

0 percent of the maximum design rate. 

Repeat three more times for a total of 60 

minutes of sampling. 

(3) All models employing multiple 

enclosures shall be tested 

simultaneously and with all burners 

operational. Results shall be reported for 

the each enclosure individually and for 

the average of the emissions from all 

interconnected combustion enclosures/ 

chambers. Control device operating data 

shall be collected continuously 

throughout the performance test using 

an electronic Data Acquisition System 

and strip chart. Data shall be submitted 

with the test report in accordance with 

paragraph (h)(8)(iii) of this section. 

(4) Inlet gas testing shall be conducted 

as specified in paragraphs (h)(4)(i) 

through (iii) of this section. 

(i) The inlet gas flow metering system 

shall be located in accordance with 

Method 2A, 40 CFR part 60, appendix 

A–1, (or other approved procedure) to 

measure inlet gas flowrate at the control 

device inlet location. The fitting for 

filling inlet gas sample containers shall 

be located a minimum of 8 pipe 

diameters upstream of any inlet gas flow 

monitoring meter. 

(ii) Inlet gas flowrate shall be 

determined using Method 2A, 40 CFR 

part 60, appendix A–1. Record the start 

and stop reading for each 60-minute 

THC test. Record the inlet gas pressure 

and temperature at 5-minute intervals 

throughout each 60-minute THC test. 

(iii) Inlet gas fuel sampling shall be 

conducted in accordance with the 

criteria in paragraphs (h)(4)(iii)(A) and 

(B) of this section. 

(A) At the inlet gas sampling location, 

securely connect a Silonite-coated 

stainless steel evacuated canister fitted 

with a flow controller sufficient to fill 

the canister over a 3 hour period. Filling 

shall be conducted as specified in the 

following: 

(1) Open the canister sampling valve 

at the beginning of the total 

hydrocarbon (THC) test, and close the 

canister at the end of each THC run. 

(2) Fill one canister across the three 

test runs for each THC test such that one 

composite fuel sample exists for each 

test condition. 

(3) Label the canisters individually 

and record on a chain of custody form. 

(B) Each inlet gas sample shall be 

analyzed using the following methods. 

The results shall be included in the test 

report. 

(1) Hydrocarbon compounds 

containing between one and five atoms 

of carbon plus benzene using ASTM 

D1945–03 (Reapproved 2010) 

(incorporated by reference as specified 

in § 63.14). 

(2) Hydrogen (H2), carbon monoxide 

(CO), carbon dioxide (CO2), nitrogen 

(N2), oxygen (O2) using ASTM D1945– 

03 (Reapproved 2010) (incorporated by 

reference as specified in § 63.14). 

(3) Higher heating value using ASTM 

D3588–98 (Reapproved 2003) or ASTM 

D4891–89 (Reapproved 2006) 

(incorporated by reference as specified 

in § 63.14). 

(5) Outlet testing shall be conducted 

in accordance with the criteria in 

paragraphs (h)(5)(i) through (v) of this 

section. 

(i) Sampling and flowrate measured in 

accordance with the following: 

(A) The outlet sampling location shall 

be a minimum of 4 equivalent stack 

diameters downstream from the highest 

peak flame or any other flow 

disturbance, and a minimum of one 

equivalent stack diameter upstream of 

the exit or any other flow disturbance. 

A minimum of two sample ports shall 

be used. 

(B) Flowrate shall be measured using 

Method 1, 40 CFR part 60, Appendix 1, 

for determining flow measurement 

traverse point location; and Method 2, 

40 CFR part 60, Appendix 1, shall be 

used to measure duct velocity. If low 

flow conditions are encountered (i.e., 

velocity pressure differentials less than 

0.05 inches of water) during the 

performance test, a more sensitive 

manometer or other pressure 

measurement device shall be used to 

obtain an accurate flow profile. 

(ii) Molecular weight shall be 

determined as specified in paragraphs 

(h)(4)(iii)(B) and (h)(5)(ii)(A) and (B) of 

this section. 

(A) An integrated bag sample shall be 

collected during the Method 4, 40 CFR 

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part 60, Appendix A, moisture test. 

Analyze the bag sample using a gas 

chromatograph-thermal conductivity 

detector (GC–TCD) analysis meeting the 

following criteria: 

(1) Collect the integrated sample 

throughout the entire test, and collect 

representative volumes from each 

traverse location. 

(2) The sampling line shall be purged 

with stack gas before opening the valve 

and beginning to fill the bag. 

(3) The bag contents shall be 

vigorously mixed prior to the GC 

analysis. 

(4) The GC–TCD calibration 

procedure in Method 3C, 40 CFR part 

60, Appendix A, shall be modified by 

using EPAAlt–045 as follows: For the 

initial calibration, triplicate injections of 

any single concentration must agree 

within 5 percent of their mean to be 

valid. The calibration response factor for 

a single concentration re-check must be 

within 10 percent of the original 

calibration response factor for that 

concentration. If this criterion is not 

met, the initial calibration using at least 

three concentration levels shall be 

repeated. 

(B) Report the molecular weight of: 

O2, CO2, methane (CH4), and N2 and 

include in the test report submitted 

under § 63.775(d)(iii). Moisture shall be 

determined using Method 4, 40 CFR 

part 60, Appendix A. Traverse both 

ports with the Method 4, 40 CFR part 

60, Appendix A, sampling train during 

each test run. Ambient air shall not be 

introduced into the Method 3C, 40 CFR 

part 60, Appendix A, integrated bag 

sample during the port change. 

(iii) Carbon monoxide shall be 

determined using Method 10, 40 CFR 

part 60, Appendix A, or ASTM D6522– 

00 (Reapproved 2005), (incorporated by 

reference as specified in § 63.14). The 

test shall be run at the same time and 

with the sample points used for the EPA 

Method 25A, 40 CFR part 60, Appendix 

A, testing. An instrument range of 0–10 

per million by volume-dry (ppmvd) 

shall be used. 

(iv) Visible emissions shall be 

determined using Method 22, 40 CFR 

part 60, Appendix A. The test shall be 

performed continuously during each 

test run. A digital color photograph of 

the exhaust point, taken from the 

position of the observer and annotated 

with date and time, will be taken once 

per test run and the four photos 

included in the test report. 

(v) Excess air shall be determined 

using resultant data from the EPA 

Method 3C tests and EPA Method 3B, 40 

CFR part 60, Appendix A, equation 3B– 

1 or ANSI/ASME PTC 19.10, 1981-Part 

10 (manual portion only) (incorporated 

by reference as specified in § 63.14). 

(6) Total hydrocarbons (THC) shall be 

determined as specified by the 

following criteria: 

(i) Conduct THC sampling using 

Method 25A, 40 CFR part 60, Appendix 

A, except the option for locating the 

probe in the center 10 percent of the 

stack shall not be allowed. The THC 

probe must be traversed to 16.7 percent, 

50 percent, and 83.3 percent of the stack 

diameter during each test. 

(ii) A valid test shall consist of three 

Method 25A, 40 CFR part 60, Appendix 

A, tests, each no less than 60 minutes 

in duration. 

(iii) A 0–10 parts per million by 

volume-wet (ppmvw) (as propane) 

measurement range is preferred; as an 

alternative a 0–30 ppmvw (as carbon) 

measurement range may be used. 

(iv) Calibration gases will be propane 

in air and be certified through EPA 

Protocol 1—‘‘EPA Traceability Protocol 

for Assay and Certification of Gaseous 

Calibration Standards,’’ September 

1997, as amended August 25, 1999, 

EPA–600/R–97/121 (or more recent if 

updated since 1999). 

(v) THC measurements shall be 

reported in terms of ppmvw as propane. 

(vi) THC results shall be corrected to 

3 percent CO2, as measured by Method 

3C, 40 CFR part 60, Appendix A. 

(vii) Subtraction of methane/ethane 

from the THC data is not allowed in 

determining results. 

(7) Performance test criteria: 

(i) The control device model tested 

must meet the criteria in paragraphs 

(h)(7)(i)(A) through (C) of this section: 

(A) Method 22, 40 CFR part 60, 

Appendix A, results under paragraph 

(h)(5)(v) of this section with no 

indication of visible emissions, and 

(B) Average Method 25A, 40 CFR part 

60, Appendix A, results under 

paragraph (h)(6) of this section equal to 

or less than 10.0 ppmvw THC as 

propane corrected to 3.0 percent CO2, 

and 

(C) Average CO emissions determined 

under paragraph (h)(5)(iv) of this section 

equal to or less than 10 parts ppmvd, 

corrected to 3.0 percent CO2. 

(D) Excess combustion air shall be 

equal to or greater than 150 percent. 

(ii) The manufacturer shall determine 

a maximum inlet gas flowrate which 

shall not be exceeded for each control 

device model to achieve the criteria in 

paragraph (h)(7)(i) of this section. 

(iii) A control device meeting the 

criteria in paragraphs (h)(7)(i)(A) 

through (C) of this section will have 

demonstrated a destruction efficiency of 

95.0 percent for HAP regulated under 

this subpart. 

(8) The owner or operator of a 

combustion control device model tested 

under this section shall submit the 

information listed in paragraphs (h)(8)(i) 

through (iii) of this section in the test 

report required under § 63.775(d)(1)(iii). 

(i) Full schematic of the control 

device and dimensions of the device 

components. 

(ii) Design net heating value 

(minimum and maximum) of the device. 

