Oil and Natural Gas Sector: Reconsideration of Certain Provisions of 

New Source Performance Standards

40 CFR Part 60 

Response to Public Comments on

Proposed Rule (78 FR 22126; April 12, 2013)

U.S. Environmental Protection Agency

Office of Air Quality Planning and Standards

Sector Policies and Programs Division

Research Triangle Park, NC 27711

July 2013
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Table of Contents

1.0 Summary................................................................................................................................... 1

1.1 Background........................................................................................................................... 1

1.2 Summary of Significant Changes Since Proposal ................................................................ 6

1.2.1 Initial Notification and Compliance Dates .................................................................... 6

1.2.2 Group 1 and Group 2 Storage Vessel Emission Standard Applicability ....................... 6

1.2.5 Definition of Storage Vessel.......................................................................................... 7

1.2.7 Streamlined Compliance Monitoring Provisions........................................................... 7

1.2.8 Combustor Control Device Manufacturer Test Protocol............................................... 7

1.2.9 Annual Report and Compliance Certification................................................................ 7

1.3 Summary of Impacts of Reconsideration.............................................................................. 7

2.0 Response to Comments Regarding Subpart OOOO ................................................................. 8

2.1 Storage Vessel Applicability................................................................................................. 8

2.1.1 Storage Vessel Affected Facility ................................................................................... 8

2.1.2 Storage Vessel Applicability Determination ............................................................... 13

2.2 Storage Vessel Control Requirements................................................................................ 32

2.2.1 General Support for Group 1 Storage Vessel Requirements....................................... 32

2.2.2 Control Equipment Design Requirements................................................................... 32

2.2.3 Electronic Ignition Systems......................................................................................... 34

2.2.4 Flares............................................................................................................................ 36

2.2.5 Carbon Adsorption....................................................................................................... 37

2.2.6 Control Device Operating Requirements..................................................................... 37

2.2.7 Storage Vessel Alternative Control Requirement........................................................ 39

2.3 Storage Vessel Recordkeeping Requirements.................................................................... 40

2.4 Storage Vessel Notification and Reporting Requirements ................................................. 41

2.4.1 Initial Notification Exemption for Compressors.......................................................... 41

2.4.2 Initial Notification for Group 1 Storage Vessels ......................................................... 41

2.4.3 Responsible Official..................................................................................................... 42

2.4.4 Reporting Deadline ...................................................................................................... 44

2.5 Compliance Demonstration and Monitoring Provisions..................................................... 45
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2.5.1 Vapor Recovery Units.................................................................................................. 45

2.5.2 Leaking Closed Vent Systems and Covers.................................................................. 45

2.5.3 Performance Testing .................................................................................................... 46

2.5.4 Compliance Monitoring Requirements........................................................................ 53

2.5.5 Startup, Shutdown and Malfunction ............................................................................ 54

2.6 Compliance Schedule.......................................................................................................... 55

2.7 Number of Storage Vessels at Different Throughput Levels (“Higher Emitting”) ............ 56

2.8 Small Business Impacts ...................................................................................................... 57
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Acronyms and Abbreviations

API American Petroleum Institute

BACT Best Available Control Technology

BPD Barrels Per Day

BSER Best System of Emission Reduction

CAA Clean Air Act

CFR Code of Federal Regulations

CO Carbon Monoxide

CO2 Carbon Dioxide

EPA Environmental Protection Agency

ERPG Emergency Response Planning Guidelines

ERT Electronic Reporting Tool

MACT Maximum Achievable Control Technology

NOX Oxides of Nitrogen

NSPS New Source Performance Standards

OAQPS Office of Air Quality Planning and Standards

OMB Office of Management and Budget

PTE Potential to Emit

RTC Response to Comments

SO2 Sulfur Dioxide

SSM Startup, Shutdown and Malfunction

TPY Tons per Year

VOC Volatile Organic Compounds

VRU Vapor Recovery Unit
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1.0 Summary

1.1 Background

On January 14, 2009, pursuant to section 304(a)(2) of the Clean Air Act (CAA), 

WildEarth Guardians and the San Juan Citizens Alliance filed a Complaint alleging that the U.S. 

Environmental Protection Agency (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 new 

source performance standards (NSPS) and the national emissions standards for hazardous air 

pollutants (NESHAP) with respect to the Oil and Natural Gas Production source category. On 

February 4, 2010, a consent decree was entered that, as modified, required the EPA to sign by 

July 28, 2011, proposed standards and/or determinations not to issue standards pursuant to CAA 

sections 111(b)(1)(B), 112(d)(6) and 112(f)(2) and to take final action by April 3, 2012.

On August 8, 2011, the EPA announced (76 FR 52738) how the Agency proposed to 

address the reviews of the new source performance standards (NSPS) for volatile organic 

compound (VOC) and sulfur dioxide (SO2) emissions from natural gas processing plants. The 

EPA proposed to add to the source category list any oil and gas operation not covered by the 

current listing. This action also included proposed amendments to the existing NSPS for VOCs 

from natural gas processing plants and proposed standards for operations not covered by the 

existing NSPS. In addition, this action proposed how the EPA would address the residual risk 

and technology review (RTR) conducted for the oil and natural gas production and natural gas 

transmission and storage national emission standards for hazardous air pollutants (NESHAP). 

The EPA further proposed standards for emission sources within these two source categories that 

were not then addressed, as well as amendments to improve aspects of these NESHAP related to 

applicability and implementation. Finally, the EPA addressed provisions in these NSPS and 

NESHAP related to emissions during periods of startup, shutdown and malfunction (SSM).

On August 16, 2012, the EPA published final NSPS and NESHAP for the oil and natural 

gas sector (77 FR49490). The Administrator received petitions for reconsideration of certain 

aspects for the standards.

On April 12, 2013, the EPA announced their proposed amendments to the oil and natural 

gas sector NSPS as a result of reconsideration of certain issues related to implementation of 

storage vessel provisions. Twenty-six comment letters were received on the proposed 

amendments and entered into the EPA’s Air and Radiation docket assigned for this rulemaking 

(docket number EPA-HQ-OAR-2010-0505). The EPA reviewed all of the comment letters 

entered into the docket.

This document presents a summary of the public comments entered into docket EPA-HQOAR-2010-0505 regarding specific issues and topics related to the development of the proposed 

subpart OOOO NSPS (40 CFR part 60) amendments and the EPA’s responses to those 

comments. The EPA assigned these comments to specific categories (see Table of Contents) 

based on an assessment of the principal subject of the comment; however, some comments 

inevitably overlap multiple subject areas. Table 1 provides the list of comments received by 
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docket document ID, the commenter and their affiliation. The last 4 digits of the docket 

document ID are used to identify comments summarized and responded to in this document.
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Table 1. List of Commenters on the Oil and Natural Gas Sector: Reconsideration of Certain Provisions of 

New Source Performance Standards; Proposed Rule (78 FR 22126; April 12, 2013)

Document ID Name and Affiliation Date Received

EPA-HQ-OAR-2010-0505-4609 Comment submitted by S. 

Akhmetkaliyeva 4/21/2013

EPA-HQ-OAR-2010-0505-4610 Anonymous public comment 4/26/2013

EPA-HQ-OAR-2010-0505-4611

Comment submitted by William C. 

Allison V, Director, Air Pollution 

Control Division, Colorado 

Department of Public Health and 

Environment

5/13/2013

EPA-HQ-OAR-2010-0505-4612

Comment submitted by Thure 

Cannon, President, Texas Pipeline 

Association (TPA)

5/13/2013

EPA-HQ-OAR-2010-0505-4613

Comment submitted by Gretchen C. 

Kern, Regulatory Advisor, 

Sustainable Development, Pioneer 

Natural Resources USA, Inc.

5/24/2013

EPA-HQ-OAR-2010-0505-4614

Comment submitted by Mark W. 

Sommer, General Manager, Power 

Ignition and Controls, LLC (PIC 

Appalachia)

5/28/2013

EPA-HQ-OAR-2010-0505-4615

Comment submitted by Jeff 

Applekamp, Director, Government 

Affairs, Gas Processors Association 

(GPA)

5/28/2013

EPA-HQ-OAR-2010-0505-4616

Comment submitted by R. Andrew 

Smith, Advanced Burner 

Technologies (ABUTEC)

5/28/2013

EPA-HQ-OAR-2010-0505-4617

Comment submitted by Kathleen M. 

Sgamma, Vice President, 

Government and Public Affairs, 

Western Energy Alliance

5/28/2013

EPA-HQ-OAR-2010-0505-4618

Comment submitted by Zak Covar, 

Executive Director, Texas 

Commission on Environmental 

Quality (TCEQ)

5/28/2013
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Document ID Name and Affiliation Date Received

EPA-HQ-OAR-2010-0505-4619

Comment submitted by Mickey 

Thompson, Executive Director, 

Domestic Energy Producers Alliance 

(DEPA)

5/28/2013

EPA-HQ-OAR-2010-0505-4620

Comment submitted by Amy Farrell, 

Vice President of Regulatory 

Affairs, America’s Natural Gas 

Alliance (ANGA) and V. Bruce 

Thompson, President, American 

Exploration and Production Council 

(AXPC)

5/28/2013

EPA-HQ-OAR-2010-0505-4621

Comment submitted by Andrew V. 

McNeill, Executive Director, 

Kentucky Oil and Gas Association 

(KOGA)

5/28/2013

EPA-HQ-OAR-2010-0505-4622 Comment submitted by David 

McCabe, Clean Air Task Force et al. 5/28/2013

EPA-HQ-OAR-2010-0505-4623

Comment submitted by Cory 

Pomeroy, General Counsel, Texas 

Oil & Gas Association (TXOGA)

5/28/2013

EPA-HQ-OAR-2010-0505-4624

Comment submitted by Alice 

Edwards, Director, Division of Air 

Quality, Alaska Department of 

Environmental Conservation 

(ADEC)

5/28/2013

EPA-HQ-OAR-2010-0505-4625

Comment submitted by Nikki C. 

Martin, Regulatory and Legal 

Affairs Manager, Alaska Oil and 

Gas Association (AOGA)

5/29/2013

EPA-HQ-OAR-2010-0505-4626

Comment submitted by James D. 

Elliott, Spilman Thomas & Battle, 

PLLC on behalf of Lee O. Fuller, 

Vice President of Government 

Relations, Independent Petroleum 

Association of America (IPAA)

5/28/2013

EPA-HQ-OAR-2010-0505-4627

Comment submitted by Laura J. 

Finley, Air Quality Attorney, Office 

of the General Counsel, Oklahoma 

5/28/2013
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Document ID Name and Affiliation Date Received

Department of Environmental 

Quality (ODEQ)

EPA-HQ-OAR-2010-0505-4628

Comment submitted by John 

Robitaille, Vice President, 

Petroleum Association of Wyoming 

(PAW)

5/28/2013

EPA-HQ-OAR-2010-0505-4629

Comment submitted by Kyle D. 

Shotts, Manager, Combustion Rental 

and Rapid Execution Group, Zeeco, 

Inc.

5/28/2013

EPA-HQ-OAR-2010-0505-4630

Comment submitted by Matthew 

Todd, Senior Policy Advisor, 

American Petroleum Institute (API)

5/28/2013

EPA-HQ-OAR-2010-0505-4631

Comment submitted by Louis D. 

D'Amico, President and Executive 

Director, Pennsylvania Independent 

Oil and Gas Association (PIOGA)

5/24/2013

EPA-HQ-OAR-2010-0505-4632

Comment submitted by Matthew S. 

Stone, President, Indiana Oil and 

Gas Association (INOGA)

6/3/2013

EPA-HQ-OAR-2010-0505-4633

Comment submitted by Adrian 

Araiza, Manager, Air Quality 

Compliance, Cimarex Energy Co.

6/3/2013

EPA-HQ-OAR-2010-0505-4634

Comment submitted by Barry T. 

Smitherman, Chairman et al., 

Railroad Commission of Texas

6/4/2013
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1.2 Summary of Changes Since Proposal

This section describes significant changes made to the reconsideration proposal that the 

EPA is now finalizing in this rule. 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.

1.2.1 Initial Notification and Compliance Dates

For Group 1 storage vessel affected facilities, we have amended the 2012 NSPS to 

require that a notification be submitted with the initial annual report to inform regulatory 

agencies of the existence and location of the vessels. In addition, we have amended the 2012 

NSPS to require that all Group 1 storage vessel affected facilities comply with the emission 

standards no later than April 15, 2015 and that all Group 2 storage vessel affected facilities 

comply with emission standards no later than April 15, 2014 (or 60 days after startup, whichever 

is later).

The final amendments also make clarifying changes to §60.5365 that clearly specify 

October 15, 2013, as the deadline for calculating potential VOC emissions from Group 1 storage 

vessels to determine affected facility status.

1.2.2 Group 1 and Group 2 Storage Vessel Emission Standard Applicability

We have amended §60.5395 to clearly state that the emission standards apply to Group 1 

and Group 2 storage vessel affected facilities (as opposed to all storage vessels).

1.2.3 Group 1 Storage Vessel Affected Facility Control Requirements

The final amendments retain the requirement in the 2012 NSPS that all storage vessel 

affected facilities meet the emission standards. However, the final amendments require that 

owners and operators of Group 1 storage vessel affected facilities comply with the emission 

standards by April 15, 2015.

1.2.4 Alternative 4-tpy Uncontrolled Actual Emission Rate

We have amended the storage vessel standards to include a sustained uncontrolled actual 

VOC emission rate of less than 4 tpy. Specifically, an owner or operator may comply with the 

uncontrolled actual VOC emission rate instead of the 95 percent control requirement where it can 

be demonstrated that, based on records of monthly emission estimates for the 12 months 

immediately preceding the demonstration, that the storage vessel affected facility uncontrolled 

actual VOC emissions estimated each of those months were below 4 tpy. The owner or operator 

would be required to re-evaluate the uncontrolled actual VOC emissions on a monthly basis to 

ensure that emissions do not reach 4 tpy. 
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1.2.5 Definition of Storage Vessel

The final amendments revise the definition of “storage vessel” to clarify that it refers only 

to vessels containing crude oil, condensate, intermediate hydrocarbon liquids or produced water. 

1.2.6 Definition of Storage Vessel Affected Facility

The final amendments revise the definition of “storage vessel affected facility” (see 

§60.5365(e)) to (1) include the 6 tpy VOC emission threshold and to clarify that a source can 

take into account any legally and practically enforceable emission limit under federal, state, local 

or tribal authority when determining the VOC emission rate for purposes of this threshold; (2) 

clarify that a storage vessel affected facility whose VOC PTE decreases to less than 6 tpy would 

remain an affected facility; (3) replace the term “other mechanisms” with “other requirements” 

and clarify that such requirements must be legally and practically enforceable under federal, 

state, local or tribal authority; and (4) allow PTE determination to exclude any vapor from the 

storage vessel that is routed to a process via a closed vent system designed and operated 

according to the closed vent requirements in the final amendments.

1.2.7 Streamlined Compliance Monitoring Provisions

For storage vessels that install controls to meet the 95 percent VOC reduction standard, 

we have amended the 2012 NSPS to adopt the streamlined compliance monitoring provisions as 

proposed without significant changes. These compliance monitoring provisions include 

inspections performed at least monthly of covers, closed-vent systems and control devices. We 

continue to evaluate the reconsideration issues raised concerning the compliance monitoring 

provisions in the 2012 NSPS and intend to complete our reconsideration by the end of 2014.

1.2.8 Combustor Control Device Manufacturer Test Protocol

We have finalized amendments to the combustor control device manufacturer test 

protocol in the NSPS to align it with a similar protocol in the Oil and Natural Gas National 

Emission Standards for Hazardous Air Pollutants (NESHAP) (40 CFR 63, subpart HH).

1.2.9 Annual Report and Compliance Certification

We finalized amendments to allow 90 days after the end of the compliance period for 

submittal of the annual report and compliance certification.

1.3 Summary of Impacts of Reconsideration

Owners and operators of storage vessel affected facilities are expected to install and 

operate the same or similar control technologies under these final amendments as would have 

been necessary to meet the previously finalized standards under the 2012 NSPS. We project that 

these amendments will not result in a significant change in costs or benefits. Since we believe 

that the same controls will be used for these final amendments as would have been used for the 

2012 final rule, there should not be any incremental costs related to this proposed revision.
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2.0 Response to Comments Regarding Subpart OOOO

2.1 Storage Vessel Applicability

2.1.1 Storage Vessel Affected Facility 

2.1.1.1 Deadline for Determining Whether a Storage Vessel is an Affected Facility

Comment: Several commenters (4613, 4617, 4620, 4626, 4631, 4633) request that the 

EPA consider a longer timeframe to determine VOC emissions from Group 2 storage vessels. A 

few of the commenters (4613, 4617, 4626) recommend a minimum of 90 days be allowed 

(versus the 60 days proposed) to determine emissions and install ay necessary controls.

One commenter (4613) requests a 90 day versus 60 day timeframe to evaluate emissions 

and install any necessary controls. The commenter recommends that the emissions evaluation 

period and control device installation period for all storage vessels (including Group 1 vessels) 

that have a triggering event, run simultaneously and should be extended to at least 90 days. The 

commenter provides that production and emissions data reportedly are often not available until 

up to 60 days after the date of first production, and procuring a control device, plus installation, 

can take weeks to months depending on the availability of controls. Further, according to the 

commenter, it is impossible to know at this point if the control device market will be able to keep 

pace with the demand so additional time is reasonable, given the uncertainties.

One commenter (4633) is concerned about the availability of flare control devices to 

meet the compliance provisions and compliance date of April 15, 2014, for affected Group 2 

storage vessels. The commenter requests that the EPA extend the compliance date for Group 2 

storage vessels. Alternatively, the commenter requests that the EPA raise the PTE VOC 

emissions threshold above the already established 6 tpy to only control higher emitting storage

vessels by April 15, 2014.

One commenter (4626) requests that the EPA extend the proposed deadline for Group 2 

storage vessels, who must determine VOC emissions by April 15, 2014, or 30 days after startup.

The commenter asserts that these time periods are too short. The commenter recommends that, at 

a minimum, 90 days is necessary to conduct the required emissions calculation and install 

controls. The commenter asserts that the first 30 days of production normally are not 

representative of stabilized production from a well, and are subject to variation that could result 

in the overestimation or underestimation of the emissions from storage vessels associated with 

that well. Thus, according to the commenter, at least 45 days is needed to evaluate and accurately 

calculate projected annual emissions from a storage vessel, and another 45 days would be needed 

to engage a contractor and install the necessary controls. The commenter provides that allowing 

a total of 90 days to make the initial emissions determination and install any necessary controls 

will ensure a more reliable emissions estimate and afford the regulated community sufficient 

time to contract for the testing/modeling of emissions and installation of controls.

The commenter (4626) requests that, if the EPA does not differentiate between storage 

vessels at new and existing facilities, the EPA institute an extended compliance period for 
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vessels at new facilities. According to the commenter, an extended compliance period for vessels 

at new facilities for a period of 2 years will reduce the likelihood that independent producers will 

be exposed to enforcement due to the lack of available equipment and service providers, while 

continuing to ensure that emissions reductions occur in a timely fashion.

Another commenter (4631) recommends that the rule be revised to allow up to 120 days 

from startup to make the annual storage vessel VOC emissions determination. The commenter 

states that the additional time will allow operators to better understand and predict the well 

decline and more accurately predict annual storage vessel VOC emissions thereby avoiding 

situations where unnecessary controls are required on new storage vessels. The commenter states 

that, during this period, the requirement to minimize emissions would still apply and should 

annual VOC emissions exceed 6 tpy, controls will be required to be in place no later than 150 

days from startup. The commenter states that, in the proposed rule under §60.5395(c), the EPA 

has allowed 30 days following startup to determine the VOC emission rate from Group 2 storage 

vessels. The commenter reports that, during the initial production phase of a well, liquid 

production levels are typically at their highest levels and then gradually decrease through a 

relatively brief (e.g., 30 to 180 day) decline period. Therefore, the commenter asserts that annual 

VOC emission estimates established during the first 30 days of production will likely exceed the 

actual observed annual VOC emissions for the storage vessels associated with the well when the 

liquids production decline curve is incorporated. The commenter is concerned that using initial, 

highest well production rates (i.e., first 30 days) rather than incorporating a representative 

decline curve into the storage vessel VOC emission estimate will lead to conservatively high 

VOC estimates that will result in the installation of unnecessary emission controls that would not 

be cost effective. According to the commenter, in accordance with proposed §60.5395(d)(2), the 

owner or operator would need to wait a full 12 months before having the opportunity to remove 

such control devices when the uncontrolled storage vessel VOC emissions drop below 4 tons per 

year. The commenter states that installation of, and 12-month operation of, VOC control devices 

on storage vessels with actual annual VOC emissions of less than 6 tons per year would 

contribute to the cited shortage.

Another commenter (4617) requests that the EPA consider a longer timeframe to 

determine VOC emissions, and that they believed that 30 days may be too short. The commenter 

believes 60 days is a more appropriate time to understand emissions and recommends 90 days to 

install controls. According to the commenter, production rates and well characteristics are often 

not well understood until after 60 days of production. For example, the commenter reports that 

there could still be flowback fluids within this 30 day timeframe and inclement weather can 

hinder the amount of data available to estimate emissions. The commenter asserts that, requiring 

the evaluation of controls within 30 days could result in improper design of a control device and 

could lead to excess emissions from supplemental make-up fuel or from the inability of the 

control device to handle a larger volume of waste gas.

One commenter (4620) supports the extension of the 60-day time frame for the design 

and installation of control devices to all storage vessels. However, the commenter believes that a 

90-day period is more appropriate. The commenter reports that 90 days is required in order for 

many operators to evaluate emissions and install any necessary control device. According to the 

commenter, production and emissions data are often not available until up to 60 days after the 
10

date of first production and control device design. The commenter asserts that installation can 

take months depending on the availability of controls. Additionally, the commenter reports that 

emissions evaluation and control design and installation schedules can vary between companies. 

Thus, the commenter believes that requiring the emissions evaluation and control device 

installation within the 90 days provides for sufficient flexibility and maintains the real emission 

reductions required by the rule.

Response: The EPA does not agree with the commenters who variously requested that 

owners or operators be allowed 90 or 150 days or, for new facilities, 2 years to determine storage 

vessel emissions and install controls. Rather, the EPA continues to believe that a period of 

30 days after startup is sufficient for an owner or operator to determine storage vessel emissions 

and that an additional 30 days, for a total of 60 days after startup, is sufficient to install any 

necessary controls. The State of Wyoming already requires controls to be installed on storage 

vessels within 60 days or less, depending on the location of the storage vessel and other factors, 

which we believe demonstrates that this is a workable time period. Accordingly, we have 

finalizing these requirements as proposed.

While we agree with the commenters who indicate that emissions typically decline and 

stabilize over time after startup, the EPA disagrees that this justifies delaying the determination 

of storage vessel emissions and the installation of controls. Rather, we believe that it would be 

inappropriate to allow emissions to go uncontrolled for any longer than necessary during this 

period of highest emissions. As noted above, we believe that 60 days after startup is sufficient for 

owners or operators to determine emissions and install controls and, therefore, we believe that it 

would be inappropriate to allow more than 60 days. 

In response to the commenters who recommended longer compliance deadlines (or 

alternatively requiring control only for “higher emitting storage vessels”) due to concern about 

the availability of control equipment and service providers, we no longer believe that to be an 

issue. See section IV.A of the preamble to the final amendments for a discussion of control 

device availability.

2.1.1.2 Support for storage vessel affected facility definition

Comment: Several commenters (4613, 4615, 4617, 4620, 4633) provide support for the 

EPA’s amended storage vessel affected facility definition in §60.5365(e). Three of the 

commenters (4615, 4617, 4620) provide that they believe that the revised definition will decrease 

the administrative burden of the rule while ensuring low emissions rates.

One of the commenters (4613) asserts that, even though the 2012 NSPS requirement to 

control affected facility tanks contains an emissions threshold and achieves the environmental 

benefits intended under this rule, the recordkeeping burden for all storage vessel affected 

facilities subject to the rule based solely on the 2012 final rule's proposal date (without the 6 tpy 

emissions threshold) would be excessively burdensome.

Response: We acknowledge the commenters’ support and agree that the revised 

definition of “storage vessel affected facility” will reduce the administrative burden of the rule 
11

while maintaining the intended emissions reductions. See section IV.C of the preamble to the 

final amendments for more on the final affected facility definition for storage vessels.

2.1.1.3 Storage vessels whose emissions fall below 6 tpy and are required to remain affected 

facility should be limited to certain types of storage vessels

Comment: Two commenters (4615, 4630) state that the provision that a storage vessel 

that decreases emissions below 6 tpy VOC remains an affected facility should not apply to a 

storage vessel affected facility that is moved from one location to another. The commenters 

assert that it would be nearly impossible for the buyer of a used tank to determine whether the 

tank to be purchased was a “storage vessel affected facility” at its previous location, thus 

effectively making all used storage vessels affected facilities. The commenters further state that 

because storage vessel potential emissions are site specific, the storage vessel potential to emit at 

a previous location is irrelevant to the new location.

Response: We disagree that a relocated storage vessel should no longer be considered an 

affected facility. However, we have added language at §60.5395(f) to address storage vessel 

affected facilities that are removed from service. Owners and operators are required to include a 

notification in their next annual report that the storage vessel has been taken out of service. If the 

storage vessel is subsequently returned to service due to fracking or refracking of a well feeding 

the storage vessel, then the owner or operator must comply with the control requirements of 

§60.5395(d) immediately upon return to service. If, however, the storage vessel’s return to 

service in not associated with well fracturing or refracturing, the PTE of the storage vessel must 

be determined within 30 days. If the PTE is 4 tpy or greater, then the storage vessel affected 

facility must comply with control requirements within 60 days of returning to service. In either 

of these situations, the owner or operator is also required to include a notification in their next 

annual report that the storage vessel has been returned to service.

See section V.B of the preamble to the final amendments for additional discussion of the 

provision that storage vessel affected facilities that decrease emissions below 6 tpy VOC remain 

an affected facility.

2.1.1.4 Affected Storage Vessel Facility Custody Transfer

Comment: One commenter (4618) requests that storage vessel affected facility 

applicability be clarified to assist an owner or operator in determining the applicability of the 

NSPS to a storage vessel after a custody transfer.

According to the commenter (4618), it appears the NSPS states that storage vessels 

downstream of the point of custody transfer are no longer subject to the rule. The commenter 

requests that the EPA confirm this interpretation, or clarify their intent as to how custody transfer 

affects the applicability of the NSPS to storage vessels. The commenter provides an example 

where multiple companies are involved with the handling of oil and gas products and the chain 

of custody includes a wellhead, a gathering station, and a processing plant: Company A owns the 

wellhead and transfers liquids offsite via pipeline to a gathering station owned by Company B. 

Company B sends the liquids on to a processing plant owned by Company C. The commenter 

states that, in this example, their interpretation of the NSPS indicates that the NSPS appears only 
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to apply to storage vessels operated by Company A, and would not apply to vessels at 

Companies B or C because those vessels are after the point of initial custody transfer.

Another commenter (4630) suggests that the term custody transfer not be limited to the 

transfer of natural gas. The commenter recommends that the definition of custody transfer be 

revised to encompass the transfer of liquid hydrocarbons as well. The commenter provides 

examples in paragraphs §60.5365(d)(1) and §60.5390(c)(1) where the phrase “the point of 

custody transfer to an oil pipeline,” is used, which implies transfer of liquids. The commenter 

states that this phrase is also used in the preamble [78 FR 22133] to describe the boundaries of 

applicability for storage vessels. According to the commenter, since the EPA repeatedly uses the 

term custody transfer in a context that pertains to transfer of liquids, the definition should be 

revised to expressly denote that the term applies to the transfer of liquids as well as to the 

transfer of natural gas.

Commenter 4630 also states that the applicability should be specified to end at the point 

of custody transfer to an oil pipeline. The commenter believes that this would be consistent with 

§§60.5365(d)(1) and 60.5390(c)(1) for pneumatic controllers. In addition, the commenter 

suggests that the EPA add the phrase "or any other form of transportation" to §60.5360(e) to 

address scenarios in which the crude oil is transported from the production field by truck (or 

railcar, etc.). The commenter states that this phrase comes from the NSPS subpart Kb definition 

of custody transfer and is used in the definition of custody transfer in this rule (§60.5430), but 

states that the definition in this rule is inexplicably limited to the transfer of natural gas.

Response: The EPA does not agree with the commenter’s example and conclusion that 

storage vessels after the point of initial “custody transfer” (as interpreted by the commenter) 

through a pipeline at the wellhead would not be subject to the NSPS. This interpretation is 

apparently based on the EPA’s statement in the preamble to the proposed amendments at 78 FR 

22133 that “[i]t is our intent that the NSPS address VOC emissions from storage vessels located 

not only at wells but at any location from the well to the point of custody transfer to an oil 

pipeline or to the point of custody transfer from the natural gas transmission and storage segment 

to the local distribution company.” However, we note that the governing language from the 2012 

NSPS, unchanged by these amendments, is found in §60.5365(e) where the storage vessel 

affected facility is defined to include “a single storage vessel located in the oil and natural gas 

production segment, natural gas processing segment or natural gas transmission and storage 

segment” with no mention of custody transfer. The statement in the preamble to the proposed

amendments was intended to further illustrate the affected facility description in §60.5365(e). 

Based on the examples provided by the commenter, it is clear that the preamble illustration lends 

itself to misinterpretation. In any case, the language in §60.5365(e) is correct, and thus storage 

vessels located outside the oil and natural gas production, natural gas processing and natural gas 

transmission and storage segments would not be subject to subpart OOOO.

We are not making any changes to the final amendments at this time in response to this 

comment because of the reasons stated above and also because the term “custody transfer” is 

used in other sections of the 2012 NSPS not affected by these final amendments. However, we 

continue to evaluate these comments for consideration in our subsequent rulemaking to be 

completed by the end of 2014.
13

2.1.2 Storage Vessel Applicability Determination

2.1.2.1 Definition of Storage Vessel

Comment: Several commenters (4613, 4623, 4624) support the EPA’s proposal to revise 

the definition of “storage vessel” as being limited to those “vessels that contain crude oil, 

condensate, intermediate hydrocarbon liquids, or produced water.” 

Response: We acknowledge the commenters’ support and have finalized the proposed 

changes to the definition.

Comment: One commenter (4633) requests that the final rule language for the definition 

of storage vessel in §60.5430 read as follows: "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 nonearthen materials (such as wood, concrete, steel, 

fiberglass, or plastic) which provide structural support."

Response: We do not agree with the commenter’s suggested change to the proposed 

definition and have not incorporated it into the final definition. In addition to creating potential 

enforcement complications, we believe that including storage vessels that were “designed for” 

storage of the listed liquids could potentially bring storage vessels under the NSPS that are not, 

in practice, used to store the listed liquids. This is not the intent of the amendments.

2.1.2.2 Group 1 and Group 2 Storage Vessel Determination

Comment: One commenter (4630) requests that the EPA modify the requirement for 

identifying storage vessels that come into applicability during the reporting period as being tied 

to startup of the affected facility and not when the storage vessel is constructed, modified or 

reconstructed during the reporting period. The commenter requests that paragraph 

§60.5420(b)(6)(i) be edited to reference the date of startup for an affected facility, rather than the 

date upon which construction, reconstruction, or modification commences. According to the 

commenter, the initial annual report, which is due 90 days after the end of the initial reporting 

period, is to include documentation of the potential VOC emission rate (which is to be 

determined within 30 days after startup) as well as a statement that compliance with the standard 

has been achieved (which is to be achieved within 60 days after startup). In that the information 

to be reported is tied to due dates after startup, the commenter maintains that this provision for 

determining which storage vessels are to be included in a reporting period should also be tied to 

startup.

Two commenters (4613, 4620) request clarification on the definition of "construction" for 

storage vessels. Specifically, the commenters seek clarification of the EPA's intent with regards 

to the use of the terms "constructed, modified or reconstructed" between specified dates and not 

premised with the word "commence" in §§60.5395 and 60.5430. The commenters also request 

that construction be triggered with "on-site fabrication, installation or erection" of the vessel per 

the "construction" definition in 40 CFR part 52.21. The commenters state that if the EPA 

interprets the rule to include "commence" and for construction to be triggered when the contract 

is entered into to procure a vessel that the EPA allow either definition discussed because the "on-
14

site fabrication, installation or erection" trigger is a more conservative option that would 

ultimately default more vessels into the rule. According to one commenter (4620), these vessels 

are generally mass produced and it is common practice to have several vessels available in a 

storage yard awaiting installation at various facilities.

One commenter (4623) recommends that the EPA define Group 1 and Group 2 vessels in 

relation to the date that construction commences. The commenter states that the proposed 

§60.5430 defines Group 1 and Group 2 storage vessels as those “constructed, modified or 

reconstructed” as of certain dates. However, according to the commenter, §§60.5360 and 

60.5365 state that the subpart applies to facilities that “commence construction, modification or 

reconstruction after [specified date].” The commenter provides that §§60.5360 and 60.5365 are 

in accordance with the EPA’s longstanding approach that its rules apply on the date when 

equipment has been ordered, even if actual construction has not begun. The commenter believes 

that the use of the phrase “constructed, modified or reconstructed,” without any qualification, to 

define Group 1 and Group 2 vessels could be read as treating some vessels that commence 

construction prior to the Group 2 trigger date as Group 2 vessels. The commenter suggests that 

the EPA revise the definitions of Group 1 and 2 vessels to include a reference to commencement 

of construction. The commenter states that, if the EPA does not adopt a “commence 

construction” approach for delineating between Groups 1 and 2, the insertion of 

“commencement” would be needed at least with respect to the Group 1 definition because 

otherwise, the EPA would classify as Group 1 a vessel that commenced construction prior to the 

rule applicability date of August 23, 2011, but was “constructed” after that date. The commenter 

also suggests that the EPA clarify what it means to be “constructed, modified or reconstructed.”

Another commenter (4611) requests that the rule require that emission rates for affected 

storage vessel facilities that are not located at well sites be determined prior to commencing 

construction. According to the commenter, emission rates at production field facilities and 

natural gas processing plants are typically known at design time. The commenter reports that 

many of these facilities are classified as major stationary sources or major sources of criteria or 

HAP emissions. The commenter further reports that construction, modification or reconstruction 

of an affected storage vessel facility at these larger facilities may trigger additional requirements 

unless they are permitted appropriately in a permit issued prior to construction.

Response: The EPA did not intend to depart from the CAA and Part 60 General 

Provisions definitions governing applicability based on the commencement of construction, 

reconstruction or modification. It was an oversight on our part to refer in the proposed 

amendments to the dates of construction, reconstruction or modification, rather than the dates 

that those activities commenced. Accordingly, the final amendments have been revised to 

include the commencement of construction, reconstruction or modification as the trigger point in 

the annual reporting requirements for storage vessels at §60.5420(b)(6)(i) and the definitions of 

Group 1 and Group 2 storage vessels at §60.5430. The references to these activities that were 

included in proposed §60.5395 were not finalized as part of revisions for other purposes.

The EPA’s intention to conform to CAA and Part 60 General Provisions usage in this 

rule is clear from the language in §§60.5360 and 60.5365 of the 2012 NSPS, which is unchanged 

by the final amendments:
15

§60.5360 What is the purpose of this subpart?

This subpart establishes emission standards and compliance schedules for the control of 

volatile organic compounds (VOC) and sulfur dioxide (SO2) emissions from affected facilities 

that commence construction, modification or reconstruction after August 23, 2011. 

§60.5365 Am I subject to this subpart?

You are subject to the applicable provisions of this subpart if you are the owner or 

operator of one or more of the onshore affected facilities listed in paragraphs (a) through (g) of 

this section for which you commence construction, modification or reconstruction after August 

23, 2011. 

However, in drafting the proposed amendments, we unintentionally left out the 

established concept that requirements are triggered based on the date that construction, 

modification or reconstruction commences. We have corrected this oversight in the final 

amendments.

Regarding the appropriate interpretation of the terms “construction” and “commence,” 

we rely on the NSPS General Provisions and NSPS program precedent. The NSPS General 

Provisions at §60.2 define these terms as follows:

Construction means fabrication, erection, or installation of an affected facility.

Commenced means, with respect to the definition of new source in section 111(a)(2) of 

the Act, that an owner or operator has undertaken a continuous program of construction or 

modification or that an owner or operator has entered into a contractual obligation to undertake 

and complete, within a reasonable time, a continuous program of construction or modification.

We do not believe that it is necessary here to elaborate on the application of these terms 

to storage vessels under this subpart. Implementing agencies have a wealth of experience in 

addressing applicability issues, and we are confident in their ability to apply these terms 

appropriately. 