(iii) Test fuel gas flow range (in both 

mass and volume). Include the 

minimum and maximum allowable inlet 

gas flowrate. 

(iv) Air/stream injection/assist ranges, 

if used. 

(v) The test parameter ranges listed in 

paragraphs (h)(8)(v)(A) through (O) of 

this section, as applicable for the tested 

model. 

(A) Fuel gas delivery pressure and 

temperature. 

(B) Fuel gas moisture range. 

(C) Purge gas usage range. 

(D) Condensate (liquid fuel) 

separation range. 

(E) Combustion zone temperature 

range. This is required for all devices 

that measure this parameter. 

(F) Excess combustion air range. 

(G) Flame arrestor(s). 

(H) Burner manifold pressure. 

(I) Pilot flame sensor. 

(J) Pilot flame design fuel and fuel 

usage. 

(K) Tip velocity range. 

(L) Momentum flux ratio. 

(M) Exit temperature range. 

(N) Exit flowrate. 

(O) Wind velocity and direction. 

(vi) The test report shall include all 

calibration quality assurance/quality 

control data, calibration gas values, gas 

cylinder certification, and strip charts 

annotated with test times and 

calibration values. 

(i) Compliance demonstration for 

combustion control devices— 

manufacturers’ performance test. This 

paragraph applies to the demonstration 

of compliance for a combustion control 

device tested under the provisions in 

paragraph (h) of this section. Owners or 

operators shall demonstrate that a 

control device achieves the performance 

requirements of § 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 

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to exceed a total of 2 minutes during 

any hour. A visible emissions test using 

Method 22, 40 CFR part 60, Appendix 

A, shall be performed each calendar 

quarter. The observation period shall be 

1 hour and shall be conducted 

according to EPA Method 22, 40 CFR 

part 60, Appendix A. 

(4) Compliance with the operating 

parameter limit is achieved when the 

following criteria are met: 

(i) The inlet gas flowrate monitored 

under paragraph (i)(1) of this section is 

equal to or below the maximum 

established by the manufacturer; and 

(ii) The pilot flame is present at all 

times; and 

(iii) During the visible emissions test 

performed under paragraph (i)(3) of this 

section the duration of visible emissions 

does not exceed a total of 2 minutes 

during the observation period. Devices 

failing the visible emissions test shall 

follow manufacturers repair 

instructions, if available, or best 

combustion engineering practice as 

outlined in the unit inspection and 

maintenance plan, to return the unit to 

compliant operation. All repairs and 

maintenance activities for each unit 

shall be recorded in a maintenance and 

repair log and shall be available on site 

for inspection. 

(iv) Following return to operation 

from maintenance or repair activity, 

each device must pass a Method 22 

visual observation as described in 

paragraph (i)(3) of this section. 

■ 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); 

■ 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 (9). 

The revisions and additions 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. 

* * * * * 

(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 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 (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 sitespecific monitoring plan. 

(2) An owner or operator is exempt 

from the monitoring requirements 

specified in paragraphs (d)(3) through 

(7) of this section for the following types 

of control devices: 

(i) Except for control devices for small 

glycol dehydration units, a boiler or 

process heater in which all vent streams 

are introduced with the primary fuel or 

is used as the primary fuel; or 

(ii) Except for control devices for 

small glycol dehydration units, a boiler 

or process heater with a design heat 

input capacity equal to or greater than 

44 megawatts. 

(3) * * * 

(i) * * * 

(A) For a thermal vapor incinerator 

that demonstrates during the 

performance test conducted under 

§ 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. 

* * * * * 

(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) and shall 

be based on the total carbon working 

capacity of the control device and 

source operating schedule. 

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(H) For a control device model whose 

model is tested under § 63.772(h): 

(1) The owner or operator shall 

determine actual average inlet waste gas 

flowrate using the model GRI– 

GLYCalc TM, Version 3.0 or 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); 

(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: 

(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 

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 of 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–95/0368.1) as inputs 

for the model GRI–GLYCalc TM, Version 

3.0 or higher, to generate a condenser 

performance curve. 

(6) An excursion for a given control 

device is determined to have occurred 

when the monitoring data or lack of 

monitoring data result in any one of the 

criteria specified in paragraphs (d)(6)(i) 

through (vi) of this section being met. 

When multiple operating parameters are 

monitored for the same control device 

and during the same operating day and 

more than one of these operating 

parameters meets an excursion criterion 

specified in paragraphs (d)(6)(i) through 

(vi) of this section, then a single 

excursion is determined to have 

occurred for the control device for that 

operating day. 

* * * * * 

(ii) For sources meeting 

§ 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. 

(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: 

■ 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). 

The revisions and additions read as 

follows: 

§ 63.774 Recordkeeping requirements. 

* * * * * 

(b) * * * 

(3) Records specified in § 63.10(c) for 

each monitoring system operated by the 

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49580 Federal Register / Vol. 77, No. 159 / Thursday, August 16, 2012 / Rules and Regulations 

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 (iv) of this section shall 

not be included in any average or 

percent leak rate computed under this 

subpart. Records shall be kept of the 

times and durations of all such periods 

and any other periods during process or 

control device operation when monitors 

are not operating or failed to collect 

required data. 

* * * * * 

(4) * * * 

(ii) Records of the daily average value 

of each continuously monitored 

parameter for each operating day 

determined according to the procedures 

specified in § 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 

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); 

■ 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 (xiv); and 

■ p. Adding paragraph (g). 

The revisions and additions 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 (b)(1)(ii) of this section, the 

initial notifications shall be submitted 

by 1 year after an affected source 

becomes subject to the provisions of this 

subpart or by June 17, 2000, whichever 

is later. Affected sources that are major 

sources on or before June 17, 2000, and 

plan to be area sources by June 17, 2002, 

shall include in this notification a brief, 

nonbinding description of a schedule 

for the action(s) that are planned to 

achieve area source status. 

(ii) An affected source identified 

under § 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 October 

15, 2013, whichever is later. An affected 

source identified under § 63.760(f)(7) or 

(9) that plans to be an area source by 

October 15, 2015, shall include in this 

notification a brief, nonbinding 

description of a schedule for the 

action(s) that are planned to achieve 

area source status. 

* * * * * 

(6) If there was a malfunction during 

the reporting period, the Periodic Report 

specified in paragraph (e) of this section 

shall include the number, duration, and 

a brief description for each type of 

malfunction which occurred during the 

reporting period and which caused or 

may have caused any applicable 

emission limitation to be exceeded. The 

report must also include a description of 

actions taken by an owner or operator 

during a malfunction of an affected 

source to minimize emissions in 

accordance with § 63.764(j), including 

actions taken to correct a malfunction. 

* * * * * 

(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 email to Oil and Gas 

Sector@epa.gov or via U.S. mail or other 

mail delivery service to U.S. EPA, 

Sector Policies and Programs Division/ 

Fuels and Incineration Group (E143– 

01), Attn: Oil and Gas Project Leader, 

Research Triangle Park, NC 27711. 

* * * * * 

(6) If there was a malfunction during 

the reporting period, the Periodic Report 

specified in paragraph (e) of this section 

shall include the number, duration, and 

a brief description for each type of 

malfunction which occurred during the 

reporting period and which caused or 

may have caused any applicable 

emission limitation to be exceeded. The 

report must also include a description of 

actions taken by an owner or operator 

during a malfunction of an affected 

source to minimize emissions in 

accordance with § 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 

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Federal Register / Vol. 77, No. 159 / Thursday, August 16, 2012 / Rules and Regulations 49581 

§ 63.772(e)(4) of this subpart, if the 

owner or operator elects to prepare a 

design analysis. 

(ii) If the owner or operator is 

required to conduct a performance test, 

the performance test results including 

the information specified in paragraphs 

(d)(1)(ii)(A) and (B) of this section. 

Results of a performance test conducted 

prior to the compliance date of this 

subpart can be used provided that the 

test was conducted using the methods 

specified in § 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 Web site: epa.gov/airquality/ 

oilandgas/. 

* * * * * 

(5) * * * 

(ii) An explanation of the rationale for 

why the owner or operator selected each 

of the operating parameter values 

established in § 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). 

* * * * * 

(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. 

(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. 

(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). 

(xiv) Certification by a responsible 

official of truth, accuracy, and 

completeness. This certification shall 

state that, based on information and 

belief formed after reasonable inquiry, 

the statements and information in the 

document are true, accurate, and 

complete. 

* * * * * 

(g) Electronic reporting. (1) Within 60 

days after the date of completing each 

performance test (defined in § 63.2) as 

required by this subpart you must 

submit the results of the performance 

tests required by this subpart to EPA’s 

WebFIRE database by using the 

Compliance and Emissions Data 

Reporting Interface (CEDRI) that is 

accessed through EPA’s Central Data 

Exchange (CDX) (www.epa.gov/cdx). 

Performance test data must be submitted 

in the file format generated through use 

of EPA’s Electronic Reporting Tool 

(ERT) (see http://www.epa.gov/ttn/chief/ 

ert/index.html). Only data collected 

using test methods on the ERT Web site 

are subject to this requirement for 

submitting reports electronically to 

WebFIRE. Owners or operators who 

claim that some of the information being 

submitted for performance tests is 

confidential business information (CBI) 

must submit a complete ERT file 

including information claimed to be CBI 

on a compact disk or other commonly 

used electronic storage media 

(including, but not limited to, flash 

drives) to EPA. The electronic media 

must be clearly marked as CBI and 

mailed to U.S. EPA/OAPQS/CORE CBI 

Office, Attention: WebFIRE 

Administrator, MD C404–02, 4930 Old 

Page Rd., Durham, NC 27703. The same 

ERT file with the CBI omitted must be 

submitted to EPA via CDX as described 

earlier in this paragraph. At the 

discretion of the delegated authority, 

you must also submit these reports, 

including the confidential business 

information, to the delegated authority 

in the format specified by the delegated 

authority. 