The EPA disagrees with the comment suggesting that applicability during the reporting 

period be tied to startup of the affected facility rather than when the storage vessel is 

constructed/modified/reconstructed. Under CAA section 111(a)(2) and EPA’s General 

Provisions in 40 CFR part 60, NSPS applicability is based on the commencement date of 

construction, modification or reconstruction, not start-up date.

Regarding the suggestion that the “construction” definition in 40 CFR 52.21 be applied to 

storage vessels under this subpart, we disagree. The NSPS program is well established with a 

long implementation history based on CAA section 111 and the implementing regulations in 

40 CFR part 60, which has long standing definitions for the statutory terms “commence” and 

“construction.” The commenter has not distinguished storage vessels from other NSPS affected 

sources or otherwise explain why storage vessels should be afforded different definitions for 

these statutory terms. 
16

We also disagree with the suggestion that the rule should require that emission rates for 

affected storage vessel facilities that are not located at well sites be determined prior to 

commencing construction. While we agree that it may be possible to determine emission rates at 

some facilities downstream from the well site prior to startup, we believe that it would be 

extremely difficult to define the cut point for such a distinction in a way that would be both clear 

and universally applicable. To maintain simplicity and consistency and avoid introducing 

uncertainty into determining the applicable requirements, we have finalized the amendments 

without creating the suggested differentiation among storage vessels. We do not believe that the 

requirements for preconstruction permitting of storage vessels bear on the structure of the final 

amendments.

Comment: One commenter (4630) requests that the EPA make changes to the definitions 

for Group 1 and Group 2 storage vessels. The commenter states that consistency with §§60.5360 

and 60.5365, the definition of Group 1 storage vessel should read “after August 23, 2011,” rather 

than “on or after August 23, 2011,” and should stipulate that the trigger is the commencement of 

construction, modification or reconstruction. The commenter explains that determination of 

whether a storage vessel is potentially subject to the rule is based on the date upon which 

construction, modification or reconstruction commences, but determination of when the initial 

report is due for that storage vessel is based on the date of startup. The commenter requests that a 

similar clarification be made in the definition of Group 2 storage vessel.

Response: We agree with the commenter that the definition of “Group 1 storage vessel” 

should read “after August 23, 2011,” rather than “on or after August 23, 2011,” consistent with 

§§60.5360 and 60.5365. As discussed in the previous response, we also agree that the definition 

should stipulate that the trigger is the commencement of construction, modification or 

reconstruction. Accordingly, we have finalized the definitions of both “Group 1 storage vessel” 

and “Group 2 storage vessel” to reflect these considerations. Also as discussed in the previous 

response, we have declined to revise the amendments to base the determination of when the 

initial report is due for a storage vessel on the date of startup.

2.1.2.3 Group 1 and Group 2 Control Requirement Determination

Comment: One commenter (4626) expresses concern about the enforcement 

ramifications of inaccurately estimating annual emissions based on the first 30 days of 

production. According to the commenter, because of inherent uncertainty in projecting the 

production of a given well, there should be provisions included in the regulations that provide 

reduced enforcement exposure if producers diligently monitor their throughput (and hence their 

emissions) and promptly report any errors discovered with regard to the annual emissions 

estimate. The commenter recommends that the EPA include in the final version of this rule

provisions that provide operators reduced enforcement exposure if errors in annual production 

based emissions calculations are promptly reported (e.g., within 30 days) to the EPA (or the 

implementing state/local authority) and appropriate controls are installed within an additional 30 

days. The commenter provides that, such notification would require an explanation of why the 

initial annual emissions estimate was incorrect.
17

Response: We expect owners and operators to exercise care in estimating storage vessel 

emissions, and we believe that the available methods for estimating emissions are reliable. 

Consequently, we do not believe that it is necessary to include provisions in the final 

amendments to address situations in which the estimates are so flawed as to result in an incorrect 

determination of whether a storage vessel is an affected facility. We note also that we anticipate 

that implementing agencies will exercise judgment according to their own procedures and 

experience in what should be rare circumstances where the initial applicability determination is 

incorrect.

Comment: Two commenters (4621, 4632) request that the EPA adopt a rolling monthly 

average of VOC emissions over 12 months (which would encompass a complete climatic cycle) 

for an operator to determine whether a Group 2 or modified Group 1 storage vessel require 

controls. The commenters believe that the current approach poses a problem for small producers. 

The commenters report that, in the earliest months of well production, a storage vessel will have 

an initial throughput that, if annualized, would result in estimated VOC emissions rate in excess 

of 6 tpy. However, the commenters provide that, over time, production will decline. The 

commenters opine that a far more accurate estimation of annual VOC emissions can be 

determined once production levels off. According to the commenters, however, that would not

occur within the 30-day period the proposed amendments grant for making an initial estimation 

of VOC emissions.

Response: We do not agree that the applicability of control requirements should be 

based on a full year of production data and have not revised this provision as requested by the 

commenters. We agree that production and emissions typically are highest in the earliest months 

of well production and will decline over time. For this reason, we believe it is important to install 

controls as quickly as possible so that storage vessels will not go uncontrolled at the very time 

that their emissions are the greatest. However, to address the situation of declining production 

and emissions, the final amendments include an alternative emission standard in §60.5395(d)(2). 

Under this provision, a storage vessel affected facility can meet the alternative standard by 

maintaining uncontrolled actual emissions below 4 tpy after documenting uncontrolled emissions 

below this level monthly for 12 consecutive months. Thus, affected storage vessels with 

significantly declining throughput and emissions may remove a control device that was initially 

required based on the level of emissions immediately after startup.

Comment: One commenter (4630) requests that the EPA specify that the potential VOC 

emission rate shall be based on a 30-day period of production prior to the date upon which the 

determination of the potential VOC emission rate is due. The commenter states that the potential 

for storage vessel emissions in the oil and gas production segment is driven by the potential 

throughput of produced fluids into the storage vessel. According to the commenter, because (as 

the EPA acknowledged in the preamble at 78 FR 22129) all wells experience a decline in 

production over time, and the storage vessels associated with those wells experience a 

corresponding decline in throughput. It would be conservative, then, to base the potential VOC 

emission rate on the actual throughput experienced during the period of production immediately 

prior to the determination of the potential VOC emission rate being due, in that production 

throughput will decline thereafter. Thus, according to the commenter, the period on which this 

determination is based should be a representative 30-day period of production prior to the date 
18

upon which the determination of the potential VOC emission rate is due. Given that the future 

potential for VOC emissions is practically limited by the actual throughput during the initial 30-

day period, the commenter requests that the rule specify that the potential VOC emission rate, 

upon which applicability is determined based on the 6 tpy threshold, is to be calculated using any 

generally accepted model or calculation methodology applied to the average throughput rate 

determined for the representative 30-day period of production.

Response: We believe that it is important that the applicability determination reflect

realistically the storage vessel’s potential to emit VOC to ensure that control is applied to the 

appropriate storage vessels. Accordingly, we believe that the estimate of potential VOC 

emissions should be determined based on maximum emissions during the 30-day period rather 

than average emissions over that period. In the final amendments, we have revised §60.5365(e) 

to require that the potential emissions determination be based on the maximum daily throughput 

of the storage vessel during the 30 days immediately preceding the determination.

2.1.2.4 Date That Owners and Operators Must Begin Tracking “Events” From Group 1 Storage 

Vessels

Comment: One commenter (4613) requests that events that may increase emissions from 

a storage vessel be considered only after the Group 1 and Group 2 control device installation date 

of April 15, 2014. The commenter opines that the assessment of "event" triggers after April 12, 

2013 will most likely require retroactive determinations of potentially triggering events, 

especially since April 12, 2013, has already past and further, because the proposed rule is not 

expected to be finalized until July 31, 2013. The commenter believes that this retroactive 

determination is infeasible and will create unnecessary administrative burden for tracking of all 

Group 1 tanks to assess if the "event" occurred, based on different timeframes than the rest of 

affected facilities considered as Group 2 tanks.

Two of the commenters (4615, 4630) state that the date upon which the owner or operator 

must begin to track these triggering events should allow time for initial determination of the 

potential VOC emission rate. The commenters provide that the EPA’s proposed language 

specifies that the owner/operator must begin to track events on April 12, 2013, but determination 

of which storage vessels are subject to this requirement is not due until October 15, 2013. 

According to the commenters, it is unreasonable to require events to be tracked before it is even 

known for which storage vessels the requirement is applicable. The commenters opine that the 

date for beginning the tracking of these events should be no earlier than October 15, 2013, the 

date upon which determination of applicability is due.

According to one commenter (4615), since compliance with the proposed rule applies at 

all times, an operator needs the minimum of 60 days proposed in the rule to obtain and install 

control equipment after an event has increased emissions from a Group 1 storage vessel. The 

commenter suggests that a minimum of 90 days is needed to implement controls and that 90 days 

would be more appropriate due to the need to size, order, and install the controls.

Similarly, another commenter (4612) submits that it is appropriate to allow for 60 days 

for the application of controls. According to the commenter, while some changes that can 

increase emissions are planned in advance, emissions calculations cannot be performed by 
19

midstream facilities until the production levels for a new well have been established in order to 

accurately determine whether controls will be needed. In addition, the commenter states that 

midstream facilities will have different engineering requirements than production sites. The 

commenter reports that, if there is an emissions increase, equipment will have to be designed, 

obtained, and installed, which takes even more time. The commenter asserts that some facilities 

may also need to comply with OSHA Process Safety Management (PSM) requirements after 

installing controls. The OSHA PSM requirements include the need to conduct a process hazard 

analysis where operating procedures must be put in place, and operating staff trained, to run the 

required processes before startup. The commenter states that a period of 60 days to accomplish 

these tasks is barely sufficient, even if the emissions increase is the result of a planned change.

One commenter (4623) argues that the EPA should tie potential triggering of Group 2 

controls to the promulgation date of the revisions of the reconsideration proposal. According to 

the commenter, the EPA’s proposal that operators track such events that occur on or after April 

12, 2013, is unworkable because operators were unaware of this requirement on that date. The 

commenter opines that it would likely be difficult or impossible for operators to identify events 

and any associated “change” in emissions when they were not required to keep records of these 

past occurrences.

Response: In the final amendments, we are not finalizing the proposed requirement to 

track events for Group 1 storage vessels (refer to section IV.A of the final rule preamble for 

further discussion regarding these changes). Therefore, the concern expressed by the commenter 

is now moot.

2.1.2.5 Storage Vessels That Initially Have PTE Less Than 6 tpy

Comment: Two commenters state that the final rule should specify a compliance period 

for Group 2 storage vessels that originally had potential VOC emissions less than 6 tpy and 

subsequently experience an event that causes the potential VOC emission rate to meet or exceed 

6 tpy. In such cases, the commenters request that the storage vessel should be required to achieve 

compliance within 60 days after the event.

Another commenter states that the proposed amendments do not limit the Group 2 control 

trigger to planned events and may include unplanned events such as emergency well reroutes as 

well as “any other” event that could increase VOC emissions. According to the commenter an 

operator cannot control and plan for an emergency event such as a tank failure that forces the rerouting of a well to a nearby vessel, nor for an unspecified “other” event.

Response: The proposed amendments clearly specify when compliance must be achieved 

for Group 2 affected facilities. We have finalized this compliance date, as proposed. 

Concerning the comments about “events” that increase the VOC PTE of a Group 2 storage 

vessel, the commenter is correct that initially we failed to address the issue of storage vessels 

that, during their initial evaluation, have PTE less than 6 tpy and are not determined to be 

affected facilities but that subsequently increase emissions such that PTE is 6 tpy or more. We 

agree this is a problem. Although our proposed rule did not include measures for us to finalize 

today to address this issue, we continue to evaluate this issue and intend to complete this 
20

evaluation in conjunction with our consideration of other issues that we plan to finalize by the 

end of 2014.

2.1.2.5 “Frac Tanks” Used As Temporary Storage

Comment: Several commenters (4613, 4617, 4620) request that the EPA confirm that 

"frac tanks" used as temporary storage during the flowback period are not considered storage 

vessels as defined in §60.5430 and may be used to transport or store flowback fluids in 

compliance with §60.5375(a). The commenters (4613, 4620) state that, if the EPA did intend to 

regulate these containers under the storage vessel standard, that they confirm that “frac tanks” 

on-site for less than 180 days or that are used in the process of recycling and transporting liquids, 

are categorized as temporary or process vessels, respectively. 

The commenters (4613, 4617, 4620) provide that the EPA indicated in the preamble to 

the original rule and to the proposed revisions that the intent was to regulate “[c]rude oil, 

condensate and produced water [that] are typically stored in fixed-roof storage vessels.” 76 FR 

52763. They report that the EPA further stated that the “intent was to regulate only certain 

storage vessels (i.e., those storage vessels that may likely emit VOC emissions), not every 

container.” 78 FR 22132. According to the commenters, hydraulic fracturing tanks are generally 

neither fixed roof nor likely to emit significant amounts of VOC emissions. The commenters 

explain that fluids that flow through these tanks are often reused or recycled and are cycled 

through on a semi-continuous basis that is inherent to the flowback and fracturing process. 

Further, according to the commenters, when these containers are used to actually store fluids, the 

tanks are rarely on-site for more than 180 days.

Response: The commenters state that hydraulic fracturing tanks are likely to have low 

emissions. If this is the case, then they likely would not be an affected facility (i.e., potential to 

emit VOC of 6 tpy or more). If the potential VOC emissions from the hydraulic fracturing tank 

are at least 6 tpy, then they would be considered a storage vessel affected facility and would be 

subject to the storage vessel requirements under the final amendments. As mentioned by the 

commenters, the definition of storage vessel in §60.5430 of the proposed amendments includes a 

provision that storage vessels located at the site less than 180 days are not considered to be 

storage vessels. We point out that §60.5430 also specifies that the storage vessel must be skidmounted or permanently attached to something that is mobile to qualify for this exemption. If the 

fracturing tanks were to satisfy all these exemption criteria, they would not fit the definition of 

“storage vessel” and would, therefore, not be considered storage vessel affected facilities.

Concerning process vessels, the storage vessel definition provides examples of process vessels 

that include surge control vessels, bottoms receivers and knockout vessels. The vessel in 

question would need to have a similar use to be considered a process vessel.

2.1.2.6 Storage vessel affected facility definition

Legally and Practically Enforceable Limits

Comment: One commenter (4612) supports the proposal to clarify the type of storage 

vessel that would be subject to the Oil and Gas NSPS: storage vessels considered to be affected 

facilities would be those that have VOC emissions of 6 or more tpy and are used to store crude 

oil, condensate, unrefined petroleum liquids, and produced water. The commenter also supports 
21

the proposed clarification that a source can take into account any legally and practically 

enforceable emission limit when determining the VOC emission rate for purposes of calculating 

threshold emissions. The commenter asserts that the 2012 NSPS could have been read to apply to 

storage vessels containing any sort of material. In addition, prior to the EPA proposed 

amendments, the final rules contained inconsistent and incomplete provisions regarding the 6 tpy 

VOC applicability threshold. The commenter also agrees that it is appropriate to take enforceable 

limits into account in determining whether a storage vessel is subject to the Oil and Gas NSPS.

Response: We acknowledge the commenters’ support and have finalized the proposed 

amendments to the storage vessel affected facility definition. Section IV.C of the preamble to the 

final amendments discusses other changes we made to the storage vessel affected facility 

definition. 

Comment: One commenter (4623) believes that the EPA has proposed appropriately that 

legally and practically enforceable limits on emissions would be considered in determining 

potential emissions for purposes of NSPS applicability. However, according to the commenter, 

the phrasing of this provision is somewhat ambiguous and cumbersome. The commenter believes 

that, by the EPA stating that it would take “into account requirements under a legally and 

practically enforceable limit in an operating permit or by other mechanism,” and that it is unclear 

what the distinction is between “requirements” and a “legally and practically enforceable limit.”

The commenter suggests that the language should read “taking into account legally and 

practically enforceable limitations on the potential to emit.” The commenter also states that it is 

unclear what the purpose of specifically mentioning operating permits is when, often such limits 

are established by construction permits or may apply by virtue of a categorical regulation in the 

state implementation plan (SIP) or in a state regulation that is not a part of the SIP. The 

commenter requests that the EPA clarify, at least in the preamble, that construction permits, state 

rules, and the like are acceptable methods of satisfying that emissions are below the threshold.

Response: In response to this and other comments, we have revised §60.5365(e) in the 

final amendments to clarify the storage vessel affected facility definition. Refer to section IV.C 

of the preamble to the final amendments for further discussion.

Applicability Emissions Rate Determination

Comment: One commenter (4611) requests that the EPA ensure that both flash and 

working/breathing losses are counted towards the 6-tpy threshold and that all components of 

VOC emissions be included in the calculation. The commenter provides that not all generally 

accepted models or calculation methodologies are capable of calculating both flash and 

working/breathing losses.

Response: All of the generally accepted models of which we are aware account for

working and breathing losses in addition to flash emissions. 

Comment: One commenter (4623) suggests that the EPA include a clarification in the 

regulation of how to determine the emissions rate for the 6 tpy threshold. The commenter opines 

that the EPA should clarify that it intends the potential to emit analysis to represent a reasonable 
22

calculation of the emissions from the vessel based on the production estimates of wells that are 

connected to that particular vessel.

Response: We have revised §60.5365(e) in the final amendments to more clearly specify 

how the potential emissions are to be determined. We believe these revisions address the 

commenter’s concerns. Section 2.1.2.3 of this document presents further discussion of this issue.

Comment: One commenter (4630) states that, as subpart OOOO is currently structured, 

it is not clear that a storage vessel subject only to a requirement for at least 95 percent control 

could rely on this control requirement to create a legally and practically enforceable limit on 

VOC emissions below 6 tpy. According to the commenter, it would provide a more 

straightforward compliance pathway than determining PTE considering legally and practicably 

enforceable controls. The commenter believes that this approach is appropriate in the context of 

the unique nature of oil and gas production and of the differing state regulatory regimes for oil 

and gas production as opposed to industrial sites.

The commenter (4630) asserts that many state programs do not currently have VOC mass 

emissions limits for storage vessels or effective means of obtaining permits that contain them. 

Likewise, according to the commenter, these programs may not have effective means of 

imposing operational limitations that could be coupled with a percent control requirement, or 

may not have extensive monitoring and recordkeeping obligations. The commenter maintains 

that this would mean that many storage vessels could be viewed as not having a legally and 

practically enforceable limit of less than 6 tpy, even though their emissions are much less than 

that level because of the installation of a control device or routing to a flow line.

The commenter (4630) suggests changes to §§60.5365(e) and 60.5395(c) that are 

designed to streamline the process for determining PTE for VOCs from storage vessels and avoid

potential problems with state programs that impose control requirements, but not specific VOC 

emissions limits or operational limitations. The suggested changes include: (1) using the first 

thirty days of production in a model to define PTE from a storage vessel; (2) consolidating 

provisions on determining VOC PTE in §60.5395(c) for clarity and consistency; (3) clarifying 

that emissions controls required by applicable state regulations or guidance can be used to 

determine the VOC potential of a storage vessel, and (4) clearly defining what emissions must be 

considered in the calculation of the potential VOC emission rate.

The commenter (4630) states that the term potential to emit is not defined in subpart 

OOOO or 40 CFR 60.2. According to the commenter, relatively few storage vessels will be in 

states that have the type of limitation that would act as an acceptable limitation on PTE. The 

commenter explains that this means that the operator of a subpart OOOO storage vessel would 

have to determine emissions based on the maximum capacity of that storage vessel to emit a 

pollutant, which could significantly raise the emissions from a storage vessel, particularly for 

wells with significant decline factors.

The commenter (4630) also states that they do not believe that the EPA intended the use 

of maximum design capacity in determining VOC emissions potential, since §60.5395(e) 

provides for the use of “any generally accepted model or calculation methodology,” which will 
23

generally rely on established production rates and flash emissions estimates, rather than worst 

case assumptions. Indeed, according to the commenter, the unique nature of oil and gas 

production means that maximum design does not truly reflect the PTE, given natural reservoirs 

with less predictable flow, increases and decreases in flow over time, and inability to ramp 

production up and down to take advantage of equipment sizing and demand.

According to the commenter (4630), their proposed changes would help maximize the 

flexibility for state NSR and SIP programs so that storage vessel emissions can be reduced 

through legally and practically enforceable means to minimize the impacts to agencies and the 

regulated industry, while achieving the EPA’s emission reduction goals.

Response: We have revised §60.5365(e) in the final amendments to more clearly specify 

how the potential emissions are to be determined. In particular, we have revised §60.5365(e) to 

state that the potential emissions determination must be based on the maximum daily throughput 

of the storage vessel during the 30 days immediately preceding the determination.

Depending on the baseline emission, a 95 percent control requirement does not 

necessarily result in below 6 tpy VOC emissions. Therefore, one cannot rely on such limit alone 

to ensure the PTE remains below 6 tpy. In response to the commenter’s concern about the ability 

of state programs to issue permits with the necessary limits to ensure the PTE remains below 6 

tpy, these concerns are beyond the scope of this action and are not addressed here.

Comment: One commenter (4615) commented on EPA’s solicitation for comment on 

distinguishing characteristics between this NSPS and other EPA regulations warrant an approach 

where, if an emission limitation is equivalent to the NSPS emission standards and can be 

enforced by state or another federal requirement, compliance with the NSPS should not be 

necessary; oversight concerns of such an approach, and how such approach is permissible under 

CAA section 111. The commenter opines that such an approach is permissible under CAA 

section 111 and is needed to prevent duplicate regulation from an NSPS rule and from state, 

tribal, or local air permits or BACT requirements.

Response: The commenter provides no additional information for us to evaluate the 

questions we posed in our solicitation for comment. 

VOC Emission Threshold for Storage Vessels

Comment: Two commenters (4621, 4632) opine that, based on the EPA’s technical 

modeling, the EPA should accept an operator’s determination that a storage vessel won’t require 

emission controls if the throughput is less than 20 bbl/day. The commenters assert that the 

requirement that Group 1 wells (those constructed, modified or reconstructed after August 23, 

2011, and on or before April 12, 2013) provide initial notification to the EPA by October 15, 

2013, raises a significant issue for small producers: How does a producer determine whether a 

storage vessel exceeds 6 tpy? According to the commenters, complicating this matter is the fact 

that the EPA has not given guidance on recommended methods for determining VOC emissions. 

The commenters provide that they understand why the EPA moved away from the throughput 

threshold of 20 bbl/day to the 6 tpy potential VOC emissions threshold. However, they believe 
24

that throughput is the simplest and clearest methodology for an operator to determine if controls 

are required.

Another commenter (4623) recommends that the EPA increase the storage vessel VOC 

threshold to 12 tpy based on cost effectiveness of controls at that level. According to the 

commenter, the final rule definition fails to include an applicability threshold for VOCs. The 

commenter asserts that, although the final rule requires controls only for those vessels with a 

PTE of greater than 6 tpy, this affected facility definition could be interpreted as including all 

vessels regardless of VOC emission levels. The commenter opines that such an interpretation 

would mean that notification, recordkeeping, and reporting requirements would apply to all 

storage vessels, even if they have very low VOC emissions. Thus, the commenter supports 

including an applicability threshold but recommends that it be set at 12 tpy, not 6 tpy based on 

the costs of controls for enclosed combustors that the EPA calculated in its Air Pollution Control 

Cost Manual. The commenter believes that 12 tpy is the lowest threshold that reduces emissions 

at a cost-effective level.

Response: We previously rejected a throughput threshold in the 2012 NSPS because we 

concluded that it is not a good indicator of VOC emissions due to the high variability in volatile 

content of the liquids flowing through storage vessels at well site and other parameters affecting 

emissions (77 FR at 49500, 49524). Nothing in the comment changes this conclusion. 

We also disagree that the threshold should be increased to 12 tpy. As discussed in the 

preamble to the 2012 NSPS (77 FR 49524), we determined that 95 percent control of storage 

vessels at 6 tpy or more is cost effective. 

Concerning the comment that we did not provide guidance on methods to determine 

VOC emissions from storage vessels, we point out that in the Response to Public Comments 

document on the August 23, 2011, proposed rule (see p. 126 of the document), which is available 

in the docket, several tools for calculating emissions were listed by commenters. These tools 

included computer programs such as E&P TANKS, HYSIM, HYSIS, WINSIM, PROSIM, as 

well as calculation methodologies such as the Vasquez-Beggs equation.

2.1.2.7 Clarification of Requirements for Determining Group 1 Storage Vessels VOC Emissions 

Comment: One commenter (4633) seeks clarification that changes in flow between 

individual storage vessels at centralized batteries or at locations with multiple tanks does not 

trigger a change from Group 1 to Group 2 status. The commenter states that the proposed 

requirements separating storage vessel affected facilities into two groups, "Group 1" and "Group 

2," include a review of changes made after April 12, 2013 at "Group 1" tanks to determine if the 

change "could reasonably be expected to increase VOC emissions." According to the 

commenter, while reviews of single-well pads would be straightforward, complications could 

arise for reviews involving the operation of storage vessels at multiple-well pads or centralized 

tank batteries. In centralized batteries, for example, a number of centralized tanks receive flow 

from numerous wells. The commenter reports that, typically, the production from each well can 

be routed to any of the storage vessels based on operational needs. The commenter expresses 

concern regarding the language in §60.5395(b)(iv) stating "any other event that could increase 

the VOC emissions from the storage vessel affected facility." The commenter explains that the 
25

overall tank battery's VOC emissions would not change if flow is moved from one tank to 

another, but the emissions from each tank could change as a result. The commenter requests that 

the EPA provide a definition of what constitutes a "change" and/or an "event" that could 

reasonably be expected to increase VOC emissions.

Response: In the final amendments, we are not finalizing the requirement we had 

proposed to track events for Group 1 storage vessels (refer to section IV.A of the preamble to the 

final amendments for further discussion regarding these changes). Therefore, the concerns

expressed by the commenter are now moot. We point out, however, that the commenter’s belief 

that a storage vessel could change from Group1 to Group 2 is incorrect. Whether a storage vessel 

is classified as Group 1 or Group 2 is determined solely by the date on which construction, 

modification or reconstruction was commenced for the storage vessel, as defined in §60.5430.

Comment: Two commenters (4623, 4630) requested that the EPA allow owners and 

operators to opt into the more stringent Group 2 control requirements for Group 1 storage vessels 

and avoid the need for tracking “events.” Specifically, one of the commenters (4623) requests 

that the EPA provide a mechanism for Group 1 vessels to voluntarily subject themselves to the 

Group 2 requirements upon installation of a control device and opt-out of the requirement to 

track “events.”

Response: We are not finalizing the proposed requirement to track events, and the final 

rule requires Group 1 storage vessels to meet the control requirements by April 15, 2015. 

Therefore, the concerns expressed by the commenters regarding tracking events are now moot. 

Refer to section IV.A of the preamble to the final amendments for further discussion regarding 

these changes.

2.1.2.8 Emergency and Safety Exceptions

Comment: Four commenters (4615, 4620, 4623, 4630) request special provisions for 

storage vessels that are installed during emergency or safety situations. Some of these 

commenters (4615, 4623, 4630) suggest that the EPA include a 180-day delay for designating 

these storage vessels as an affected facility.

One commenter (4615) recommends that the EPA allow a 180 day window before a likekind replacement storage vessel becomes an affected facility in subpart OOOO. According to the 

commenter, unless the EPA allows for a 180 day window, in some states, an operator would first 

need to obtain a construction permit or operating permit modification to install an emergency 

replacement vessel since it would be considered an NSPS affected facility.

Another commenter (4620) requests that the EPA clarify that storage vessels installed for 

the beneficial purpose of replacing existing vessels due to mechanical integrity or Spill 

Prevention Countermeasure and Control (SPCC) compliance purposes are not considered new or 

modified storage vessels under the rule. The commenter asserts that, in the case of this routine 

replacement activity there is no associated emissions increase, but significant risk reduction from 

a spill and safety perspective.
26

Another commenter (4623) requests that the EPA define and exclude “emergency 

replacement vessel(s)” from the rule for 180 days. The commenter asserts that the rule creates 

uncertainty for sources that must replace a storage vessel in cases of failure. According to the 

commenter, the rule could create potential permitting delays because many jurisdictions require a 

construction permit for replacement vessels if the vessel is subject to an NSPS. The commenter 

requests that the EPA provide the ability to extend the use of a temporary tank if the facility has 

applied for required permits for a permanent tank but has not had sufficient time to install it 

(recognizing that obtaining the permit may itself take 6 or more months and that construction on 

the tank cannot begin until the permit is obtained). The commenter states that defining a term, 

emergency replacement vessel, as not subject to the NSPS would allow permanent replacement 

units to be installed without a minor NSR construction permit. According to the commenter, 

under their suggested scenario, this permit would be obtained within 180 days, when the 

emergency classification expires. The commenter asserts that this approach would address 

potential problems with temporary tanks in that they are typically rectangular and often do not fit 

into the existing containment berm for a round permanent storage vessel. Additionally, the 

commenter reports that temporary tanks may also require installation of temporary piping and, 

due to their size, multiple replacement tanks may be required to temporarily replace one failed 

storage vessel. Lastly, according to the commenter, temporary tanks are generally not compatible 

with emission control devices, and thus may not be an option due to state permit requirements 

for control devices or emission limits.

One commenter (4630) requests that the EPA include a 180-day delay for designating a 

new storage vessel as an affected facility when the activity qualifies as an emergency 

replacement. The commenter states that there is precedent for a 180-day period in such cases 

already set by the EPA through allowed use of temporary storage vessels. The commenter further 

states that if a permanent storage vessel is brought in before expiration of the 180-day period that 

was started with a temporary storage vessel, the deadline for designating as an affected facility is 

not reset; whatever storage vessel is in place at the end of the 180-day period becomes a storage 

vessel affected facility. According to the commenter, emergency replacement of a storage vessel 

may be required for various reasons, including but not limited to storage vessel failure having 

been deemed imminent or having already occurred. According to the commenter, prior to the 

promulgation of NSPS subpart OOOO, storage vessel replacement in the oil production segment 

often did not trigger any state permitting requirements. However, the commenter reports that 

several states require permits for any facility that becomes subject to an NSPS, in which case 

installation of a replacement storage vessel as a subpart OOOO affected facility would not be 

allowed until it was permitted. The commenter states that for nonemergency storage vessel 

replacement, where advanced planning allows time for the permitting process, this is not a

significant issue. However, according to the commenter, when an emergency replacement is 

needed, advanced planning time is minimal to nonexistent, and the permitting trigger becomes a 

major issue in that a replacement storage vessel is needed immediately but the state does not 

allow such replacement until a permit is obtained. The commenter further states that while 

subpart OOOO allows for a temporary storage vessel to not be an affected facility for up to 180 

days in such cases, it would be preferable to immediately install a permanent replacement if one 

is available.
27

The commenter (4630) asserts that the solution to emergency replacement of storage 

vessels is to delay triggering the affected facility designation for 180 days from the start of 

installation of the replacement, regardless of whether the replacement is a temporary or 

permanent storage vessel. The commenter maintained that if an operator has a new permanent 

storage vessel immediately available to replace a failed storage vessel, replacement installation 

would then be allowed to begin while concurrently applying for the needed permit. Additionally, 

the commenter stated that replacement construction would need to occur only once if a 

permanent vessel could be used, thereby reducing costs for the operator.

The commenter (4630) requests that a new definition of "storage vessel emergency 

replacement" be added to clarify the usage of this term. This commenter also requests changes in 

the associated recordkeeping requirements to address their requested delay change.

Response: The EPA does not believe, nor have the commenters offered any support, that 

CAA section 111 authorizes delaying affected facility determination, which in turn would delay

compliance, to allow facilities to first deal with their state requirements. In fact, such delay 

would seem contrary to the requirement under section 111(e) of the CAA, which prohibits any 

new source from operating in violation of any applicable NSPS. We believe that state agencies, 

not the EPA, are more appropriate in addressing their own requirements.

 

We note, however, that the definition of storage vessel under §60.5430 includes a 

provision that “[v]essels 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” are not considered storage vessels. The provision of 180 days, which 

was promulgated in the 2012 NSPS, would allow the owner or operator to bring in a temporary 

replacement vessel that was skid-mounted or was permanently attached to something mobile for 

up to 180 days until the permanent replacement tank could be obtained and the requisite permits 

obtained. According to the comments, this 180-day period would be sufficient to obtain the 

permits. 

2.1.2.9 Alternative Emissions Standard

General Support and Opposition for 4 tpy Alternative Emission Standard

Comment: Several commenters (4612, 4613, 4633) support the concept of the provisions 

for the removal of controls at such a time that production and associated emissions decline to 

below a control threshold, as described in §60.5395(d)(2).

One commenter (4612) reports that the claimed benefit of freeing up scarce control 

equipment where emissions have consistently been below the 6 tpy VOC applicability threshold 

in the Oil and Gas NSPS would be diminished by lowering the 4 tpy requirement in proposed 

§60.5395(d)(2). The commenter states that this is because fewer storage vessels could take 

advantage of the compliance alternative if the 4 tpy limit were reduced, and therefore fewer 

storage vessels would be able to operate without control equipment. According to the commenter 

(4612), there is no reason to require a storage vessel with demonstrated emissions of less than 4 

tpy VOC to continue to apply controls. If anything, the commenter believes that the EPA should 

revise proposed §60.5395(d)(2) by raising the 4 tpy limit to 5 tpy, because they believe it would 
28

free up additional control equipment while still limiting the availability of the no-controls 

compliance alternative to those vessels whose VOC emissions are well below the 6 tpy 

applicability threshold.

Response: We acknowledge the commenters’ support for the concept of the provisions 

that would allow the removal of controls where emissions have declined to below a specified 

emission rate. Please see section IV.A of the preamble to the final amendments for a discussion 

on our revised estimate of the combustor supply and our rationales for finalizing an uncontrolled 

actual VOC emission rate of less than 4 tpy. 

Alternative Emission Threshold Periodic Emissions Determinations

Comment: One commenter (2624) supports monthly recordkeeping requirements to 

determine emissions and verify compliance with the alternative emission limit and states that the 

proposed requirements would be consistent with standard title V reporting requirements.

Another commenter (4626) states that, instead of requiring 12 months of data 

demonstrating uncontrolled emissions below 4 tpy, they believe that six months of data 

demonstrating emissions below 6 tpy is sufficient. The commenter also suggests that the 

obligation to conduct monthly monitoring be discontinued after six months of data demonstrating 

VOC emissions below 4 tpy, absent an intervening event as set forth in §60.5395(b)(2).

One commenter (4612) states that the periodic emissions determinations should, at most, 

be required on a monthly basis because it would present an unnecessary increased burden on 

owners and operators if they had to make such determinations on a more frequent basis, with 

little additional environmental benefit. The commenter asserts that a rule that requires more 

frequent determinations would contravene the President's Executive Order 13563, which directs 

federal agencies to "identify and use the best, most innovative, and least burdensome tools for 

achieving regulatory ends." In addition, according to the commenter, the proposed rules should 

be revised to provide that determinations need only be made on a quarterly basis once there had 

been 12 consecutive months of VOC emissions less than 4 tpy after the removal of controls. 

According to the commenter, this would be an appropriate lessening of the regulatory burden as 

it would only apply to storage vessels with a substantial history of consistently low VOC 

emissions.

One commenter (4613) suggests that quarterly versus monthly calculations be allowed.

The commenter does not object to the requirement to demonstrate that the VOCs are below a 

certain threshold for the time period of twelve consecutive months; however, they feel that 

quarterly calculations would adequately demonstrate a well’s decline since production typically

peaks early in the life of the well and declines rapidly. The commenter requests that the EPA 

allow quarterly demonstrations of VOC emissions for this provision, as opposed to monthly.

Similarly, another commenter (4630) requests that the EPA include a provision for 

emission calculations to be less frequent if the actual VOC emission rate persists at a level of less 

than 4 tpy. The commenter states that this would be similar to the reduced monitoring frequency 

specified in LDAR programs, where it would be appropriate to reduce the calculation frequency 
29

from monthly to quarterly after a period of continued documentation that the actual VOC 

emission rate is being maintained at less than 4 tpy. According to the commenter, calculations to 

demonstrate compliance would be needed less frequently when the actual emission rate has been 

demonstrated to be persistently below 4 tpy, and the reward of less frequent emission 

calculations would provide an incentive for owners and operators to achieve low emission rates.

One commenter (4615) suggests that, after the first 12 consecutive months of less than 4 

tpy uncontrolled VOC emissions, the frequency of determinations should revert to annual 

determinations.