(2) All reports required by this 

subpart not subject to the requirements 

in paragraph (g)(1) of this section must 

be sent to the Administrator at the 

appropriate address listed in § 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 

* * * * * 

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49582 Federal Register / Vol. 77, No. 159 / Thursday, August 16, 2012 / Rules and Regulations 

TABLE 2 TO SUBPART HH OF PART 63—APPLICABILITY OF 40 CFR PART 63 GENERAL PROVISIONS TO SUBPART HH 

General provisions reference Applicable to 

subpart HH Explanation 

§ 63.1(a)(1) ............................................... Yes. 

§ 63.1(a)(2) ............................................... Yes. 

§ 63.1(a)(3) ............................................... Yes. 

§ 63.1(a)(4) ............................................... Yes. 

§ 63.1(a)(5) ............................................... No ..................... Section reserved. 

§ 63.1(a)(6) ............................................... Yes. 

§ 63.1(a)(7) through (a)(9) ........................ No ..................... Section reserved. 

§ 63.1(a)(10) ............................................. Yes. 

§ 63.1(a)(11) ............................................. Yes. 

§ 63.1(a)(12) ............................................. Yes. 

§ 63.1(b)(1) ............................................... No ..................... Subpart HH specifies applicability. 

§ 63.1(b)(2) ............................................... No ..................... Section reserved. 

§ 63.1(b)(3) ............................................... Yes. 

§ 63.1(c)(1) ................................................ No ..................... Subpart HH specifies applicability. 

§ 63.1(c)(2) ................................................ Yes ................... Subpart HH exempts area sources from the requirement to obtain a Title V permit 

unless otherwise required by law as specified in § 63.760(h). 

§ 63.1(c)(3) and (c)(4) ............................... No ..................... Section reserved. 

§ 63.1(c)(5) ................................................ Yes. 

§ 63.1(d) .................................................... No ..................... Section reserved. 

§ 63.1(e) .................................................... Yes. 

§ 63.2 ........................................................ Yes ................... Except definition of major source is unique for this source category and there are 

additional definitions in subpart HH. 

§ 63.3(a) through (c) ................................. Yes. 

§ 63.4(a)(1) through (a)(2) ........................ Yes. 

§ 63.4(a)(3) through (a)(5) ........................ No ..................... Section reserved. 

§ 63.4(b) .................................................... Yes. 

§ 63.4(c) .................................................... Yes. 

§ 63.5(a)(1) ............................................... Yes. 

§ 63.5(a)(2) ............................................... Yes. 

§ 63.5(b)(1) ............................................... Yes. 

§ 63.5(b)(2) ............................................... No ..................... Section reserved. 

§ 63.5(b)(3) ............................................... Yes. 

§ 63.5(b)(4) ............................................... Yes. 

§ 63.5(b)(5) ............................................... No ..................... Section Reserved. 

§ 63.5(b)(6) ............................................... Yes. 

§ 63.5(c) .................................................... No ..................... Section reserved. 

§ 63.5(d)(1) ............................................... Yes. 

§ 63.5(d)(2) ............................................... Yes. 

§ 63.5(d)(3) ............................................... Yes. 

§ 63.5(d)(4) ............................................... Yes. 

§ 63.5(e) .................................................... Yes. 

§ 63.5(f)(1) ................................................ Yes. 

§ 63.5(f)(2) ................................................ Yes. 

§ 63.6(a) .................................................... Yes. 

§ 63.6(b)(1) ............................................... Yes. 

§ 63.6(b)(2) ............................................... Yes. 

§ 63.6(b)(3) ............................................... Yes. 

§ 63.6(b)(4) ............................................... Yes. 

§ 63.6(b)(5) ............................................... Yes. 

§ 63.6(b)(6) ............................................... No ..................... Section reserved. 

§ 63.6(b)(7) ............................................... Yes. 

§ 63.6(c)(1) ................................................ Yes. 

§ 63.6(c)(2) ................................................ Yes. 

§ 63.6(c)(3) through (c)(4) ........................ No ..................... Section reserved. 

§ 63.6(c)(5) ................................................ Yes. 

§ 63.6(d) .................................................... No ..................... Section reserved. 

§ 63.6(e)(1)(i) ............................................ No ..................... See § 63.764(j) for general duty requirement. 

§ 63.6(e)(1)(ii) ........................................... No. 

§ 63.6(e)(1)(iii) ........................................... Yes. 

§ 63.6(e)(2) ............................................... No ..................... Section reserved. 

§ 63.6(e)(3) ............................................... No. 

§ 63.6(f)(1) ................................................ No. 

§ 63.6(f)(2) ................................................ Yes. 

§ 63.6(f)(3) ................................................ Yes. 

§ 63.6(g) .................................................... Yes. 

§ 63.6(h)(1) ............................................... No. 

§ 63.6(h)(2) through (h)(9) ........................ Yes. 

§ 63.6(i)(1) through (i)(14) ........................ Yes. 

§ 63.6(i)(15) ............................................... No ..................... Section reserved. 

§ 63.6(i)(16) ............................................... Yes. 

§ 63.6(j) ..................................................... Yes. 

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Federal Register / Vol. 77, No. 159 / Thursday, August 16, 2012 / Rules and Regulations 49583 

TABLE 2 TO SUBPART HH OF PART 63—APPLICABILITY OF 40 CFR PART 63 GENERAL PROVISIONS TO SUBPART HH— 

Continued 

General provisions reference Applicable to 

subpart HH Explanation 

§ 63.7(a)(1) ............................................... Yes. 

§ 63.7(a)(2) ............................................... Yes ................... But the performance test results must be submitted within 180 days after the 

compliance date. 

§ 63.7(a)(3) ............................................... Yes. 

§ 63.7(a)(4) ............................................... Yes. 

§ 63.7(c) .................................................... Yes. 

§ 63.7(d) .................................................... Yes. 

§ 63.7(e)(1) ............................................... No. 

§ 63.7(e)(2) ............................................... Yes. 

§ 63.7(e)(3) ............................................... Yes. 

§ 63.7(e)(4) ............................................... Yes. 

§ 63.7(f) ..................................................... Yes. 

§ 63.7(g) .................................................... Yes. 

§ 63.7(h) .................................................... Yes. 

§ 63.8(a)(1) ............................................... Yes. 

§ 63.8(a)(2) ............................................... Yes. 

§ 63.8(a)(3) ............................................... No ..................... Section reserved. 

§ 63.8(a)(4) ............................................... Yes. 

§ 63.8(b)(1) ............................................... Yes. 

§ 63.8(b)(2) ............................................... Yes. 

§ 63.8(b)(3) ............................................... Yes. 

§ 63.8(c)(1) ................................................ 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 ..................... Subpart HH does not require continuous opacity monitors. 

§ 63.8(c)(4)(ii) ............................................ Yes. 

§ 63.8(c)(5) through (c)(8) ........................ Yes. 

§ 63.8(d)(1) ............................................... Yes. 

§ 63.8(d)(2) ............................................... Yes. 

§ 63.8(d)(3) ............................................... Yes ................... Except for last sentence, which refers to an SSM plan. SSM plans are not required. 

§ 63.8(e) .................................................... Yes ................... Subpart HH does not specifically require continuous emissions monitor performance evaluation, however, the Administrator can request that one be conducted. 

§ 63.8(f)(1) through (f)(5) .......................... Yes. 

§ 63.8(f)(6) ................................................ Yes. 

§ 63.8(g) .................................................... No ..................... Subpart HH specifies continuous monitoring system data reduction requirements. 

§ 63.9(a) .................................................... Yes. 

§ 63.9(b)(1) ............................................... Yes. 

§ 63.9(b)(2) ............................................... Yes ................... Existing sources are given 1 year (rather than 120 days) to submit this notification. Major and area sources that meet § 63.764(e) do not have to submit initial 

notifications. 

§ 63.9(b)(3) ............................................... No ..................... Section reserved. 

§ 63.9(b)(4) ............................................... Yes. 

§ 63.9(b)(5) ............................................... Yes. 

§ 63.9(c) .................................................... Yes. 

§ 63.9(d) .................................................... Yes. 

§ 63.9(e) .................................................... Yes. 

§ 63.9(f) ..................................................... Yes. 

§ 63.9(g) .................................................... Yes. 

§ 63.9(h)(1) through (h)(3) ........................ Yes ................... Area sources located outside UA plus offset and UC boundaries are not required 

to submit notifications of compliance status. 

§ 63.9(h)(4) ............................................... No ..................... Section reserved. 

§ 63.9(h)(5) through (h)(6) ........................ Yes. 

§ 63.9(i) ..................................................... Yes. 

§ 63.9(j) ..................................................... Yes. 

§ 63.10(a) .................................................. Yes. 

§ 63.10(b)(1) ............................................. Yes ................... § 63.774(b)(1) requires sources to maintain the most recent 12 months of data 

on-site and allows offsite storage for the remaining 4 years of data. 

§ 63.10(b)(2) ............................................. Yes. 

§ 63.10(b)(2)(i) .......................................... No. 