Response: We have finalized the proposed monthly recordkeeping requirements to 

determine emissions and verify compliance with the conditional uncontrolled actual VOC 

emission rate in the final rule. We believe the monthly requirement is necessary to assure 

compliance with the less than 4 tpy uncontrolled actual VOC emission rate. Even though we 

acknowledge that there is generally a gradual decline in emissions over the life of a well, there 

may also be fluctuations in flow where emissions could potentially increase, requiring that we 

maintain monthly emissions determinations and recordkeeping requirements in order to prevent 

uncontrolled emissions from reaching 4 tpy. See section V.C of the preamble to the final 

amendments for further discussion of this issue.

Clarification of Requirements After Emission Rates Decrease Below 4 tpy

Comment: One commenter (4630) requests that the EPA clarify that the use of a control 

device may be discontinued when emissions fall below 4 tpy. The commenter states that the 

EPA's intent was to specify that if the uncontrolled VOC emission rate for a storage vessel 

affected facility that is subject to Group 2 controls subsequently drops below 4 tpy, the controls 

may be discontinued as long as the storage vessel is maintained at less than 4 tpy as documented 

by monthly calculations. The commenter cites the proposal preamble to illustrate the EPA's 

intent (78 FR 22133). The commenter requests that the EPA revise the rule language to reflect 

this intent.

Response: We are finalizing the alternative uncontrolled actual VOC emission rate of 

less than 4 tpy, as proposed. Refer to section V.C of the preamble to the final amendments for

comments on the alternative uncontrolled actual VOC emission standard and the EPA’s 

responses to those comments.

Comment: One commenter (4630) recommends that the rule text clarify that, while 

remaining an affected facility, a storage vessel that has its potential for VOC emissions decrease 

to less than 6 tpy would become subject to the standard specified in §60.5395(d)(2), rather than 

that specified in §60.5395(d)(1), if the VOC emission rate were to fall below 4 tpy.

Response: We revised §60.5395(d) of the final rule to better clarify storage vessel 

applicability requirements (including requirements associated with the uncontrolled actual VOC 

emission limit of 4 tpy). We believe that the revisions made address the commenter’s concerns.

See section V.C of the preamble to the final amendments for a discussion of this issue.
30

Clarification of Requirements for Group 1 Storage Vessels that Become Subject to 

Control Requirements after an Event and Opt For the Alternative Emission Standard

Comment: One commenter (4623) requests that the EPA clarify and revise language 

concerning Group 1 vessels that become subject to the control requirements after an event that 

opt for the 4 tpy alternative mass-based limit. According to the commenter, most Group 1 

storage vessels, unless required by local regulations, will not have had a control device installed, 

nor have they been required to keep records of their actual VOC emissions for 12 months prior to 

triggering an event. The commenter believes that an absurd outcome that may result is that a 

Group 1 vessel with actual emissions, post-event, of 3 tpy, may be required to install controls to 

achieve a 95 percent reduction for 12 months, after which time it may remove the controls. To 

avoid this outcome, the commenter requests that the EPA revise the criteria for meeting the 4 tpy 

limit to remove the control and recordkeeping requirements for any vessel transitioning from 

Group 1 to Group 2 due to an event.

Response: We believe the commenter is referring to the proposed requirement that 

Group 1 storage vessel affected facilities would be subject to the control requirements only after 

an event that would likely increase emissions. We are not finalizing the proposed provisions 

related to events, so the commenter’s concern relative to that proposal is now moot. See section 

IV.A of the preamble to the final amendments for a discussion of this issue.

Reinstallation of Controls If Emissions Increase Above 4 tpy

Comment: One commenter (4620) recommends that the reinstallation of controls be 

required within 90 days of the determining that projected actual or actual emissions are over 6 

tpy. The commenter believes that it is more appropriate to require reinstallation at the same 6 tpy 

threshold applicable to new Group 2 storage vessels or Group 1 vessel with a triggering event 

rather than the 4 tpy alternative emission limit. The commenter states that these storage vessels 

will require the same installation and design requirements as the initial control device installation 

and should have the same control threshold.

One commenter (4612), in response to the EPA’s concern about leaving emissions 

unaddressed for a 30-day period under this proposal (where emissions in excess of 4 tpy VOC 

may be uncontrolled for a short period of time, between the monthly emissions determination 

and the application of controls) is that a period of at least 30 days is appropriate for the 

installation of controls in this circumstance. The commenter provides that application of controls 

will often involve locating and acquiring the necessary equipment, installation, and testing, a 

process that can be expected to take weeks to complete. According to the commenter, shortening 

the deadline to a period less than 30 days would create a requirement that in many cases would 

be very difficult if not impossible to fulfill, with minimal environmental benefits in most cases. 

The commenter asserts that shortening the 30-day period by a week or 10 days would not 

appreciably minimize emissions, which could be expected in many cases to be only slightly 

above the 4 tpy VOC uncontrolled emissions threshold allowed by the proposed revisions. 

According to the commenter, it is unlikely that many storage vessels that had been operating so 

as to emit less than 4 tpy VOC would suddenly begin operating at a much higher level.
31

Two commenters (4615, 4630) provide that they believe the appropriate measures to take 

for this short 30-day period should be the same as it is for “new” affected storage vessels in 

§60.5395(c)(2) which is to “minimize emissions to the extent practicable during the 30-day 

period using good engineering practices through the period prior to installation of controls.”

According to the commenters, typically, it will take just as much time to obtain and reinstall 

controls as it would for installing controls for a newly affected storage vessel. (This may not 

always be the case if, for instance, the exact same model of enclosed combustor was reinstalled 

such that existing piping, foundation, etc. can be used without modification; however, that 

scenario would be an infrequent exception.) In addition, according to the commenters, the 

number of affected storage vessels that get below the 4 tpy threshold in order to remove controls, 

and then again have a significant increase to require controls, will be much fewer than the 

number of “new” affected storage vessels in any given year; therefore, the same requirements 

should be sufficient and should apply. Also, the commenters report that a permitted facility with 

a storage vessel in this situation must still comply with state air permit limits or permitting 

thresholds such that the VOC emissions from the affected storage vessel during this uncontrolled 

period will effectively continue to be limited.

Another commenter (4618) states that, should a previously affected facility need to 

reinstall controls, the ability to find one in less than 30 days could prove extremely difficult. The 

commenter recommends that additional time be granted in this instance. The commenter believes 

that 180 days would be sufficient time for a site to find a control device. Moreover, the 

commenter provides that a 180-day deadline is consistent with the 40 CFR §60.14(g) definition 

of modification which allows 180 days following the completion of any physical or operational 

change subject to control measures to comply with all applicable standards.

One commenter (4620) recommends that the reinstallation of controls be required within 

90 days of the determining that projected actual or actual emissions are over 6 tpy. The 

commenter believes that it is more appropriate to require reinstallation at the same 6 tpy 

threshold applicable to new Group 2 storage vessels or Group 1 vessel with a triggering event 

rather than the 4 tpy alternative emission limit. The commenter states that these vessels will 

require the same installation and design requirements as the initial control device installation and 

should have the same control threshold.

Response: The EPA maintains that a period of 30 days is appropriate for the installation 

of controls in this circumstance. A period of 30 days is consistent with control requirements that 

apply to Group 2 storage vessels where an owner or operator has 30 days to install controls once 

it is determined that a storage vessel is an affected facility subject to control requirements.

In response to the comment that suggests the EPA should require owners and operators of 

storage vessel affected facilities to “minimize emissions to the extent practicable during the 30-

day period using good engineering practices through the period prior to installation of controls,” 

we believe that such a requirement could add significant burden and confusion regarding 

enforcement of undefined requirements. 

We are not finalizing the provisions in our proposal related to tracking emission increase 

events; therefore any comments related to tracking events are now moot.
32

2.2 Storage Vessel Control Requirements

2.2.1 General Support for Group 1 Storage Vessel Requirements

Comment: One commenter (4623) provides support for the EPA’s proposal to limit the 

regulatory requirements applicable on October 15, 2013, for Group 1 storage vessels to 

notification requirements (and excluding them from control requirements until future facility 

changes occur).

Similarly, another commenter (4633) provides support for the compliance date of 

October 15, 2013, for Group 1 storage vessels.

Response: We acknowledge the commenters support for the initial notification and 

compliance date for “Group 1 storage vessels” and the EPA’s proposal to limit the regulatory 

requirements for Group 1 storage vessels to notification requirements. See section IV.A of the 

preamble to the final amendments for additional discussion regarding Group 1 storage vessel 

applicability and compliance dates.

2.2.2 Control Equipment Design Requirements

Comment: One commenter (4622) who supported the inclusion of design requirements 

in the NSPS provides several possible approaches which they believe will assure that equipment 

is properly designed to meet the storage vessel standards: 

The EPA could prescribe design criteria for the size of storage tanks; the weight, 

placement, or material of hatches and covers; the size or rating of control devices; and 

any other system design elements affecting the pressure in the tank during loading.

The EPA could require the operator to certify both: (1) the maximum emissions 

expected from the storage vessel, including maximum flash emissions expected 

during loading or transfer operations, and (2) the capacity of the control system to 

handle that flowrate. This certification, which resembles the approach currently 

reflected in subpart Kb, could be submitted as part of the existing

compliance-certification process.

The EPA could also require an alarm or similar monitoring system for all PRDs, as it 

proposed in the Uniform Standards, and designate non-emergency or repeated 

releases from PRDs as violations of the NSPS. This approach would be consistent 

with the regulation of bypass lines at closed vent systems under current subpart 

OOOO, which requires such bypass lines to be equipped with monitoring systems and 

regards any release as a deviation.

The EPA could also consider requiring equipment that ensures control systems 

operate under appropriate conditions. For instance, CDPHE has examined “closedloop” emission capture systems that are specifically designed to recover vapors from 

PRDs and thief hatches. 

The commenter (4622) also provides that another demonstrated technology is the 

installation of a surge tank between the two or three phase separator and the condensate tank 
33

battery, which avoids over-pressurizing the condensate tank. According to the commenter, this 

add-on equipment is used at existing and low-flow wells. Alternatively, the commenter suggests 

that installing a high pressure low-pressure separator (HLP) essentially causes VOCs from the 

condensate to flash from the three phase separator rather than the condensate tank and that some 

operators use HLPs at new and high-pressure wells. 

One commenter (4612) believes that prescribing additional design standards would add to 

the complexity of the rules, thus increasing compliance burdens. 

Two commenters (4623, 4628) add that operators have sufficient incentive to design and 

operate their equipment properly to avoid safety, economic and environmental disruptions. 

Moreover, one of the commenters (4623) argues that the EPA does not have the authority under 

NSPS to require a particular technology or design as a performance standard. 

Another commenter (4628) reports that OSHA incorporates design standards in their 

rules in 29 CFR §1910.106. The commenter opines that, if the EPA were to create their own 

design criteria, it could limit the flexibility operators need to efficiently operate their facilities. 

Additionally, according to the commenter, new design requirements from the EPA may conflict 

with existing OSHA, industry, or company safety standards creating an unworkable situation.

Response: As discussed in section V.E of the preamble to the final amendments, we did 

not propose any specific design requirements and are therefore not finalizing any design 

requirements for storage vessels and associated closed vent systems and control devices in the 

final amendments.

Comment: One commenter (4611) requests that the EPA clarify that the closed vent 

system and cover requirements for storage vessels and centrifugal compressor wet seal degassing 

systems will prevent emissions during additions of liquid to the storage vessel, especially during 

high pressure liquid addition. The commenter asserts that this is important to reduce the 

possibility for an unintended loophole in the rule language which might result in potentially 

significant emissions.

The commenter (4611) reports that they have observed the highest emission rates 

corresponding to flash VOC emissions while liquids are being added to an existing storage 

vessel. The commenter states that this is common at well sites, where the natural formation 

results in high pressure liquids which are then routed through the separator to a storage vessel 

that is at or around atmospheric pressure. The commenter further states that, if a closed cover is 

not maintained during such liquids addition, a large percentage of the annual emissions could 

vent out of a pressure relief valve or thief hatch, rather than being routed to a control device and 

the EPA should not allow exceptions to the closed cover requirements simply for pressure 

equalization.

Response: As stated in our previous response, we are not finalizing any design 

requirements at this time. 
34

2.2.3 Electronic Ignition Systems

Comment: Several commenters (4614, 4616, 4619, 4620, 4629) request that the EPA 

should allow control devices that do not have a continuous pilot light.

According to one commenter (4616), the proposed rule’s preamble and regulatory text 

contains an ambiguity which can be interpreted to either permit or disallow the use of electronic 

ignition, creating confusion in the combustor industry. The commenter states that, in the 

preamble to the August 2012 final rule, electronic ignition is not mentioned and a reference to 

continuous flame pilot lights is vague. The commenter states that the last mention of continuous 

ignition source omits the phrase “over the duration of the flowback.” The commenter believes 

the better reading is that “duration of flowback” modifies “continuous ignition source” and that it 

was left off in the last sentence for stylistic reasons. The commenter urges the EPA to clarify this 

language in the final rule and to indicate that electronic ignition is permissible. The commenter 

suggests clarifying language to proposed provisions §§60.5415 and 60.5417 to, according to the 

commenter, unambiguously permit the use of electronic igniters.

One commenter (4633) requests that the EPA consider open-flame flare stacks or 

enclosed vapor combustors equipped with auto-igniters as acceptable and that this acceptable use 

specifically be incorporated into §60.5417(h).

One commenter (4616) requests that the EPA consider their enclosed combustor 

technology, consisting of an electronic ignition device that attains a destruction and removal 

efficiency of 99.99 percent. This commenter includes their manufacturer’s certification 

performance test for their enclosed gas vapor combustor.

According to one commenter (4616), in response to comments that mentioned that 

technological innovation made the requirement for a continuous pilot obsolete, the EPA has 

offered no technical basis for its belief that continuous pilots are more effective than electronic 

ignition at handling “intermittent and inconsistent nature of emissions...combined with highly 

variable VOC concentrations.” The commenter asserts that the EPA implicitly assumes that 

devices employing a continuous pilot will be effective to control low BTU flowback gas and that 

in the EPA’s response to commenters request that electronic igniters be permitted in lieu of 

continuously operating pilot lights, does not provide a quantitative analysis of its assertion that 

devices employing a continuous pilot will be effective to control low BTU flowback gas. 

The commenter (4616) sees no environmental basis to support a conclusion that 

electronic ignition devices should not be permitted on storage vessel combustors, especially 

when the igniter is utilized as part of a smart technology system with safety features such as 

pressure monitoring devices, on/off valves that only open when gas is present, and temperature 

monitoring devices to indicate and record when flame is present and combustion is within the 

proper operating range. This commenter also states that, in the Natural Gas Star Program, the 

EPA separately encourages the use of “electronic flare ignition devices” to replace “continuously 

burning pilot flames.” According to the commenter, absent an analytical comparison of the 

relative efficacy of continuous pilots and electronic ignition at combusting VOCs, it appears that 

one part of the EPA Air Office supports a technology which another part actively disfavors. 
35

One commenter (4629), regarding a "continuous ignition device", requests confirmation 

that subpart OOOO requires a verifiable continuous standalone dedicated pilot with stable 

reliable pilot fuel source for an enclosed combustion device operating with vent gas feed to be 

considered a control device, and that a pilot should have its own dedicated verification of the 

presence of its flame. According to the commenter, just as required on a flare, the purpose of a 

reliable standalone dedicated pilot is to assure there is reliable flame during vent gas feed. Using 

a tank's vent gas itself with its common low pressure and variable component makeup may not 

be stable in all atmospheric conditions, and thus the device would not meet the intent of the 

regulation. In addition, the commenter asserts that, unless the pilot is continuously burning in 

anticipation of a release, the time required to ignite and confirm the presence of a flame upon the 

determination that a release is imminent will very likely lead to a direct vent to the atmosphere 

either through the control device or via backpressure through the tank pressure relieving device.

Response: The 2012 NSPS requires pilot flames on combustion control devices. We 

have not proposed any change to that requirement. As we explained in the Response to Public 

Comments document for the August 23, 2011 proposed rule (see p. 307 of the document), we 

maintain our position that without a continuous pilot flame, there may be periods of uncontrolled 

emissions, and continuous ignition sources are designed to combust the flammable portion of the 

flowback gas, even if the flowback gas has a low BTU content. We also note that in §60.18(b)(2) 

of the General Provisions for 40 CFR part 60 rules, a continuous pilot flame is required for 

flares, and we believe the same requirement is applicable to the combustion control devices 

typically used for control of emissions from storage vessels in the oil and natural gas industry. 

As we stated in the response to comments for the proposed 2011 standards, there is not sufficient 

data at this time to suggest that electronic ignition systems on combustion devices are capable of 

continuously supplying a constant source of ignition adequate to keep a flame present on a 

continuous basis. In addition, for flares, test data for which the current standards in §§63.11(b) 

and 60.18 were written show that operating a flare with a continuously lit pilot adds an additional 

degree of flame stability to the flare itself.

One of the commenters suggests clarifying language be made to §§60.5415 and 60.5417 

of the final amendments to unambiguously permit the use of electronic igniters. We disagree.

The final amendments at §60.5412(d)(1)(i) specify the use of a continuous burning pilot flame.

Electronic igniters do not meet this provision. Although an electronic ignition device does not 

qualify as a continuous burning pilot flame, it may be used, for example, as a means of relighting a pilot flame that has been extinguished by wind or other factor, as long as a continuous 

burning pilot flame is maintained when vapors are being routed to the combustion device. For 

the reasons stated above, the final amendments do not include specific regulatory language in 

§§60.5415 and 60.5417 regarding electronic igniters. 

Concerning the comment on whether a continuous ignition device would be required on 

an enclosed combustion device burning vent gas, we confirm that such a device would have to 

have a continuous ignition device. We disagree with the commenter that such a control device 

does not meet the intent of the standards. This is in fact the emission source and emission control 

we envision to be subject to the control requirements of §60.5395 of the final amendments.
36

With regard to commenters’ suggested changes to the compliance requirements in the 

2012 NSPS, we continue to evaluate issues concerning the compliance requirements of the 2012 

final NSPS. We intend to complete our evaluation of compliance provisions by the end of 2014.

2.2.4 Flares

Comment: Several commenters (4615, 4629, 4630) assert that the EPA should clarify the 

control device standards as they pertain to flares.

One commenter (4630) reports that the proposed amendments contain provisions that 

apply to “each control device” and to “each combustion device,” both of which would be 

applicable to flares. However, the commenter expresses concern that flares are not expressly 

cited, and there are certain references to “enclosed combustion device(s)” that would seem to be 

applicable to flares. The commenter suggests edits to §60.5412(d) to clearly identify those 

provisions which are applicable to flares. 