§ 63.10(b)(2)(ii) ......................................... No ..................... See § 63.774(g) for recordkeeping of (1) occurrence and duration and (2) actions 

taken during malfunctions. 

§ 63.10(b)(2)(iii) ......................................... Yes. 

§ 63.10(b)(2)(iv) through (b)(2)(v) ............. No. 

§ 63.10(b)(2)(vi) through (b)(2)(xiv) .......... Yes. 

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49584 Federal Register / Vol. 77, No. 159 / Thursday, August 16, 2012 / Rules and Regulations 

TABLE 2 TO SUBPART HH OF PART 63—APPLICABILITY OF 40 CFR PART 63 GENERAL PROVISIONS TO SUBPART HH— 

Continued 

General provisions reference Applicable to 

subpart HH Explanation 

§ 63.10(b)(3) ............................................. Yes ................... § 63.774(b)(1) requires sources to maintain the most recent 12 months of data 

on-site and allows offsite storage for the remaining 4 years of data. 

§ 63.10(c)(1) .............................................. Yes. 

§ 63.10(c)(2) through (c)(4) ...................... No ..................... Sections reserved. 

§ 63.10(c)(5) through (c)(8) ...................... Yes. 

§ 63.10(c)(9) .............................................. No ..................... Section reserved. 

§ 63.10(c)(10) through (11) ....................... No ..................... See § 63.774(g) for recordkeeping of malfunctions. 

§ 63.10(c)(12) through (14) ....................... Yes. 

§ 63.10(c)(15) ............................................ No. 

§ 63.10(d)(1) ............................................. Yes. 

§ 63.10(d)(2) ............................................. Yes ................... Area sources located outside UA plus offset and UC boundaries do not have to 

submit performance test reports. 

§ 63.10(d)(3) ............................................. Yes. 

§ 63.10(d)(4) ............................................. Yes. 

§ 63.10(d)(5) ............................................. No ..................... See § 63.775(b)(6) or (c)(6) for reporting of malfunctions. 

§ 63.10(e)(1) ............................................. Yes ................... Area sources located outside UA plus offset and UC boundaries are not required 

to submit reports. 

§ 63.10(e)(2) ............................................. Yes ................... Area sources located outside UA plus offset and UC boundaries are not required 

to submit reports. 

§ 63.10(e)(3)(i) .......................................... Yes ................... Subpart HH requires major sources to submit Periodic Reports semi-annually. 

Area sources are required to submit Periodic Reports annually. Area sources 

located outside UA plus offset and UC boundaries are not required to submit 

reports. 

§ 63.10(e)(3)(i)(A) ..................................... Yes. 

§ 63.10(e)(3)(i)(B) ..................................... Yes. 

§ 63.10(e)(3)(i)(C) ..................................... No. 

§ 63.10(e)(3)(i)(D) ..................................... Yes ................... Section reserved. 

§ 63.10(e)(3)(ii) through (viii) .................... Yes. 

§ 63.10(e)(4) ............................................. Yes. 

§ 63.10(f) ................................................... Yes. 

§ 63.11(a) and (b) ..................................... Yes. 

§ 63.11(c), (d), and (e) .............................. Yes. 

§ 63.12(a) through (c) ............................... Yes. 

§ 63.13(a) through (c) ............................... Yes. 

§ 63.14(a) through (q) ............................... Yes. 

§ 63.15(a) and (b) ..................................... Yes. 

§ 63.16 ...................................................... Yes. 

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 (2); 

and 

■ e. Adding paragraphs (d)(3) and (4). 

The revisions and additions 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 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 

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 

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Federal Register / Vol. 77, No. 159 / Thursday, August 16, 2012 / Rules and Regulations 49585 

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 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 October 15, 2015, except as 

provided in § 63.6(i). 

(4) Each affected small glycol 

dehydration unit, as defined in 

§ 63.1271, located at a major source, that 

commenced construction on or after 

August 23, 2011, must achieve 

compliance immediately upon initial 

startup or October 15, 2012, whichever 

is later. 

* * * * * 

■ 24. Section 63.1271 is amended by: 

■ a. Adding, in alphabetical order, 

definitions for the terms ‘‘affirmative 

defense,’’ ‘‘BTEX,’’ ‘‘flare,’’ ‘‘large glycol 

dehydration units,’’ ‘‘responsible 

official’’ and ‘‘small glycol dehydration 

units;’’ and 

■ b. Revising the definition for ‘‘glycol 

dehydration unit baseline operations.’’ 

The additions and revision 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). 

* * * * * 

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 longterm 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. 

* * * * * 

Responsible official means one of the 

following: 

(1) For a corporation: A president, 

secretary, treasurer, or vice-president of 

the corporation in charge of a principal 

business function, or any other person 

who performs similar policy or 

decision-making functions for the 

corporation, or a duly authorized 

representative of such person if the 

representative is responsible for the 

overall operation of one or more 

manufacturing, production, or operating 

facilities applying for or subject to a 

permit and either: 

(i) The facilities employ more than 

250 persons or have gross annual sales 

or expenditures exceeding $25 million 

(in second quarter 1980 dollars); or 

(ii) The delegation of authority to 

such representatives is approved in 

advance by the permitting authority; 

(2) For a partnership or sole 

proprietorship: A general partner or the 

proprietor, respectively; 

(3) For a municipality, State, Federal, 

or other public agency: Either a 

principal executive officer or ranking 

elected official. For the purposes of this 

part, a principal executive officer of a 

Federal agency includes the chief 

executive officer having responsibility 

for the overall operations of a principal 

geographic unit of the agency (e.g., a 

Regional Administrator of EPA); or 

(4) For affected sources: 

(i) The designated representative in so 

far as actions, standards, requirements, 

or prohibitions under title IV of the Act 

or the regulations promulgated 

thereunder are concerned; and 

(ii) The designated representative for 

any other purposes under part 70. 

* * * * * 

Small glycol dehydration unit means 

a glycol dehydration unit, located at a 

major source, with an actual annual 

average natural gas flowrate less than 

283.0 thousand standard cubic meters 

per day or actual annual average 

benzene emissions less than 0.90 Mg/yr, 

determined according to § 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 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. 

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49586 Federal Register / Vol. 77, No. 159 / Thursday, August 16, 2012 / Rules and Regulations 

(1) To establish the affirmative 

defense in any action to enforce such a 

standard, you must timely meet the 

reporting requirements in paragraph 

(d)(2) of this section, and must prove by 

a preponderance of evidence that: 

(i) The violation: 

(A) Was caused by a sudden, 

infrequent, and unavoidable failure of 

air pollution control equipment, process 

equipment, or a process to operate in a 

normal or usual manner; and 

(B) Could not have been prevented 

through careful planning, proper design 

or better operation and maintenance 

practices; and 

(C) Did not stem from any activity or 

event that could have been foreseen and 

avoided, or planned for; and 

(D) Was not part of a recurring pattern 

indicative of inadequate design, 

operation, or maintenance; and 

(ii) Repairs were made as 

expeditiously as possible when a 

violation occurred. Off-shift and 

overtime labor were used, to the extent 

practicable to make these repairs; and 

(iii) The frequency, amount and 

duration of the violation (including any 

bypass) were minimized to the 

maximum extent practicable; and 

(iv) If the violation resulted from a 

bypass of control equipment or a 

process, then the bypass was 

unavoidable to prevent loss of life, 

personal injury, or severe property 

damage; and 

(v) All possible steps were taken to 

minimize the impact of the violation on 

ambient air quality, the environment, 

and human health; and 

(vi) All emissions monitoring and 

control systems were kept in operation 

if at all possible, consistent with safety 

and good air pollution control practices; 

and 

(vii) All of the actions in response to 

the violation were documented by 

properly signed, contemporaneous 

operating logs; and 

(viii) At all times, the affected source 

was operated in a manner consistent 

with good practices for minimizing 

emissions; and 

(ix) A written root cause analysis has 

been prepared, the purpose of which is 

to determine, correct, and eliminate the 

primary causes of the malfunction and 

the violation resulting from the 

malfunction event at issue. The analysis 

shall also specify, using best monitoring 

methods and engineering judgment, the 

amount of any emissions that were the 

result of the malfunction. 

(2) Report. The owner or operator 

seeking to assert an affirmative defense 

shall submit a written report to the 

Administrator with all necessary 

supporting documentation, that it has 

met the requirements set forth in 

paragraph (d)(1) of this section. This 

affirmative defense report shall be 

included in the first periodic 

compliance, deviation report or excess 

emission report otherwise required after 

the initial occurrence of the violation of 

the relevant standard (which may be the 

end of any applicable averaging period). 

If such compliance, deviation report or 

excess emission report is due less than 

45 days after the initial occurrence of 

the violation, the affirmative defense 

report may be included in the second 

compliance, deviation report or excess 

emission report due after the initial 

occurrence of the violation of the 

relevant standard. 

■ 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). 

The revisions and addition read as 

follows: 

§ 63.1274 General standards. 

* * * * * 

(c) The owner or operator of an 

affected source (i.e., glycol dehydration 

unit) located at an existing or new major 

source of HAP emissions shall comply 

with the requirements in this subpart as 

follows: 

* * * * * 

(d) [Reserved] 

* * * * * 

(g) In all cases where the provisions 

of this subpart require an owner or 

operator to repair leaks by a specified 

time after the leak is detected, it is a 

violation of this standard to fail to take 

action to repair the leak(s) within the 

specified time. If action is taken to 

repair the leak(s) within the specified 

time, failure of that action to 

successfully repair the leak(s) is not a 

violation of this standard. However, if 

the repairs are unsuccessful, and a leak 

is detected, the owner or operator shall 

take further action as required by the 

applicable provisions of this subpart. 

(h) At all times the owner or operator 

must operate and maintain any affected 

source, including associated air 

pollution control equipment and 

monitoring equipment, in a manner 

consistent with safety and good air 

pollution control practices for 

minimizing emissions. Determination of 

whether such operation and 

maintenance procedures are being used 

will be based on information available 

to the Administrator which may 

include, but is not limited to, 

monitoring results, review of operation 

and maintenance procedures, review of 

operation and maintenance records, and 

inspection of the source. 

■ 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). 

The revisions 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 (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 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. 

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Where: 

ELBTEX = Unit-specific BTEX emission limit, 

megagrams per year; 

3.10 × 10¥4 = BTEX emission limit, grams 

BTEX/standard cubic meter-ppmv; 

Throughput = Annual average daily natural 

gas throughput, standard cubic meters 

per day; 

Ci,BTEX = Annual average BTEX concentration 

of the natural gas at the inlet to the 

glycol dehydration unit, ppmv. 

Where: 

ELBTEX = Unit-specific BTEX emission limit, 

megagrams per year; 

5.44 × 10¥5 = BTEX emission limit, grams 

BTEX/standard cubic meter-ppmv; 

Throughput = Annual average daily natural 

gas throughput, standard cubic meters 

per day; 

Ci,BTEX = Annual average BTEX concentration 

of the natural gas at the inlet to the 

glycol dehydration unit, ppmv. 

(A) Connect the process vent to a 

control device or combination of control 

devices through a closed-vent system. 

The closed vent system shall be 

designed and operated in accordance 

with the requirements of § 63.1281(c). 

The control device(s) 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). 

(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; 

■ 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). 

The revisions and additions read as 

follows: 

§ 63.1281 Control equipment 

requirements. 

* * * * * 

(c) * * * 

(1) The closed-vent system shall route 

all gases, vapors, and fumes emitted 

from the material in an emissions unit 

to a control device that meets the 

requirements specified in paragraph (d) 

of this section. 

* * * * * 

(d) Control device requirements for 

sources except small glycol dehydration 

units. Owners and operators of small 

glycol dehydration units shall comply 

with the control requirements in 

paragraph (f) of this section. 

(1) * * * 

(i) * * * 

(C) Operates at a 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) * * * 

(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 


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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 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 

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). 

(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: 

■ 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 (3); 

■ t. Adding paragraphs (e)(4) through 

(e)(6); 

■ u. Revising paragraph (f) introductory 

text; 

■ v. Revising paragraph (f)(1); 

■ w. Revising paragraph (f)(2) 

introductory text; 

■ x. Revising paragraph (f)(2)(iii) 

introductory text, (f)(2)(iii)(A) and 

(f)(2)(iii)(B); 

■ y. Revising paragraph (f)(3); and 

■ z. Adding paragraphs (g) and (h). 

The revisions and additions 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 (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 

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Federal Register / Vol. 77, No. 159 / Thursday, August 16, 2012 / Rules and Regulations 49589 

BTEX emissions using the model GRI– 

GLYCalcTM, Version 3.0 or higher, and 

the procedures presented in the 

associated GRI–GLYCalcTM Technical 

Reference Manual. Inputs to the model 

shall be representative of actual 

operating conditions of the glycol 

dehydration unit and may be 

determined using the procedures 

documented in the Gas Research 

Institute (GRI) report entitled 

‘‘Atmospheric Rich/Lean Method for 

Determining Glycol Dehydrator 

Emissions’’ (GRI–95/0368.1); or 

(ii) The owner or operator shall 

determine an average mass rate of 

benzene or BTEX emissions in 

kilograms per hour through direct 

measurement by performing three runs 

of Method 18 in 40 CFR part 60, 

appendix A; or ASTM D6420–99 

(Reapproved 2004) (incorporated by 

reference as specified in § 63.14), 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 stream. For process 

streams that contain nitrogen, air, or 

other inert gases that are not organic 

HAP or VOC, the average stream 

response factor shall be calculated on an 

inert-free basis. 

* * * * * 

(c) Test procedures and compliance 

demonstrations for small glycol 

dehydration units. This paragraph (c) 

applies to the test procedures for small 

dehydration units. 

(1) If the owner or operator is using 

a control device to comply with the 

emission limit in § 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 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 

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; 

(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. 

(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 

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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 (incorporated by 

reference as specified in § 63.14), 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 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 (Reapproved 2004) 

(incorporated by reference as specified 

in § 63.14), 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, ASTM 

D6522–00 (Reapproved 2005), or ANSI/ 

ASME PTC 19.10–1981, Part 10 (manual 

portion only) (incorporated by reference 

as specified in § 63.14) shall be used to 

determine the oxygen concentration 

(%O2d). The samples shall be taken 

during the same time that the samples 

are taken for determining TOC 

concentration or total HAP 

concentration. 

* * * * * 

(v) To determine compliance with the 

BTEX emission limit specified in 

§ 63.1275(b)(1)(iii) the owner or operator 

shall use one of the following methods: 

Method 18, 40 CFR part 60, appendix A; 

ASTM D6420–99 (Reapproved 2004) 

(incorporated by reference as specified 

in § 63.14), 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. 

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 

(Reapproved 2004) (incorporated by 

reference as specified in § 63.14) 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 initial 

performance test for existing 

combustion control devices (i.e., control 

devices installed on or before August 

23, 2011) at major sources shall be 

conducted no later than October 15, 

2015. If the owner or operator of an 

existing combustion control device at a 

major source chooses to replace such 

device with a control device whose 

model is tested under § 63.1282(g), then 

the newly installed device shall comply 

with all provisions of this subpart no 

later than October 15, 2015. The 

performance test results shall be 

submitted in the Notification of 

Compliance Status Report as required in 

§ 63.1285(d)(1)(ii). 

(B) Periodic performance tests shall be 

conducted for all control devices 

required to conduct initial performance 

tests except as specified in paragraphs 

(e)(3)(vi)(B)(1) and (2) of this section. 

The first periodic performance test shall 

be conducted no later than 60 months 

after the initial performance test 

required in paragraph (d)(3)(vi)(A) of 

this section. Subsequent periodic 

performance tests shall be conducted at 

intervals no longer than 60 months 

following the previous periodic 

performance test or whenever a source 

desires to establish a new operating 

limit. The periodic performance test 

results must be submitted in the next 

Periodic Report as specified in 

§ 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 (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 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. 

* * * * * 


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(5) As an alternative to the procedures 

in paragraph (d)(4)(i) of this section, an 

owner or operator may elect to use the 

procedures documented in the GRI 

report entitled, ‘‘Atmospheric Rich/Lean 

Method for Determining Glycol 

Dehydrator Emissions,’’ (GRI–95/ 

0368.1) as inputs for the model GRI– 

GLYCalcTM, 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 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 

§ 63.1283(d) must be operated at all 

times the affected source is operating. A 

monitoring system malfunction is any 

sudden, infrequent, not reasonably 

preventable failure of the monitoring 

system to provide valid data. 

Monitoring system failures that are 

caused in part by poor maintenance or 

careless operation are not malfunctions. 

Monitoring system repairs are required 

to be completed in response to 

monitoring system malfunctions and to 

return the monitoring system to 

operation as expeditiously as 

practicable. 

(5) Data recorded during monitoring 

system malfunctions, repairs associated 

with monitoring system malfunctions, 

or required monitoring system quality 

assurance or control activities may not 

be used in calculations used to report 

emissions or operating levels. All the 

data collected during all other required 

data collection periods must be used in 

assessing the operation of the control 

device and associated control system. 

(6) Except for periods of monitoring 

system malfunctions, repairs associated 

with monitoring system malfunctions, 

and required quality monitoring system 

quality assurance or quality control 

activities (including, as applicable, 

system accuracy audits and required 

zero and span adjustments), failure to 

collect required data is a deviation of 

the monitoring requirements. 

(f) Compliance demonstration with 

percent reduction or emission limit 

performance requirements—condensers. 

This paragraph applies to the 

demonstration of compliance with the 

performance requirements specified in 

§ 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 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. 

(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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49592 Federal Register / Vol. 77, No. 159 / Thursday, August 16, 2012 / Rules and Regulations 

(g) Performance testing for 

combustion control devices— 

manufacturers’ performance test. 

(1) This paragraph (g) applies to the 

performance testing of a combustion 

control device conducted by the device 

manufacturer. The manufacturer shall 

demonstrate that a specific model of 

control device achieves the performance 

requirements in (g)(7) of this section by 

conducting a performance test as 

specified in paragraphs (g)(2) through 

(6) of this section. 

(2) Performance testing shall consist 

of three one-hour (or longer) test runs 

for each of the four following firing rate 

settings making a total of 12 test runs 

per test. Propene (propylene) gas shall 

be used for the testing fuel. All fuel 

analyses shall be performed by an 

independent third-party laboratory (not 

affiliated with the control device 

manufacturer or fuel supplier). 

(i) 90–100 percent of maximum 

design rate (fixed rate). 