Another commenter (4615) opines that, when §60.5412(a) was modified to apply only to 

centrifugal compressor affected facilities, and §60.5412(d) was added for storage vessel affected 

facilities, it became unclear what needs to be done when using a flare as a control device for a 

storage vessel affected facility. The commenter proposed that the following change be made to 

make it clear (bolded language is added):

§60.5412(d)(1) Each flare or enclosed combustion device...

One commenter (4629) states that §60.5413 states "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." By the commenters'

interpretation, this is defining a typical flare that has been utilized in industry for many years and 

as such will achieve a minimum 98 percent VOC destruction efficiency primarily based upon 

testing sponsored by the EPA and the Chemical Manufacturers Association in July 1983. The 

commenter requests the following changes be made to §60.5413 to reduce confusion: (1) add a 

statement that for normal process VOC reduction use of an open or enclosed flare designed and 

operated in accordance with §60.18(b) is acceptable for obtaining VOC destruction efficiency in 

excess of 98 percent; (2) add a statement that flares used for normal process VOC reduction are 

required to have a constant burning pilot as defined by API 537; (3) clarify what constitutes an 

upset condition which would fall outside of normal process VOC reduction.

Response: The owner or operator of a storage vessel affected facility may use any 

control technology, so long as compliance with the emission reduction requirement can be 

demonstrated. Therefore, we do not believe it is necessary to specifically incorporate into the 

rule that flares, and open-flame flare stacks or enclosed vapor combustors equipped with autoigniters (see also the previous comment response) are acceptable for use to meet the required 

emission reduction standard. We point out, however, that a flare is not an enclosed combustion 

device and the definition of flare in the 2012 NSPS specifically points this out. We also believe, 

considering the variability of flow to the combustion control device from storage vessels, that it 

is not appropriate to assume that a flare designed and operated in accordance with §60.18(b) is 
37

achieving the required control efficiency at all times. However, the 2012 NSPS does provide at 

§60.5413(a)(1) that a flare designed and operated in accordance with §60.18(b) is exempt from 

performance testing. Such a flare would still be required to perform Method 22 visual emissions 

testing.

Additionally, §60.5417(h) specifies continuous control device monitoring requirements 

for control devices used to comply with the emission reduction standard of §60.5395(d). The 

control device requirements of §60.5417(h) would apply to open-flame flare stacks or enclosed 

vapor combustors equipped with auto-igniters (as well as other control devices) if used to 

comply with the emission reduction standard and do not need to be specifically cited as being 

acceptable. 

Although we have not made the commenters’ suggested changes, we continue to evaluate 

the issues raised by commenters concerning the compliance requirements and flare provisions of 

the 2012 final NSPS. We intend to complete our evaluation of the compliance requirements and 

flare provisions by the end of 2014.

2.2.5 Carbon Adsorption

Comment: One commenter (4630) asserts that the EPA should not require carbon 

management for carbon absorption systems used with centrifugal compressors. The commenter 

requests that the EPA delete §60.5412(c)(2) in its entirety. The commenter maintains that the 

pertinent carbon management requirement for carbon adsorption systems used with centrifugal 

compressors is specified in §60.5412(c)(1), which is that the carbon must be replaced according 

to the specified schedule. According to the commenter, the EPA should not be prescribing waste 

management requirements within a CAA regulation. The owner/operator has a separate 

obligation to determine the applicability of regulations under other programs, such as RCRA, 

and the commenter opines that it is beyond the purview of an air rule to stipulate the applicability 

of rules under other programs. The commenter believes it adds unnecessary text to the rule, and 

makes it more difficult to discern what the requirements of the rule are.

Response: The carbon management provisions in the proposed amendments are identical 

to those in the 2012 NSPS. We included them in the proposed amendments only as part of our 

effort to separately distinguish the requirements for storage vessels and centrifugal compressors. 

Therefore, the carbon management provisions are not within the scope of issues addressed by 

these final amendments.

2.2.6 Control Device Operating Requirements

Comment: One commenter (4633) asserts that because many states consider vapor 

recovery devices such as a vapor recovery tower and/or a vapor recovery unit as process 

equipment rather than control devices, it will be confusing for facilities to use vapor recovery 

devices as "control" under subpart OOOO and as "process" under state permitting requirements. 

Further, according to the commenter, storage vessels that include vapor recovery operations (or 

routing of tank emissions to flow lines for processing) would correctly apply those operations in 

the calculation to determine whether the storage vessel's VOC emission rate would exceed 6 tpy 

or greater for applicability purposes. The commenter states that, for many states, neither the 
38

vapor recovery device nor the routing of off gas from a tank to a flow line would require 

permitting. Thus, the commenter believes that the proposed revisions seem to unnecessarily 

require a facility to seek a "legally and practically enforceable limit in an operating permit or by 

other mechanism" (§60.5395(e)). The commenter is concerned that this approach could lead to 

process piping within a facility being considered "control."

Response: First, we believe the commenter may have confused the usage of similar terms 

that are used in the NSPS. Vapor recovery devices are control devices such as a carbon adsorber 

or a condenser. A vapor recovery unit is a piece of equipment, usually a compressor, that collects 

a gas stream and returns it to the process for a useful purpose, such as recovery, recycling or 

reuse. The 2012 NSPS final rule includes a definition of “routed to a process or route to a 

process” as including emissions that “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.” Vapor recovery units and flow lines that would meet this definition 

would be considered part of the process and would not be considered control devices that are 

subject to the control requirements under the final amendments. We believe that the commenter 

has misinterpreted the vapor recovery device requirements considered to be control devices 

under the NSPS with vapor recovery units. However, we point out that the final amendments 

include provisions for consideration of emissions routed through vapor recovery units in 

determining storage vessel’s potential to emit for purposes of affected facility determination. See 

section IV.C of the preamble to the final amendments for a discussion of this issue. 

Comment: Two commenters (4615, 4630) request that the EPA clarify that control 

devices need only be operating when vapors are being routed to the control device. 

One commenter (4615) states that a VRU is usually set to operate only when needed and 

that the EPA should clarify that the control device must be operating when vapors are actually 

being pushed through the control device. The commenter suggests the following wording

changes to §60.5415(e)(3)(ii)(C) to ensure the correct interpretation of the word, “operational”:

§60.5415(e)(3)(ii)(C) (commenter added bold language and deleted word "operational"): 

Each closed vent system that routes emissions to a flow line, as defined in §60.5430, 

must be capable of being operated when the storage vessel affected facility is in 

service 95 percent of the year or greater.

This commenter (4615) also states that a flare or enclosed combustion device should only be 

required to be in operation when there is flow into the storage vessel affected facility and 

provided the following suggested language changes to §60.5412(d)(3) to address their comment: 

§60.5412(d)(3) (bold language added and "are" removed): You must operate each control 

device used to comply with this subpart at all times when there is flow into the storage 

vessel causing gases, vapors, and fumes to be vented from the storage vessel affected 

facility 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.
39

Response: We considered the commenters’ suggested edits. We did not make the 

suggested edits to §60.5415(e)(3) because we do not believe they would add clarity to the rule 

and the determination of when a closed vent system is “capable” of being operated presents 

significant enforcement challenges. We did not make the suggested edits to §60.5412(d)(3) 

because, even when there is no flow into the storage vessel affected facility, there are still 

emissions from breathing losses that occur when there is no liquid flow being introduced to the 

storage vessel.

2.2.7 Storage Vessel Alternative Control Requirement

Comment: Several commenters (4611, 4615, 4630) request that the definition of flow 

line be amended so that it applies to production field facilities and natural gas processing plants. 

One commenter (4630) recommends amending the definition of flow line to read as 

follows: 

Flow line means a pipeline used to transport oil and/or gas from the well or process to 

processing facility, a mainline pipeline, re-injection, or other useful purpose. The flow 

line includes any process equipment, such as a compressor, used to introduce a vapor 

stream into a pipeline or into other useful processes.

Another commenter (4615) requests that the storage vessel alternative control 

requirement allow for the use of vapor recovery to a flow line be modified to be applicable to 

midstream storage vessels. The commenter suggests 2 options to address their concerns: 

Option 1: Modify the definition of "flow line" to read as follows:

Flow line means a pipeline used to transport oil and/or gas from a well or process to a 

processing facility, a mainline pipeline, re-injection, or other useful purpose. The flow 

line includes any process equipment, such as a compressor, used to introduce a vapor 

stream into a pipeline, process line, fuel system or into other useful processes.

Option 2: Modify the rule language (e.g., §60.5395(e)(1)) wherever the alternative 

compliance option is addressed to read as follows: 

As an alternative to routing the closed vent system to a control device, you may route the 

closed vent system to a flow line, as defined in §60.5430, or to a process natural gas line. 

If you route vapors to a flow line, or to a process natural gas line, 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(c).

Response: We considered and agree with the commenters’ request that the definition of 

“flow line” be amended so that it does not appear to be restricted to flow that originates at a well.

In order to address commenters’ concerns, we made the following changes to the definition of 

“flow line” in the final amendments:
40

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 routed to a process or other useful purpose.

It is important to note that the 2012 NSPS includes a definition of “routed to a process or 

route to a process” as including emissions that “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.” Flow lines that would meet this definition would 

be considered part of the process and would not be considered control devices. We believe that, 

using this defined phrase within the definition of “flow line” addresses the commenters’ 

concerns.

2.3 Storage Vessel Recordkeeping Requirements

Comment: Several commenters (4615, 4620, 4626, 4630) request that the EPA allow 

owners and operators to maintain records off-site and/or maintain records in electronic format 

rather than paper format.

One commenter (4633) states that §60.5412(d) proposes that "all inspection, repair, and 

maintenance activities ... be recorded in a log ... available on-site for inspection." Instead of 

requiring that these logs be maintained on-site, the commenter proposes that such logs be "kept 

in a readily accessible location" as is required in other NSPS regulations. The commenter reports 

that they, like many operators, maintain required records in an electronic format, which allows 

both field and corporate personnel to readily access data and records without time-consuming 

trips to remote locations to confirm record availability. 

One commenter (4630) asserts that there is no need to maintain records onsite if they can 

be retrieved within a reasonable period of time. The commenter states that this is particularly true 

for unmanned sites, where there are no personnel available to maintain records. Further, the 

commenter asserts that production facilities often lack adequate building space to store records.

Two commenters (4620, 4626) recommend that any records required by the rule, such as 

proof of inspection and monitoring such as those in §60.5412(d)(1)(iii) not be required to be kept 

onsite, but be allowed to be maintained electronically or at the nearest field office.

Another commenter (4626) asserts that many affected vessels are located in remote areas 

and protecting records from exposure to the environment is difficult. Additionally, the 

commenter reports that some operators conduct inspections and monitor certain equipment 

electronically, and therefore do not always generate “paper copies” on location. The commenter 

opines that dictating that hard copies be maintained onsite is not necessary and may not be the 

best or most feasible way to retain the important information. The commenter asserts that, 

providing the operators the requested flexibility would benefit industry without harming the 

environment or reducing the EPA’s ability to monitor compliance effectively.
41

One commenter (4615) requests that the EPA remove the word “onsite” from 

§§60.5413(e)(4) and 60.5417(h)(3), and remove of the sentence “Manufacturer’s records must be 

maintained onsite” from §60.5420(c)(14).

Response: We agree with the commenters that it is not necessary for facilities to retain 

records onsite because there are typically no structures (such as offices) at well sites where 

documentation may be stored protected from the environment. We also clarify that there are no 

requirements in the 2012 NSPS that specify records must be maintained only on paper. 

Therefore, we have revised the final rule (§§60.5412(d)(1)(iii), 60.5413(e)(4), 

60.5415(b)(2)(vii)(C), 60.5417(h)(3), 60.5420(c)(13)) to reflect that records do not need to be 

maintained onsite. Further, we have amended §60.5420(c) to state that all records required by 

this NSPS may be kept onsite or at the nearest field office. The 2012 NSPS does, however, 

specify that records must be made available for inspection. If the owner or operator chooses to 

maintain records offsite, then they are still responsible to provide those records during 

inspections.

Comment: One commenter (4630) requests that §60.5420(c)(5)(iv) be edited to specify 

that the record of the length of time a storage vessel has been located at a site should be required 

to be maintained only while the storage vessel is actually onsite. Also, the commenter maintains 

that the drop-off and pick-up receipts should suffice as records of the duration of time that the 

vessel was onsite.

Response: The carbon management provisions of §60.5420(c)(5)(iv) are not within the 

scope of issues addressed by these final amendments.

2.4 Storage Vessel Notification and Reporting Requirements

2.4.1 Initial Notification Exemption for Compressors

Comment: Two commenters (4612, 4620) support the proposed revisions that add 

centrifugal and reciprocating compressors to the list of facilities that are not required to submit 

the notifications required by 40 CFR 60.7(a)(1), (3), and (4). According to one commenter 

(4612), it is appropriate that this exemption be extended to centrifugal and reciprocating 

compressors for the same reasons that well completions, pneumatic controllers and storage 

vessels are exempt from the notifications required by 40 CFR 60.7(a)(1), (3) and (4) in the final 

2012 rule.

Response: We acknowledge the commenters’ support and have finalized the revisions to 

add centrifugal and reciprocating compressors to the list of facilities that are not required to 

submit the notifications required by 40 CFR 60.7(a)(1), (3), and (4).

2.4.2 Initial Notification for Group 1 Storage Vessels

Comment: Two commenters (4615, 4630) request that the EPA allow initial notifications 

for Group 1 storage vessels to be submitted with the initial annual report. The commenters state 

that the proposed standard for Group 1 storage vessel affected facilities is to submit a notification 
42

with storage vessel identification and location, which is the same information required in the 

initial annual report which is due just 90 days later. The commenters state that, in order to avoid 

unnecessary duplication of reporting, the notifications for Group 1 storage vessel affected 

facilities should be specified as being due with the initial annual report, due 90 days after 

October 15, 2013. One commenter (4615) also states that requiring the submittal of these 

notifications 9 weeks after the final amendments are signed by the Administrator leaves little 

time to collect and compile the data required for submittal.

One commenter (4633) states that 40 CFR §60.5420(a)(3) and (b)(6)(i) requires the 

October 15, 2013, notice of Group 1 storage vessel affected facilities to be accurate to five 

decimal degrees latitude and longitude in North American Datum (NAD) 1983 format. The 

commenter requests additional time to gather latitude and longitude information for Group 1 

storage vessel affected facilities.

Another commenter (4623) requests that the EPA clarify that notifications are only 

required for tanks that exceed the 6 tpy threshold on October 15, 2013. 

Response: We considered and agree with the commenters’ request to allow initial 

notifications for Group 1 storage vessels to be submitted with the initial annual report to reduce 

the burden of having to submit duplicate information only a few months apart. Therefore, the 

final amendments (§60.5420(b)(6)(iv)) allow submittal of the Group 1 storage vessel affected 

facility notification with your initial annual report. By allowing the initial notification for Group 

1 storage vessels to be submitted with your annual report additional time to gather latitude and 

longitude information will be provided. We also clarify that only Group 1 storage vessel affected 

facilities (Group 1 storage vessels with the potential to emit VOC of 6 tpy or more), not all 

Group 1 storage vessels, are subject to the notification requirements.

Comment: One commenter (4630) recommends that the EPA clarify the 

latitude/longitude coordinates and datum requirements (required in the initial notification and 

initial annual report). The commenter asserts that GPS devices and other systems tend to display 

latitude and longitude coordinates to 5 decimal places, but that does not mean they are absolutely 

accurate to 5 decimal places. The commenter requests that §60.5420(a)(3) be modified to specify 

that the system is “represented by the vendor” to an accuracy of “five (5) decimals of a degree 

plus or minus 30 feet.” Furthermore, the commenter asserts that GPS devices and other systems 

for determining latitude and longitude do not all use the NAD 1983 format, and there is no 

reasonable rationale for requiring this reference.

Response: The proposed amendments did not include revisions to the sections of the 

NSPS addressed by this commenter and are, therefore, not within the scope of issues addressed 

by these final amendments.

2.4.3 Responsible Official

Comment: Several commenters (4613, 4615, 4623, 4628, 4630) request that the EPA 

remove the requirement for annual reports to be certified by a responsible official.
43

One of the commenters (4623) asserts that the requirement for minor sources regulated 

under the rule to submit annual compliance certifications signed by a “responsible official” was 

reserved for major sources (and not minor sources) by Congress under the CAA.

Similarly, another commenter (4615) opines that the requirement for certification by a 

responsible official is overreaching for an NSPS regulation addressing minor emissions sources.

The commenter asserts that certification by a responsible official should not be required for what 

are usually very small sources. According to the commenter, if required, delegation to local field 

supervision should be provided. Furthermore, the commenter asserts that obtaining the necessary 

information and preparing these reports and obtaining a responsible official signature will be 

very difficult to complete within 30 days, especially since these reports will be due at many 

different times throughout the year. The commenter suggests that, if the EPA insists on a

responsible official signature, then moving the time from 30 days to 90 days will at least help 

give operators sufficient time to obtain, prepare, and certify the information necessary for the 

annual reports.

Two commenters (4628, 4630) argue that the requirement for a responsible official as 

defined in title V to certify annual compliance reports for area sources is inappropriate and 

overly burdensome. The commenters suggest that the EPA develop a certification requirement 

specific to subpart OOOO that uniquely defines a responsible official as someone much lower in 

the management hierarchy. According to the commenters, this would result in a person with 

more direct knowledge of the operations being requested to certify the report, with no loss of 

accuracy or truthfulness. The commenters state that, unlike a title V site which has a defined 

boundary and a relatively fixed number of emission sources for which compliance must be 

certified, many oil and gas operators will have sources regulated under subpart OOOO that will 

be dispersed among hundreds or thousands of small sites across wide geographic areas. The 

commenters are concerned that the number of sources requiring annual certified compliance 

reports will continue to grow as more and more regulated sources are constructed. As a result, 

the commenters state that the reporting burden will compound each year. According to the 

commenters, requiring a title V equivalent responsible official to absorb this ever increasing 

burden will detract from that person’s normal management responsibilities, and make it 

increasingly difficult to conduct the necessary “reasonable inquiry” necessary for certification as 

high level managers, particularly for larger companies, do not have direct oversight of the 

operations requiring compliance certification. The commenters assert that it is much more 

appropriate to push the certification requirement down to the management level that has direct 

oversight of the operations. The commenters maintain that this would more effectively spread the 

load of certification among more supervisors and reduce the burden as it continues to grow over 

time. The commenters further state that with direct oversight of operations, local or regional 

management is in a much better position to conduct “reasonable inquiry” to certify the truth and 

accuracy of the report. According to the commenters, if responsible official is defined under 

subpart OOOO as a first line operations or regulatory supervisor with direct oversight of 

operations or any higher level of management, operators will have the flexibility of determining 

who is the most appropriate person to certify reports based on their organizational structure and 

hierarchy and will accommodate both large and small operators.
44

Another commenter (4623) states that the requirement for an annual compliance 

certification by a responsible official is burdensome and inappropriate for this source category. 