(ii) 70–100–70 percent (ramp up, 

ramp down). Begin the test at 70 percent 

of the maximum design rate. During the 

first 5 minutes, incrementally ramp the 

firing rate to 100 percent of the 

maximum design rate. Hold at 100 

percent for 5 minutes. In the 10–15 

minute time range, incrementally ramp 

back down to 70 percent of the 

maximum design rate. Repeat three 

more times for a total of 60 minutes of 

sampling. 

(iii) 30–70–30 percent (ramp up, ramp 

down). Begin the test at 30 percent of 

the maximum design rate. During the 

first 5 minutes, incrementally ramp the 

firing rate to 70 percent of the maximum 

design rate. Hold at 70 percent for 5 

minutes. In the 10–15 minute time 

range, incrementally ramp back down to 

30 percent of the maximum design rate. 

Repeat three more times for a total of 60 

minutes of sampling. 

(iv) 0–30–0 percent (ramp up, ramp 

down). Begin the test at 0 percent of the 

maximum design rate. During the first 5 

minutes, incrementally ramp the firing 

rate to 30 percent of the maximum 

design rate. Hold at 30 percent for 5 

minutes. In the 10–15 minute time 

range, incrementally ramp back down to 

0 percent of the maximum design rate. 

Repeat three more times for a total of 60 

minutes of sampling. 

(3) All models employing multiple 

enclosures shall be tested 

simultaneously and with all burners 

operational. Results shall be reported for 

each enclosure individually and for the 

average of the emissions from all 

interconnected combustion enclosures/ 

chambers. Control device operating data 

shall be collected continuously 

throughout the performance test using 

an electronic Data Acquisition System 

and strip chart. Data shall be submitted 

with the test report in accordance with 

paragraph (g)(8)(iii) of this section. 

(4) Inlet testing shall be conducted as 

specified in paragraphs (g)(4)(i) through 

(iii) of this section. 

(i) The inlet gas flow metering system 

shall be located in accordance with 

Method 2A, 40 CFR part 60, appendix 

A–1, (or other approved procedure) to 

measure inlet gas flowrate at the control 

device inlet location. The fitting for 

filling fuel sample containers shall be 

located a minimum of 8 pipe diameters 

upstream of any inlet gas flow 

monitoring meter. 

(ii) Inlet gas flowrate shall be 

determined using Method 2A, 40 CFR 

part 60, appendix A–1. Record the start 

and stop reading for each 60-minute 

THC test. Record the inlet gas pressure 

and temperature at 5-minute intervals 

throughout each 60-minute THC test. 

(iii) Inlet gas sampling shall be 

conducted in accordance with the 

criteria in paragraphs (g)(4)(iii)(A) and 

(B) of this section. 

(A) At the inlet gas sampling location, 

securely connect a Silonite-coated 

stainless steel evacuated canister fitted 

with a flow controller sufficient to fill 

the canister over a 3 hour period. Filling 

shall be conducted as specified in the 

following: 

(1) Open the canister sampling valve 

at the beginning of the total 

hydrocarbon (THC) test, and close the 

canister at the end of each THC test run. 

(2) Fill one canister across the three 

test runs for each THC test such that one 

composite fuel sample exists for each 

test condition. 

(3) Label the canisters individually 

and record on a chain of custody form. 

(B) Each inlet gas sample shall be 

analyzed using the following methods. 

The results shall be included in the test 

report. 

(1) Hydrocarbon compounds 

containing between one and five atoms 

of carbon plus benzene using ASTM 

D1945–03 (Reapproved 2010) 

(incorporated by reference as specified 

in § 63.14). 

(2) Hydrogen (H2), carbon monoxide 

(CO), carbon dioxide (CO2), nitrogen 

(N2), oxygen (O2) using ASTM D1945– 

03 (Reapproved 2010) (incorporated by 

reference as specified in § 63.14). 

(3) Higher heating value using ASTM 

D3588–98 (Reapproved 2003) or ASTM 

D4891–89 (Reapproved 2006) 

(incorporated by reference as specified 

in § 63.14). 

(5) Outlet testing shall be conducted 

in accordance with the criteria in 

paragraphs (g)(5)(i) through (v) of this 

section. 

(i) Sampling and flowrate measured in 

accordance with the following: 

(A) The outlet sampling location shall 

be a minimum of 4 equivalent stack 

diameters downstream from the highest 

peak flame or any other flow 

disturbance, and a minimum of one 

equivalent stack diameter upstream of 

the exit or any other flow disturbance. 

A minimum of two sample ports shall 

be used. 

(B) Flowrate shall be measured using 

Method 1, 40 CFR part 60, Appendix 1, 

for determining flow measurement 

traverse point location; and Method 2, 

40 CFR part 60, Appendix 1, shall be 

used to measure duct velocity. If low 

flow conditions are encountered (i.e., 

velocity pressure differentials less than 

0.05 inches of water) during the 

performance test, a more sensitive 

manometer or other pressure 

measurement device shall be used to 

obtain an accurate flow profile. 

(ii) Molecular weight shall be 

determined as specified in paragraphs 

(g)(4)(iii)(B), and (g)(5)(ii)(A) and (B) of 

this section. 

(A) An integrated bag sample shall be 

collected during the Method 4, 40 CFR 

part 60, Appendix A, moisture test. 

Analyze the bag sample using a gas 

chromatograph-thermal conductivity 

detector (GC–TCD) analysis meeting the 

following criteria: 

(1) Collect the integrated sample 

throughout the entire test, and collect 

representative volumes from each 

traverse location. 

(2) The sampling line shall be purged 

with stack gas before opening the valve 

and beginning to fill the bag. 

(3) The bag contents shall be 

vigorously mixed prior to the GC 

analysis. 

(4) The GC–TCD calibration 

procedure in Method 3C, 40 CFR part 

60, Appendix A, shall be modified by 

using EPAAlt–045 as follows: For the 

initial calibration, triplicate injections of 

any single concentration must agree 

within 5 percent of their mean to be 

valid. The calibration response factor for 

a single concentration re-check must be 

within 10 percent of the original 

calibration response factor for that 

concentration. If this criterion is not 

met, the initial calibration using at least 

three concentration levels shall be 

repeated. 

(B) Report the molecular weight of: 

O2, CO2, methane (CH4), and N2 and 

include in the test report submitted 

under § 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 

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introduced into the Method 3C, 40 CFR 

part 60, Appendix A, integrated bag 

sample during the port change. 

(iii) Carbon monoxide shall be 

determined using Method 10, 40 CFR 

part 60, Appendix A or ASTM D6522– 

00 (Reapproved 2005) (incorporated by 

reference as specified in § 63.14). The 

test shall be run at the same time and 

with the sample points used for the EPA 

Method 25A, 40 CFR part 60, Appendix 

A, testing. An instrument range of 0–10 

per million by volume-dry (ppmvd) 

shall be used. 

(iv) Visible emissions shall be 

determined using Method 22, 40 CFR 

part 60, Appendix A. The test shall be 

performed continuously during each 

test run. A digital color photograph of 

the exhaust point, taken from the 

position of the observer and annotated 

with date and time, will be taken once 

per test run and the four photos 

included in the test report. 

(v) Excess air shall be determined 

using resultant data from the EPA 

Method 3C tests and EPA Method 3B, 40 

CFR part 60, Appendix A, equation 3B– 

1 or ANSI/ASME PTC 19.10–1981, Part 

10 (manual portion only) (incorporated 

by reference as specified in § 63.14). 

(6) Total hydrocarbons (THC) shall be 

determined as specified by the 

following criteria: 

(i) Conduct THC sampling using 

Method 25A, 40 CFR part 60, Appendix 

A, except the option for locating the 

probe in the center 10 percent of the 

stack shall not be allowed. The THC 

probe must be traversed to 16.7 percent, 

50 percent, and 83.3 percent of the stack 

diameter during the test run. 

(ii) A valid test shall consist of three 

Method 25A, 40 CFR part 60, Appendix 

A, tests, each no less than 60 minutes 

in duration. 

(iii) A 0–10 parts per million by 

volume-wet (ppmvw) (as propane) 

measurement range is preferred; as an 

alternative a 0–30 ppmvw (as carbon) 

measurement range may be used. 

(iv) Calibration gases will be propane 

in air and be certified through EPA 

Protocol 1—‘‘EPA Traceability Protocol 

for Assay and Certification of Gaseous 

Calibration Standards,’’ September 

1997, as amended August 25, 1999, 

EPA–600/R–97/121 (or more recent if 

updated since 1999). 

(v) THC measurements shall be 

reported in terms of ppmvw as propane. 

(vi) THC results shall be corrected to 

3 percent CO2, as measured by Method 

3C, 40 CFR part 60, Appendix A. 

(vii) Subtraction of methane/ethane 

from the THC data is not allowed in 

determining results. 

(7) Performance test criteria: 

(i) The control device model tested 

must meet the criteria in paragraphs 

(g)(7)(i)(A) through (C) of this section: 

(A) Method 22, 40 CFR part 60, 

Appendix A, results under paragraph 

(g)(5)(v) of this section with no 

indication of visible emissions, and 

(B) Average Method 25A, 40 CFR part 

60, Appendix A, results under 

paragraph (g)(6) of this section equal to 

or less than 10.0 ppmvw THC as 

propane corrected to 3.0 percent CO2, 

and 

(C) Average CO emissions determined 

under paragraph (g)(5)(iv) of this section 

equal to or less than 10 parts ppmvd, 

corrected to 3.0 percent CO2. 

(D) Excess combustion air shall be 

equal to or greater than 150 percent. 

(ii) The manufacturer shall determine 

a maximum inlet gas flowrate which 

shall not be exceeded for each control 

device model to achieve the criteria in 

paragraph (g)(7)(i) of this section. 

(iii) A control device meeting the 

criteria in paragraph (g)(7)(i)(A) through 

(C) of this section will have 

demonstrated a destruction efficiency of 

95.0 percent for HAP regulated under 

this subpart. 

(8) The owner or operator of a 

combustion control device model tested 

under this section shall submit the 

information listed in paragraphs (g)(8)(i) 

through (iii) in the test report required 

under § 63.775(d)(1)(iii). 

(i) Full schematic of the control 

device and dimensions of the device 

components. 

(ii) Design net heating value 

(minimum and maximum) of the device. 

(iii) Test fuel gas flow range (in both 

mass and volume). Include the 

minimum and maximum allowable inlet 

gas flowrate. 

(iv) Air/stream injection/assist ranges, 

if used. 

(v) The test parameter ranges listed in 

paragraphs (g)(8)(v)(A) through (O) of 

this section, as applicable for the tested 

model. 

(A) Fuel gas delivery pressure and 

temperature. 

(B) Fuel gas moisture range. 

(C) Purge gas usage range. 

(D) Condensate (liquid fuel) 

separation range. 

(E) Combustion zone temperature 

range. This is required for all devices 

that measure this parameter. 

(F) Excess combustion air range. 

(G) Flame arrestor(s). 

(H) Burner manifold pressure. 

(I) Pilot flame sensor. 

(J) Pilot flame design fuel and fuel 

usage. 

(K) Tip velocity range. 

(L) Momentum flux ratio. 

(M) Exit temperature range. 

(N) Exit flowrate. 

(O) Wind velocity and direction. 

(vi) The test report shall include all 

calibration quality assurance/quality 

control data, calibration gas values, gas 

cylinder certification, and strip charts 

annotated with test times and 

calibration values. 

(h) Compliance demonstration for 

combustion control devices— 

manufacturers’ performance test. This 

paragraph applies to the demonstration 

of compliance for a combustion control 

device tested under the provisions in 

paragraph (g) of this section. Owners or 

operators shall demonstrate that a 

control device achieves the performance 

requirements of § 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. 

(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. 

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49594 Federal Register / Vol. 77, No. 159 / Thursday, August 16, 2012 / Rules and Regulations 

■ 30. Section 63.1283 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); 

■ 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 paragraph (d)(6)(ii); 

■ n. Adding paragraph (d)(6)(v); 

■ o. Revising paragraph (d)(7); and 

■ p. Removing and reserving paragraph 

(d)(8). 

The additions and revisions 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 

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 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. 

(iv) The owner or operator must 

conduct a performance evaluation of 

each CPMS in accordance with the sitespecific 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 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 

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 

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define the conditions at which the 

control device must be operated to 

continuously achieve the applicable 

performance requirements of 

§ 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 

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 

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. 

* * * * * 

(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. 

(8) [Reserved] 

* * * * * 

■ 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 paragraphs (f), (g) and (h). 

The revisions and additions read as 

follows: 

§ 63.1284 Recordkeeping requirements. 

* * * * * 

(b) * * * 

(3) Records specified in § 63.10(c) for 

each monitoring system operated by the 

owner or operator in accordance with 

the requirements of § 63.1283(d). 

Notwithstanding the previous sentence, 

monitoring data recorded during 

periods identified 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 

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 

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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. 

(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; 

■ 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 paragraph (e)(2)(ii)(B); 

■ p. Adding paragraphs (e)(2)(ii)(D) and 

(E); 

■ q. Adding paragraphs (e)(2)(x) through 

(xiii); and 

■ r. Adding paragraph (g). 

The revisions and additions read as 

follows: 

§ 63.1285 Reporting requirements. 

* * * * * 

(b) * * * 

(1) The initial notifications required 

for existing affected sources under 

§ 63.9(b)(2) shall be submitted as 

provided in paragraphs (b)(1)(i) and (ii) 

of this section. 

(i) Except as otherwise provided in 

paragraph (b)(1)(ii) of this section, the 

initial notification shall be submitted by 

1 year after an affected source becomes 

subject to the provisions of this subpart 

or by June 17, 2000, whichever is later. 

Affected sources that are major sources 

on or before June 17, 2000 and plan to 

be area sources by June 17, 2002 shall 

include in this notification a brief, 

nonbinding description of a schedule 

for the action(s) that are planned to 

achieve area source status. 

(ii) An affected source identified 

under § 63.1270(d)(3) shall submit an 

initial notification required for existing 

affected sources under § 63.9(b)(2) 

within 1 year after the affected source 

becomes subject to the provisions of this 

subpart or by October 15, 2013, 

whichever is later. An affected source 

identified under § 63.1270(d)(3) that 

plans to be an area source by October 

15, 2015, shall include in this 

notification a brief, nonbinding 

description of a schedule for the 

action(s) that are planned to achieve 

area source status. 

* * * * * 

(6) If there was a malfunction during 

the reporting period, the Periodic Report 

specified in paragraph (e) of this section 

shall include the number, duration, and 

a brief description for each type of 

malfunction which occurred during the 

reporting period and which caused or 

may have caused any applicable 

emission limitation to be exceeded. The 

report must also include a description of 

actions taken by an owner or operator 

during a malfunction of an affected 

source to minimize emissions in 

accordance with § 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. 

(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 Web site: epa.gov/airquality/ 

oilandgas/. 

* * * * * 

(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 

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any data and calculations used to 

develop the value, and a description of 

why the chosen value indicates that the 

control device is operating in 

accordance with the applicable 

requirements of § 63.1281(d)(1), 

(e)(3)(ii), or (f)(1). 

* * * * * 

(iv) For each carbon adsorber, the 

predetermined carbon replacement 

schedule as required in 

§ 63.1281(d)(5)(i). 

* * * * * 

(10) The owner or operator shall 

submit the analysis prepared under 

§ 63.1281(e)(2) to demonstrate that the 

conditions by which the 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. 

* * * * * 

(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. 

* * * * * 

(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 http://www.epa.gov/ttn/chief/ 

ert/index.html). Only data collected 

using test methods on the ERT Web site 

are subject to this requirement for 

submitting reports electronically to 

WebFIRE. Owners or operators who 

claim that some of the information being 

submitted for performance tests is 

confidential business information (CBI) 

must submit a complete ERT file 

including information claimed to be CBI 

on a compact disk or other commonly 

used electronic storage media 

(including, but not limited to, flash 

drives) to EPA. The electronic media 

must be clearly marked as CBI and 

mailed to U.S. EPA/OAPQS/CORE CBI 

Office, Attention: WebFIRE 

Administrator, MD C404–02, 4930 Old 

Page Rd., Durham, NC 27703. The same 

ERT file with the CBI omitted must be 

submitted to EPA via CDX as described 

earlier in this paragraph. At the 

discretion of the delegated authority, 

you must also submit these reports, 

including the confidential business 

information, to the delegated authority 

in the format specified by the delegated 

authority. 

(2) All reports required by this 

subpart not subject to the requirements 

in paragraph (g)(1) of this section must 

be sent to the Administrator at the 

appropriate address listed in § 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. 

■ 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 

* * * * * 

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TABLE 2 TO SUBPART HHH OF PART 63—APPLICABILITY OF 40 CFR PART 63 GENERAL PROVISIONS TO SUBPART HHH 

General provisions 

reference 

Applicable to 

subpart HHH Explanation 

§ 63.1(a)(1) ............................................... Yes. 

§ 63.1(a)(2) ............................................... Yes. 

§ 63.1(a)(3) ............................................... Yes. 

§ 63.1(a)(4) ............................................... Yes. 

§ 63.1(a)(5) ............................................... No ..................... Section reserved. 

§ 63.1(a)(6) through (a)(8) ........................ Yes. 

§ 63.1(a)(9) ............................................... No ..................... Section reserved. 

§ 63.1(a)(10) ............................................. Yes. 

§ 63.1(a)(11) ............................................. Yes. 

§ 63.1(a)(12) ............................................. Yes. 

§ 63.1(b)(1) ............................................... No ..................... Subpart HHH specifies applicability. 

§ 63.1(b)(2) ............................................... Yes. 

§ 63.1(b)(3) ............................................... No. 

§ 63.1(c)(1) ................................................ No ..................... Subpart HHH specifies applicability. 

§ 63.1(c)(2) ................................................ No. 

§ 63.1(c)(3) ................................................ No ..................... Section reserved. 

§ 63.1(c)(4) ................................................ Yes. 

§ 63.1(c)(5) ................................................ Yes. 

§ 63.1(d) .................................................... No ..................... Section reserved. 

§ 63.1(e) .................................................... Yes. 

§ 63.2 ........................................................ Yes ................... Except definition of major source is unique for this source category and there are 

additional definitions in subpart HHH. 

§ 63.3(a) through (c) ................................. Yes. 

§ 63.4(a)(1) ............................................... Yes.

§ 63.4(a)(2) ............................................... Yes.

§ 63.4(a)(3) ............................................... No ..................... Section reserved. 

§ 63.4(a)(4) ............................................... No ..................... Section reserved. 

§ 63.4(a)(5) ............................................... No ..................... Section reserved. 

§ 63.4(b) .................................................... Yes. 

§ 63.4(c) .................................................... Yes. 

§ 63.5(a)(1) ............................................... Yes. 

§ 63.5(a)(2) ............................................... No ..................... Preconstruction review required only for major sources that commence construction after promulgation of the standard. 