The commenter asserts that, while it may work for large title V facilities, it is not true for the oil 

and gas sector. The commenter reports that, at a typical title V facility, the responsible official is 

the plant manager who is typically located at the facility, has responsibility for overall plant 

operations, and is in daily contact with operations and compliance personnel. According to the 

commenter, in the oil and gas sector, the affected sources are spread out over large areas and are 

only infrequently visited by personnel. Additionally, the commenter reports that the requirement 

that a responsible official have overall responsibility over one or more facilities that employ 

more than 250 persons or have sales exceeding $25 million (1980 dollars) does not work well for 

oil and gas facilities that are generally very small with no full time employees and low revenue. 

The commenter asserts that, to meet these requirements it will likely require a high-level official 

within the company who will not have working knowledge of the day-to-day operations of the 

oil and gas wells. The commenter encourages the EPA to seek to have personnel in supervisorial 

roles closest to the operation submitting the reports to the Agency. The commenter asserts that 

these personnel will still have a significant level of responsibility and also be far more 

knowledgeable of the day-to-day operations of the affected sources than would a responsible 

official as the EPA defines it. The commenter asserts that the EPA would still achieve its goal of 

assuring the public that the information submitted is accurate while reducing the burden on the 

regulated companies.

One commenter (4613) states that the responsible official would be required to sign 

annual reports certifying the truth, accuracy and completeness of the information contained 

therein for a substantial number of small affected facilities spread over a large area. According to 

the commenter, with regards to their company, there are only a few vice-presidents or officers 

that would qualify as a responsible official. The commenter recommends that the EPA develop

alternative responsible official criteria for this NSPS so that field management personnel, who 

are closer to the day-to-day affected facilities and likely more knowledgeable to make a 

reasonable inquiry to certify "truth, accuracy and completeness" of information in the report, 

qualify. The commenter requests that alternative criteria language in the rule would allow 

additional company personnel to sign annual reports for this NSPS and would streamline the 

reporting process, facilitate verification of report content and ease compliance.

Response: The requirement for the annual report to be signed by a responsible official is 

not within the scope of issues addressed by these final amendments. However, we have finalized 

the proposed amendment that submittal of the annual report and compliance certification be 

extended from 30 days to 90 days after the compliance period. We believe this will give 

operators and the designated responsible official sufficient time to obtain, prepare, and certify the 

information necessary.

2.4.4 Reporting Deadline

Comment: Several commenters (4612, 4613, 4617, 4620, 4624, 4633) provide support 

for extending the annual report and compliance certification reporting deadline to 90 days past 

the end of the compliance period. 
45

Specifically, three commenters (4612, 4613, 4624) support the EPA’s proposal to amend 

§60.5420 to allow 90 days from the end of a compliance period for facilities to submit their 

annual report and compliance certifications. Two of the commenters (4612, 4624) assert that the 

proposed change to §60.5420(b) would make the reporting requirements consistent with title V 

requirements and certification requirements.

Two commenters (4612, 4613) assert that a large number of facilities/companies would

have many sources covered by these rules necessitating the additional time to submit their annual 

report. One commenter (4613) asserts that, for their company, a large number of affected 

facilities would need to be rolled up into one report that would be signed by one Vice-President 

and that this requires additional time in order that the responsible official (in this case the VicePresident of their company) can perform a reasonable inquiry that would be necessary to achieve 

compliance. Similarly, commenter 4612 asserts that affected facilities need the additional time to 

compile, verify, and report the required information. 

Two commenters (4617, 4620) state that production, monitoring, and other operational 

data are typically not available for at least 60 days after the close of the month, so 90 days are 

necessary in order to compile and verify the report.

Response: We acknowledge the commenters support and have finalized the proposed

amendments to allow 90 days after the end of the compliance period for submittal of the annual 

report and compliance certification.

2.5 Compliance Demonstration and Monitoring Provisions

2.5.1 Vapor Recovery Units

Comment: One commenter (4613) requests that the EPA explicitly confirm that vapor 

recovery units (VRUs) are considered process devices, not control devices, in the rule.

Response: The EPA clarifies that VRUs that route emissions to a process are considered 

part of that process and are not considered control devices. 

2.5.2 Leaking Closed Vent Systems and Covers

Comment: One commenter (4622) asserts that the EPA should not extend the repair 

periods for permanent repair of storage vessel leaks to 30 calendar days. According to the 

commenter, the EPA did not provide any explanation of or support for, and did not mention in 

the preamble, the proposed extension of time allowed for permanent repair of storage vessel 

leaks to 30 calendar days. The commenters report that subpart OOOO currently requires 

permanent repairs of observed leaks within 15 days. The commenter referred to a court case 

where an agency changing its course must supply a reasoned analysis [Cf. Motor Vehicle Mfrs. 

Ass'n v. State Farm Mut. Auto. Ins., 463 U.S. 29, 57 (1983)]. The commenter states that the 30-

day repair deadline is significantly less stringent than some of the state and local requirements 

currently in effect. The commenter reports that some states require repairs to be completed 

within 72 hours of detection.
46

One commenter (4611) requests that the EPA clarify when sources would be required to 

complete repair of a closed vent system or cover for which a leak has been discovered if repair is 

delayed.

Response: In the preamble to the proposed amendments (see 78 FR 22134), we discussed 

issues raised by petitioners related to the compliance monitoring requirements and the burden 

these requirements placed on affected facilities in light of our revised estimate of the number of 

storage vessel affected facilities. In response to these concerns, the EPA proposed certain 

streamlined monitoring and compliance demonstration requirements and we are finalizing the 

streamlined requirements in the final amendments. One aspect of the streamlined requirements is 

the increase in the time to complete permanent repairs from 15 days to 30 days. We continue to 

believe that, because of the large number of storage vessel affected facilities along with the 

remoteness of their location, a longer period of time to complete permanent repairs is warranted. 

We note that we continue to evaluate the issue raised by commenters concerning the more 

stringent compliance provisions of the 2012 final NSPS. We intend to complete our evaluation of 

monitoring provisions by the end of 2014.

Concerning the comment on when repairs must be completed if the repair is delayed, 

§60.5416(c)(5) of the final amendments specifies that such repairs must be completed at the next 

shutdown.

2.5.3 Performance Testing

2.5.3.1 Manufacturer’s Performance Testing Requirements

Comment: One commenter (4633) supports the use of manufacturer information to 

demonstrate compliance with control efficiency requirements. The commenter also supports the 

use of visual, olfactory, and auditory inspections of the facility.

Several commenters (4612, 4614, 4618, 4620) support manufacturing testing provisions 

that allow for the certification of specific device makes and models. 

One commenter (4614) states that, by allowing the control device manufacturers to 

perform compliance testing on the specific model of control device over a range of operating 

conditions, the EPA can ensure that these devices will meet the percent reduction requirements 

of the rule, while still requiring owners and operators to monitor site specific operating 

conditions to demonstrate that actual operations are within the design parameters of the control 

device.

Another commenter (4618) generally supports the concept of certifying a unique control 

device model based on a single set of tests as stipulated in proposed §60.5413(d). The 

commenter states that the model of control device that will receive a certification based on 

testing of the same model should have the same physical and operational characteristics such that 

the same (successful) compliance test would have resulted if the manufacturer had actually run 

the same tests on each certified device.
47

One commenter (4620) supports the manufacturer testing provisions that allow for the 

certification of specific device makes and models and aligns testing requirements between 

NESHAP subpart HH and NSPS subpart OOOO.

Other commenters (4629, 4630) express concern over the use of manufacturers 

performance testing being allowed to demonstrate compliance with control efficiency 

requirements.

One commenter (4629) states that they do not believe that manufacturers performance 

testing will be representative of actual field performance of the control device environment when 

the equipment is operated in the field. According to the commenter, temperature control would 

require capability to control both air feed and fuel feed and be a more expensive system to 

provide and that adherence to the requirement that the system is designed and operated in 

accordance with §60.18(b) should be a sufficient requirement to avoid costly temperature control 

requirements for these control devices.

Another commenter (4630) states that they support innovative approaches that would 

truly reduce the burden on EPA, the states, and the regulated community. However, the 

commenter opines that if the Agency intends to expand their reach into identifying specific 

pollution control manufacturers and models that are “compliance ready,” there are likely many 

years of work that will need to be done in advance of finalizing any rule to avoid compliance 

complications for the regulated community. The commenter questions whether or not this will 

truly result in a burden reduction or only complicate compliance and the rulemaking process. 

Finally, according to the commenter, the introduction of new or innovative approaches to CAA 

compliance should not take place within proposed amendments for a single source category. The 

commenter encourages the EPA to seek ways to streamline compliance and reduce the burden on 

all affected parties. However, they believe that the EPA should propose these new approaches in 

a separate Federal Register notice as an Advanced Notice of Proposed Regulation and take 

comment from all source categories that are subject to NSPS. In any event, the commenter 

opines that the Agency should not finalize this approach in this rulemaking until it has worked 

with all stakeholders.

Response: The EPA thanks the commenters for their support concerning amendments to 

the combustor control device manufacturer test protocol and associated reporting requirement to 

align them with similar provisions in the Oil and Natural Gas NESHAP (40 CFR 63, subpart 

HH), and clarify that manufacturer testing is not mandatory. 71 FR at 22135. Regarding the 

broader comment questioning the use of manufacturer performance testing, its use was finalized

in the 2012 NSPS. The matter was not reopened for notice and comment and, therefore, is not 

within the scope of this rulemaking. 

Regarding one commenter’s recommendation that adherence to the requirement that the 

system is designed and operated in accordance with §60.18(b) should be a sufficient requirement 

to avoid temperature control requirements for these control devices, the EPA notes that 

§60.18(b) applies specifically to flares and is not applicable here to enclosed combustors. 

Regarding one commenter’s recommendation that the EPA propose new approaches and take 

comment for all source categories subject to NSPS, we note that this is beyond the scope of this 

action.
48

Regarding the comments related to innovative approaches, we do not consider 

manufacturer testing to be a new concept introduced in this rule. The Agency has used this 

approach in other rules in the past and has not experienced any of the unforeseen complications 

or years of delay envisioned by the commenter.

Comment: One commenter (4624) requests that the EPA ensure that certification of 

combustors as “compliance ready” take into account proper design, installation and operation 

requirements. The commenter is concerned that the EPA's certification of combustors as 

"compliance ready" based on manufacturers' performance testing would not take into account 

proper site-specific design requirements, installation, or operation of the combustors. 

Response: The NSPS, including today’s amendments, does not include a certification 

process; rather, it includes a control device manufacturer testing protocol, which requires three 

one-hour test runs for each of four rate settings to verify that the control device can meet the 

control requirements of the 2012 NSPS under a variety of conditions. To the extent the 

commenter is asking whether the manufacturer testing protocol accounts for site-specific design, 

installation or operation, they are not covered in the protocol because the EPA believes that it is 

the responsibility of the owner or operator to properly select and install a combustor based on 

site-specific needs. However, we note that the final amendments include initial and continuous 

compliance requirements to help assure proper operation of the control device.

Comment: One commenter (4629) requests that the EPA clarify whether they are 

providing design certification requirements for enclosed combustors. According to the 

commenter, if the EPA provides design certification requirements for enclosed combustors, they 

assume this certification will be public and complete in providing what operation range it has 

been tested and certified. The commenter further states that they assume that the EPA will 

defend an EPA certified design at EPA expense as needed in questioned performance litigation.

Response: EPA clarifies that neither the 2012 NSPS nor the final amendments include 

design certification requirements for enclosed combustors. Rather, the NSPS allows 

manufacturer testing in lieu of field testing and includes a manufacturer testing protocol which 

requires three one-hour test runs for each of four rate settings to verify that the control device can 

meet the control requirements of the 2012 NSPS under a variety of conditions. We believe that 

operators have an incentive to use manufacturer-tested combustors because those combustors 

have reduced frequency of visible emissions testing. The NSPS prescribes a specific test protocol 

that must be followed and certain criteria that must be met for manufacturer-tested combustors, 

including no visible emissions, emission limits for THC and CO and a percent excess air 

requirement. Once a model has been tested and a complete test report is sent to the EPA, we will 

review the test report to ensure that the model tested meets the required criteria. The EPA will 

post the models meeting the combustor test protocol on our website (listed in the final 

amendments). 

Comment: One commenter (4614) requests clarification on whether a test protocol is 

required to be submitted to the EPA for approval prior to conducting the performance test if the 

procedures in §60.5413(d) are followed. The commenter requests that, if pre-test protocol 
49

submittal and approval is not required, that the option to submit a protocol for EPA approval for 

deviations from the test protocol be outlined in the rule.

Response: We do not require that a performance test protocol be submitted to the EPA 

prior to conducting the manufacturer performance test. We also decline to include the option to 

submit for EPA approval a request for deviation from a test protocol. The performance test 

procedures in the final rule must be followed and a complete test report must be submitted to the 

EPA before a model that meets the required criteria will be listed on the EPA’s website. 

Comment: One commenter (4618) states that the EPA solicited comment on a potential 

compliance approach based on the use of these manufacturer-tested combustor models. The 

commenter suggests that EPA Method 19 should be considered as an alternative flow 

measurement method. The commenter reports that this method uses either the O2 or CO2 

concentration, the fuel "F" factor, and fuel flow rate to calculate the emission flow rate using 

stoichiometric calculations.

Response: The EPA declines to include Method 19 as an alternative measurement 

method. Method 19 does not explicitly provide details for the calculation of flow rate. Given that 

the manufacturers’ performance tests will be used by a variety of manufacturers, the EPA 

believes that each test should be conducted consistently. Thus, the EPA will not allow Method 

19 as an alternative flow rate measurement.

Comment: One commenter (4614) states that they do not believe that a requirement for 

manufacturers to report the names of entities that had purchased certified control devices will 

provide any additional compliance certification for the EPA. According to the commenter, once 

the unit is purchased, the manufacturer loses control over where the unit may be installed, 

whether the unit is resold, if the unit is moved or otherwise maintained and operated in a manner 

consistent with manufacturer recommendations, etc. Therefore, the commenter believes that such 

a report will be quickly outdated and lose its effectiveness as a compliance evaluation tool.

Response: We do not require that a manufacturer report the names of entities who 

purchase their control devices.

2.5.3.2 Collecting the Gas Sample in a Bag

Comment: One commenter (4618) states that §60.5413(d)(7)(i) specifies collecting the 

gas sample in a bag for analysis using a gas chromatograph-thermal conductivity detector. 

According to the commenter, collecting samples in a bag can create a number of problems. The 

commenter suggests that the EPA include the option of pulling the sample directly from the 

source into the instrument via a heat-traced sample line in the rule.

Response: Although the commenter may have concerns about collecting the gas sample 

in a bag, the commenter did not sufficiently explain the potential problems with bag sampling, 

and the EPA is making no change in the final amendments with regard to gas sample collection 

procedures. Variations to established test methods must be evaluated on a case-by-case basis to 

avoid unintended consequences that may result at other facilities having different operating 

conditions or situations than those presented by the commenter. However, we note that a source 
50

may make a request to the EPA under the provisions of §60.8(b) for an alternative test method, 

including direct sampling as an alternative to bag sampling.

2.5.3.3 Use of Alternative Gases as the Testing Fuel 

Comment: Two commenters (4629, 4630) request that the EPA allow the use of 

alternative gases as the testing fuel when conducting manufacturer’s performance tests. 

One commenter (4630) recommends that the EPA allow the use of propane, rather than 

propene, as the testing fuel for the manufacturers' performance test. The commenter opines that 

the preferred gas for the testing fuel should be propane, rather than propene. According to the 

commenter, use of the turn-up and turn-down of fuel to set an operating envelope, as required by 

this rule, would result in a more representative performance curve if the testing fuel were 

propane, in that propane is more representative of field conditions and thus is a better indicator 

of representative performance than is propene. Furthermore, the commenter asserts that propene 

is less readily available, more costly, and is a more highly reactive

VOC than propane.

The other commenter (4629) requests that the test gas for manufacturers performance 

testing be changed to methane or ethane to be, in their opinion, more reflective of the intent of 

the regulation. The commenter provides that their understanding is that the intent of the subpart 

OOOO regulation is to reduce methane and ethane emissions to the atmosphere and methane and 

ethane make up a majority of the gas constituents in the applications that will be most affected 

by the regulation. The commenter states that, if reduction in methane and ethane is the intent, 

propene does not have relevancy in this testing. According to the commenter, all testing for the 

manufacturer's performance test requires propene as the test gas to determine VOC destruction 

efficiency. The commenter states that, not only is propene an easier hydrocarbon to destroy than 

methane or ethane but it is also a less available and more expensive gas to test with than methane 

or ethane. 

Response: The EPA notes that propylene gas has long been the standard fuel for flare 

testing, and is a more rigorous fuel with which to display performance than propane, methane or 

ethane. In addition, it is not feasible to require field gas as the test fuel as field gas varies greatly 

by region and basin and transport to the manufacturer would be difficult. Propylene was chosen 

as the manufacturer test fuel to ensure that a tested model would sufficiently destruct VOC in the 

field and was also used as a test fuel by another combustor manufacturer when performing 

controlled testing of combustors in recent years.

2.5.3.4 Alternative to Method 4

Comment: One commenter (4618) reports that §60.5413 specifies Method 4 for 

determining moisture and requests that the EPA consider FTIR instrumentation using EPA 

Method 320 or ASTM D6348-12 as an alternative test method to Method 4 where it is 

applicable. The commenter states that Method 4 requires pulling stack gas through chilled 

impingers containing water and silica gel and measuring the sample volume with a calibrated dry 

gas meter. According to the commenter, the percent moisture is calculated using the 

volume/weight gain in the impinger train. The commenter states there currently are several 
51

instrumental methods available that can monitor stack moisture. The commenter reports that 40 

CFR 75, §75.11(b)(2) describes several options that are currently in use and that advances in 

instrument technology, such as Fourier Transform Infrared (FTIR) Spectroscopy, can monitor 

multiple analytes, including moisture.