§ 63.5(b)(1) ............................................... Yes. 

§ 63.5(b)(2) ............................................... No ..................... Section reserved. 

§ 63.5(b)(3) ............................................... Yes. 

§ 63.5(b)(4) ............................................... Yes. 

§ 63.5(b)(5) ............................................... No ..................... Section reserved. 

§ 63.5(b)(6) ............................................... Yes. 

§ 63.5(c) .................................................... No ..................... Section reserved. 

§ 63.5(d)(1) ............................................... Yes. 

§ 63.5(d)(2) ............................................... Yes. 

§ 63.5(d)(3) ............................................... Yes. 

§ 63.5(d)(4) ............................................... Yes. 

§ 63.5(e) .................................................... Yes. 

§ 63.5(f)(1) ................................................ Yes. 

§ 63.5(f)(2) ................................................ Yes. 

§ 63.6(a) .................................................... Yes. 

§ 63.6(b)(1) ............................................... Yes. 

§ 63.6(b)(2) ............................................... Yes. 

§ 63.6(b)(3) ............................................... Yes. 

§ 63.6(b)(4) ............................................... Yes. 

§ 63.6(b)(5) ............................................... Yes. 

§ 63.6(b)(6) ............................................... No ..................... Section reserved. 

§ 63.6(b)(7) ............................................... Yes. 

§ 63.6(c)(1) ................................................ Yes. 

§ 63.6(c)(2) ................................................ Yes. 

§ 63.6(c)(3) and (c)(4) ............................... No ..................... Section reserved. 

§ 63.6(c)(5) ................................................ Yes. 

§ 63.6(d) .................................................... No ..................... Section reserved. 

§ 63.6(e) .................................................... Yes. 

§ 63.6(e) .................................................... Yes ................... Except as otherwise specified. 

§ 63.6(e)(1)(i) ............................................ No ..................... See § 63.1274(h) for general duty requirement. 

§ 63.6(e)(1)(ii) ........................................... No. 

§ 63.6(e)(1)(iii) ........................................... Yes. 

§ 63.6(e)(2) ............................................... No ..................... Section reserved. 

§ 63.6(e)(3) ............................................... No. 

§ 63.6(f)(1) ................................................ No. 

§ 63.6(f)(2) ................................................ Yes. 

§ 63.6(f)(3) ................................................ Yes. 

§ 63.6(g) .................................................... Yes. 

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TABLE 2 TO SUBPART HHH OF PART 63—APPLICABILITY OF 40 CFR PART 63 GENERAL PROVISIONS TO SUBPART

HHH—Continued 

General provisions 

reference 

Applicable to 

subpart HHH Explanation 

§ 63.6(h)(1) ............................................... No. 

§ 63.6(h)(2) ............................................... Yes. 

§ 63.6(h)(3) ............................................... No ..................... Section reserved. 

§ 63.6(h)(4) through (h)(9) ........................ Yes. 

§ 63.6(i)(1) through (i)(14) ........................ Yes. 

§ 63.6(i)(15) ............................................... No ..................... Section reserved. 

§ 63.6(i)(16) ............................................... Yes. 

§ 63.6(j) ..................................................... Yes. 

§ 63.7(a)(1) ............................................... Yes. 

§ 63.7(a)(2) ............................................... Yes ................... But the performance test results must be submitted within 180 days after the 

compliance date. 

§ 63.7(a)(3) ............................................... Yes. 

§ 63.7(a)(4) ............................................... Yes. 

§ 63.7(b) .................................................... Yes. 

§ 63.7(c) .................................................... Yes. 

§ 63.7(d) .................................................... Yes. 

§ 63.7(e)(1) ............................................... No. 

§ 63.7(e)(2) ............................................... Yes. 

§ 63.7(e)(3) ............................................... Yes. 

§ 63.7(e)(4) ............................................... Yes. 

§ 63.7(f) ..................................................... Yes. 

§ 63.7(g) .................................................... Yes. 

§ 63.7(h) .................................................... Yes. 

§ 63.8(a)(1) ............................................... Yes. 

§ 63.8(a)(2) ............................................... Yes. 

§ 63.8(a)(3) ............................................... No ..................... Section reserved. 

§ 63.8(a)(4) ............................................... Yes. 

§ 63.8(b)(1) ............................................... Yes. 

§ 63.8(b)(2) ............................................... Yes. 

§ 63.8(b)(3) ............................................... Yes. 

§ 63.8(c)(1) ................................................ Yes. 

§ 63.8(c)(1)(i) ............................................ 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) through (c)(8) ........................ Yes. 

§ 63.8(d)(1) ............................................... Yes. 

§ 63.8(d)(2) ............................................... Yes. 

§ 63.8(d)(3) ............................................... Yes ................... Except for last sentence, which refers to an SSM plan. SSM plans are not required. 

§ 63.8(e) .................................................... Yes ................... Subpart HHH does not specifically require continuous emissions monitor performance evaluations, however, the Administrator can request that one be conducted. 

§ 63.8(f)(1) through (f)(5) .......................... Yes. 

§ 63.8(f)(6) ................................................ No ..................... Subpart HHH does not require continuous emissions monitoring. 

§ 63.8(g) .................................................... No ..................... Subpart HHH specifies continuous monitoring system data reduction requirements. 

§ 63.9(a) .................................................... Yes. 

§ 63.9(b)(1) ............................................... Yes. 

§ 63.9(b)(2) ............................................... Yes ................... Existing sources are given 1 year (rather than 120 days) to submit this notification. 

§ 63.9(b)(3) ............................................... No ..................... Section reserved. 

§ 63.9(b)(4) ............................................... Yes. 

§ 63.9(b)(5) ............................................... Yes. 

§ 63.9(c) .................................................... Yes. 

§ 63.9(d) .................................................... Yes. 

§ 63.9(e) .................................................... Yes. 

§ 63.9(f) ..................................................... Yes. 

§ 63.9(g) .................................................... Yes. 

§ 63.9(h)(1) through (h)(3) ........................ Yes. 

§ 63.9(h)(4) ............................................... No ..................... Section reserved. 

§ 63.9(h)(5) and (h)(6) .............................. Yes. 

§ 63.9(i) ..................................................... Yes. 

§ 63.9(j) ..................................................... Yes. 

§ 63.10(a) .................................................. Yes. 

§ 63.10(b)(1) ............................................. Yes ................... Section 63.1284(b)(1) requires sources to maintain the most recent 12 months of 

data on-site and allows offsite storage for the remaining 4 years of data. 

§ 63.10(b)(2) ............................................. Yes. 

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49600 Federal Register / Vol. 77, No. 159 / Thursday, August 16, 2012 / Rules and Regulations 

TABLE 2 TO SUBPART HHH OF PART 63—APPLICABILITY OF 40 CFR PART 63 GENERAL PROVISIONS TO SUBPART

HHH—Continued 

General provisions 

reference 

Applicable to 

subpart HHH Explanation 

§ 63.10(b)(2)(i) .......................................... No. 

§ 63.10(b)(2)(ii) ......................................... No ..................... See § 63.1284(f) for recordkeeping of (1) occurrence and duration and (2) actions 

taken during malfunction. 

§ 63.10(b)(2)(iii) ......................................... Yes. 

§ 63.10(b)(2)(iv) through (b)(2)(v) ............. No. 

§ 63.10(b)(2)(vi) through (b)(2)(xiv) .......... Yes. 

§ 63.10(b)(3) ............................................. No. 

§ 63.10(c)(1) .............................................. Yes. 

§ 63.10(c)(2) through (c)(4) ...................... No ..................... Sections reserved. 

§ 63.10(c)(5) through (c)(8) ...................... Yes. 

§ 63.10(c)(9) .............................................. No ..................... Section reserved. 

§ 63.10(c)(10) through (c)(11) .................. No ..................... See § 63.1284(f) for recordkeeping of malfunctions. 

§ 63.10(c)(12) through (c)(14) .................. Yes. 

§ 63.10(c)(15) ............................................ No. 

§ 63.10(d)(1) ............................................. Yes. 

§ 63.10(d)(2) ............................................. Yes. 

§ 63.10(d)(3) ............................................. Yes. 

§ 63.10(d)(4) ............................................. Yes. 

§ 63.10(d)(5) ............................................. No ..................... See § 63.1285(b)(6) for reporting of malfunctions. 

§ 63.10(e)(1) ............................................. Yes. 

§ 63.10(e)(2) ............................................. Yes. 

§ 63.10(e)(3)(i) .......................................... Yes ................... Subpart HHH requires major sources to submit Periodic Reports semi-annually. 

§ 63.10(e)(3)(i)(A) ..................................... Yes. 

§ 63.10(e)(3)(i)(B) ..................................... Yes. 

§ 63.10(e)(3)(i)(C) ..................................... No ..................... Section reserved. 

§ 63.10(e)(3)(i)(D) ..................................... Yes. 

§ 63.10(e)(3)(ii) through (e)(3)(viii) ........... Yes. 

§ 63.10(f) ................................................... Yes. 

§ 63.11(a) through (e) ............................... Yes. 

§ 63.12(a) through (c) ............................... Yes. 

§ 63.13(a) through (c) ............................... Yes. 

§ 63.14(a) through (q) ............................... Yes. 

§ 63.15(a) and (b) ..................................... Yes. 

[FR Doc. 2012–16806 Filed 8–15–12; 8:45 am] 

BILLING CODE 6560–50–P 

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