Response: The EPA is making no change in the final amendments with regard to 

alternatives to Method 4 in response to this comment. The EPA evaluated this comment and 

determined that the commenter did not provide sufficient quality assurance/quality control 

(QA/QC) procedures, such as spiking procedures, to include Method 320 or ASTM D6348-12 as 

alternatives to Method 4. We also note that variations to established test methods must be 

evaluated on a case-by-case basis to avoid unintended consequences that may result at other 

facilities having different operating conditions or situations than those presented by the 

commenter. However, we note that a source may make a request to the EPA under the provisions 

of §60.8(b) for an alternative test method.

2.5.3.5 Integrated burner system

Comment: One commenter (4614) seeks clarification on whether an integrated burner 

system to manage emissions from storage vessels (or any similar system) would be subject to 

two sets of testing requirements: (1) when firing the vented emissions in the burner, the unit 

meets the intent of the process heater/boiler control option exempt from performance testing in 

§60.5413(a)(3); and (2) when use of the supplemental afterburner would be classified as a 

control device that requires either the manufacturer testing or site-specific testing in §60.5413.

Response: We have reviewed the information submitted by the commenter, and believe 

that an integrated burner system, as described by the commenter, would be a combustion control 

device and not a heater or boiler. Therefore, the integrated burner system described would be 

subject to the applicable requirements for combustion control devices.

2.5.3.6 Visible Emissions and Method 22 Requirements

Comment: One commenter (4611) requests that the EPA clarify what period of time 

would constitute a visible emissions violation. The commenter reports that the preamble and rule 

are inconsistent.

Response: The EPA clarifies that for manufacturer-tested enclosed combustors the 

required frequency of the Method 22 test is quarterly and devices must be operated with no 

visible emissions, except for periods not to exceed a total of 2 minutes during any hour. For all 

other combustion controls, the required frequency of the Method 22 test is monthly and devices 

must be operated with no visible emissions, except for periods not to exceed a total of one 

minute during any 15 minute period.

Comment: One commenter (4630) recommends that the EPA change the Method 22 

observation period for the manufacturer-tested devices to match the requirements for devices not 

tested by the manufacturer. Specifically, the commenter requests that the observation period for 

manufacturer-tested devices be 15 minutes rather than1 hour. The commenter asserts that using a 

1 hour observation period and the Method 22 test method would require the operator to dedicate 

an hour and 15 minutes to complete the visible emissions observation. At a minimum, the 
52

commenter states that this would result in an additional 1 hour of time on-site for a lease operator 

and subsequently fewer facility visits per day/week/month, etc. The commenter opines that all 

that should vary between manufacturer-tested devices and those not tested by the manufacturer is 

the minimum frequency of site inspections (i.e., quarterly rather than monthly). 

Response: The EPA is finalizing the streamlined compliance monitoring requirements, 

as proposed, with minor clarifying changes. As we stated in the preamble to the proposed 

amendments (78 FR 22134), we will continue to fully evaluate the compliance demonstration 

and monitoring issues. We intend to complete our reconsideration of these requirements, along 

with other issues for which we intend to grant reconsideration, by the end of 2014. We note, 

however, that the Method 22 test frequency for manufacturer tested units is quarterly, so that 

even with an observation period of 1 hour we do not believe a quarterly test would result in a 

significant burden as the commenter suggests. 

Comment: Three commenters (4619, 4623, 4630) request that the EPA clarify the EPA 

Method 22 requirements. The commenters (4623, 4630) opine that the EPA should only require

Method 22 inspections when smoke or visible emissions are observed, rather than monthly, 

whereas the other commenter (4619) suggests that the EPA substitute the current Method 22 test 

requirements for a “smoke/no smoke” test.

Response: Method 22 is a test for the determination of the frequency of smoke 

emissions. It is a Federal reference method which was proposed and promulgated and is used in 

many EPA rulemakings. It is a simple test method which can be used to inform operators of 

potential combustion control device issues/malfunctions. The EPA believes that performing a 

Method 22 test only if smoke is seen will not assure the same level of compliance as a periodic 

Method 22 test. 

Comment: One commenter (4630) argues that the EPA should change the references to 

the Method 22 test procedure to specifically reference section 11.4.1. The commenter states that 

the Method 22 procedure should be more specifically referenced to identify the intended 

requirements of section 11.4.1, so as to avoid the unintended prescription of the form and sketch 

specified in sections 11.2 and 11.5. Also, according to the commenter, given that the specified 

15-minute observation period does not have any breaks, the commenter maintained that 

measurement of the duration of that period does not require a stopwatch. According to the 

commenter, any type of chronometer, such as a clock, ordinary wristwatch, cell phone or 

computer would be suitable.

Response: The EPA evaluated this comment and believes that the reference to section 11 

of Method 22 is appropriate and that referring to a number of different subsections within section 

11 would be unnecessarily complicated. Regarding the commenter’s statement on the use of a 

stopwatch, we believe that any chronometer whose functionality includes that of a stopwatch 

would be permissible.
53

2.5.3.7 Clarification of the Timing of Performance Testing

Comment: Two commenters (4614, 4631) request clarification on the timing of 

performance testing. The commenters request that the language originally stated in the August 

16, 2012 final rule be included with the date modified for Group 2 storage vessels as follows:

"You must conduct an initial performance test as required in § 60.5413 within 180 days 

after initial startup or within 180 days of April 15, 2014, whichever is later.”

According to the commenter (4631), as the VOC emission rate determinations and reduction 

requirements for Group 2 storage vessels are not required until April 15, 2014, per 

§60.5395(c)(1), and (d)(1), respectively, it is not appropriate to require that an initial 

performance test be completed by the same date.”

Response: Since field performance testing in not required in the final amendments, the 

commenters’ concern is now moot. 

2.5.4 Compliance Monitoring Requirements

Comment: Two commenters (4612, 4626) provide support for the EPA’s proposed 

streamlined monitoring and continuous compliance demonstration requirements in lieu of the 

requirements currently contained in the Oil and Gas NSPS. One commenter (4612) supports both 

the EPA's decision to reconsider the requirements contained in the final rule and also the EPA's 

proposal to replace those requirements, on an interim basis.

Response: The EPA thanks the commenters for their support.

Comment: One commenter (4630) requests that the EPA add provisions for remote 

notification of open bypass devices at unmanned facilities.

Response: The final rule does not proscribe the use of remote notification of open bypass 

devices. We understand that many of the facilities subject to the NSPS are unmanned and in 

remote locations. Thus, the owner or operator may install systems that allow remote notification, 

such as at a field office, for open bypass devices. We also note that the final amendments also 

allow records to be maintained at the nearest field office instead of maintaining the records 

onsite.

Comment: One commenter (4611) requests that the EPA should clarify the definition of 

“no detectable emissions” and its application to closed-vent systems, including inspection 

requirements. Similarly, this commenter requests that the EPA clarify what "leak free condition" 

means as stated in the requirements to demonstrate initial compliance with the enclosed 

combustion device requirements. The commenter is concerned that, since the EPA has not 

presented a definition of leak free condition for the operation of enclosed combustion devices, 

the discovery of a leak would mean an automatic violation, without regard for pending repair or 

correction. The commenter asserted that, typically, discovery of a leak would trigger the source 

to repair or fix the leak within a prescribed timeframe, and the enforcing agency would consider 

these mitigating efforts in any noncompliance assessment.
54

Response: In §60.5411(c)(2) of the final amendments, we specify that closed vent 

systems must be designed and operated with no detectable emissions as determined using an 

olfactory, visual and auditory (OVA) inspection. Therefore, a condition of no detectable 

emissions would result when the OVA inspection revealed no leaks that were smelled, seen or 

heard during the inspection. Similarly, §60.5417(h) requires monthly OVA inspections of control

devices, and operating in a leak free condition would mean that no leaks that were smelled, seen 

or heard during the inspection.

Comment: One commenter (4611) requests that the EPA revise the proposed language to 

reflect that AVO for closed vent systems be required for all oil and gas sites, but opined that 

requiring AVO alone would be insufficient for production field facilities and gas processing 

plants, especially at facilities that include other processes and equipment subject to more 

extensive leak detection requirements.

Response: In the preamble to the proposed amendments (see 78 FR 22134), we discussed 

issues raised by petitioners related to the compliance monitoring requirements and the burden 

these requirements placed on affected facilities in light of our revised estimate of the number of 

affected facilities. In response to these concerns, the EPA proposed certain streamlined 

monitoring and compliance demonstration requirements and we are finalizing the streamlined 

requirements in the final amendments. One aspect of the streamlined requirements is to require 

monthly AVO inspections of covers, closed vent systems and control devices. In part, these 

AVO requirements replaced field testing requirements. The AVO requirements apply to storage 

vessels throughout the oil and natural gas production segment, natural gas processing segment 

and natural gas transmission and storage segment. We see no reason, nor does the commenter 

provide reasons, why the AVO methods would not be effective for storage vessels in production 

field facilities and gas processing plants

However, it appears that the commenter may be stating that the AVO methods may not 

be appropriate for equipment other than storage vessels at production field facilities and gas 

processing plants. We point out that the AVO requirements in the final amendments apply only 

to storage vessels (and centrifugal compressors). The 2012 NSPS includes LDAR requirements 

for natural gas processing plants at §60.5400.

2.5.5 Startup, Shutdown and Malfunction

Comment: One commenter (4630) requests that the EPA amend §60.5411(c)(3)(ii) to 

include a specific exemption for pressure relief valve safety devices so that it is clear they do not 

require a flow indicator and alarm required for bypasses. According to the commenter, the 

purpose of the pressure relief valve is to protect the integrity of the storage vessel by allowing 

vapors to quickly exit the storage vessel and avoid an over-pressure condition. The commenter 

states that a flow meter would restrict flow from the relief valve, which could compromise the 

storage vessel integrity and possibly result in catastrophic failure in a worst-case scenario.

Response: We believe the pressure relief devices the commenter is referring to are

conservation vents. It was not our intent to consider emissions from conservation vents on 

atmospheric storage vessels subject to the NSPS to be bypasses. The conservation vents on these 
55

storage vessels function to relieve both over-pressure and under-pressure situations that occur 

during normal operation of atmospheric storage vessels. This type of operation of the 

conservation vent is in contrast to a pressure relief device on a pressurized storage vessel in 

which a significant emissions event may occur when the pressure relief device opens and is 

designed to avoid a catastrophic failure of the storage vessel, which is the situation we intended 

for installation of flow indicators and alarms. We also note that the storage vessels subject to the 

NSPS are typically equipped with a weighted thief hatch in addition to a conservation vent. The 

thief hatch will function to relieve pressure to prevent a catastrophic failure of the storage vessel.

Comment: One commenter (4630) requests that the EPA clarify that certain features 

(e.g., sampling ports, when obtaining material samples from the storage vessel, and pressure 

relief devices, when it is necessary to relieve excess pressure) of the cover and closed vent 

system have operational or safety related functions that are allowed to be open without having 

vapors routed through a closed vent system.

Response: Sample ports would be subject to the cover requirements of §60.5411(b), 

which specify that each cover opening must be secured in a closed, sealed position when the 

opening is not in use (such as while obtaining a sample). The cover requirements in §60.5411(b) 

are designed to convey as much of the vapors as possible to the control device. Since these 

openings are subject to the cover requirements, we did not intend for them to also be vented 

through a closed vent system.

Comment: One commenter (4611) suggests that the EPA include monitoring and 

recordkeeping for downtime or the time that equipment is operating but the air pollution control 

equipment is not available.

Response: We note that the owner or operator is required to meet the control 

requirements of §60.5395(d) at all times, and we disagree that imposing additional monitoring 

and recordkeeping requirements beyond that specified in the final amendments are warranted. 

The final amendments also require certain monthly inspections of covers, closed vent systems 

and control devices, and any abnormalities noted during these inspections must be recorded. We 

believe these monthly inspections and the associated recordkeeping are sufficient for the 

situations presented in the comment.

2.6 Compliance Schedule

Comment: Several commenters (4613, 4615, 4617, 4620) provide support for the EPA’s 

phased in approach to storage vessel requirements and proposed control installation date of April 

15, 2014.

One commenter (4615) states that the proposed control installation date of April 15, 

2014, for Group 2 storage vessels is consistent with the EPA’s recognition that sufficient control 

equipment won’t be available for the large number of storage vessels that will be subject to the 

rule. The commenter asserts that such controls cannot be considered BSER until after a sufficient 

compliance time, i.e., April 15, 2014.
56

Response: Please see section IV.B of the preamble to the final amendments for a 

discussion on the Group 2 compliance date in the final amendments.

Comment: Two commenters (4613, 4623) request that the EPA provide for a streamlined

process by which regulated entities can obtain an extension of the compliance date upon 

demonstration that controls are not available or reasonably available. One of the commenters 

(4623) suggests that the EPA provide for a petition or other “exception” process. 

Response: As explained in more detail in Section IV.A of the preamble to the final 

amendments, the EPA has re-analyzed the availability of control devices and, based on rationales 

set forth in that section, extended the compliance date in the 2012 NSPS to provide sufficient 

time to obtain and install control devices. In light of the compliance deadlines in the final 

amendments, we believe that a provision to allow further extension is not needed. See section 

IV.A of the preamble to the final amendments for a discussion of control device availability.

2.7 Number of Storage Vessels at Different Throughput Levels (“Higher 

Emitting Storage Vessels”)

Comment: Two commenters (4615, 4630) opine that it is very difficult to provide 

information on the number of storage vessels with different potential VOC emissions due to the 

many variables that affect emissions, such as throughput, separator temperature and pressure, 

and separator liquid composition and API gravity, especially given the time constraints of the 

comment period. 

Two commenters (4615, 4630) state that the EPA has not defined “higher emitting”

storage vessels; however, they suggest that a storage vessel or a battery of storage vessels that 

can potentially emit more than title V major source threshold of 100 tpy VOC be considered 

“higher emitting storage vessels.” The commenters provide that the EPA should not be overly 

concerned about the number of “higher emitting storage vessels” that may remain uncontrolled 

until April 15, 2014, for the following reasons: 

(1) All “higher emitting storage vessels” are already subject to existing air permitting 

requirements. The commenters explain that operators will typically install controls on any 

storage vessel or a battery of storage vessels with a potential to emit VOC above title V major 

source thresholds in order to avoid title V permitting if possible. The commenters further explain 

that for storage vessels located at gathering stations and gas processing plants, there are other 

significant VOC emission sources located at the site such that the amount of VOC emitted from 

storage vessels is further limited if an operator wishes to avoid title V permitting. The 

commenter states their belief that there will be few storage vessels or batteries of storage vessels 

prior to April 15, 2014, that are emitting VOC above or near title V major source thresholds.

(2) Operators will often install controls on storage vessels or a battery of storage vessels 

in order to use a more streamlined state air permitting process. The commenters explain that 

some states have minor source permits such as general permits or permits by rule with 

limitations on total VOC emissions that are significantly less than title V major source 

thresholds. Therefore, the commenters maintain that “higher emitting storage vessels” must be 

controlled in order to permit midstream facilities under the general permits or permits by rule. 
57

The commenters also state that some states may apply BACT requirements in state general 

permits or permits by rule which may further limit the amount of VOC that can be emitted from 

storage vessels at permitted midstream facilities.

(3) While there may be tens of thousands of Group 1 storage vessels industry-wide with 

potential uncontrolled VOC emissions between 1 tpy and 50 tpy, there will not be that great a 

number of Group 1 storage vessels that are “higher emitting.” According to the commenters, the 

EPA does not need to require control for storage vessels with emissions above a certain level 

beyond the 6 tpy threshold as existing title V major source permitting thresholds, and even lower 

state air permitting thresholds, have the effect of limiting emissions from storage vessels that 

otherwise would be “higher emitting.” 

Response: In the proposed rule, the EPA solicited comment on the number of storage 

vessels at different throughput levels (or VOC emission levels) to further inform our 

consideration of controlling higher emitting storage vessels earlier than April 15, 2014. We thank 

the commenters for the information provided. However, no substantive data on the number of 

higher emitting storage vessels was provided, and we decided to take another approach. Based on 

our recent understanding of the supply of control devices and concerns related to how quickly 

the combustor industry can ramp up production, we decided to take a phased-in approach that 

requires the newer affected facilities (which would have higher emissions) to comply first. Since 

this approach would, we believe, effectively control the higher emitting storage vessels first, we 

no longer had need to estimate the number of higher emitting storage vessels.

2.8 Small Business Impacts

Comment: One commenter (4634) provides that the EPA indicates, on page 22137 of the 

proposal published in the April 12, 2013, issue of the Federal Register, there will be no 

significant compliance costs as a result of this proposed rule because "owners and operators of 

storage vessel affected facilities would install the same or similar control technologies as they 

would have installed to comply with the previously finalized standards." The commenter states 

that the EPA further indicates that it has certified that the proposed action will not have 

significant economic impact on a substantial number of small entities. After stating that it 

considered the economic impact of the proposed NSPS on small entities, the commenter states 

that the EPA certified that the proposed NSPS would not have a significant economic impact on 

a substantial number of small entities, based on the EPA's conclusion that many affected firms 

are expected to receive revenues from the additional natural gas and condensate recovery 

resulting from certain emissions controls, particularly those for completion-related activities and 

vapor recovery units on storage vessels. According to the commenter, most crude oil producers, 

particularly operators of stripper crude oil wells, will not realize this benefit. The commenter 

provides that, as they commented in their letter dated October 25, 2011, to the EPA's proposed 

rules published in the August 23, 2011, issue of the Federal Register (76 FR 52738), they 

believe the EPA greatly underestimated the negative impact of compliance with the rule on small 

businesses. The commenter states that their review indicates that the EPA did not respond to this 

specific comment submitted to the EPA in their 2011 comment letter and they request that the

EPA respond to their comment concerning impacts to small businesses.

Response: The comments related to the impacts of the 2012 NSPS were addressed in that 

rulemaking. See Response to Public Comments on Proposed Rule, August 23, 2011 (76 FR 
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52738), which is available in the docket. However, although the number of storage vessel 

affected facilities is greater than initially estimated in the 2012 NSPS, we believe that changes 

we are finalizing in this rule, such as streamlined compliance monitoring, will provide relief to 

industry, including relief to small business entities and operators of stripper crude oil wells. As 

noted in section V.C of the preamble to the final amendments, the Group 1 compliance date we 

have adopted addresses our concern about how a potential shortage of trained personnel may 

impact small businesses as comments we received indicate that larger owners and operators may 

be able to garner the majority of the available installation personnel due to their greater 

resources. This may result in a situation where small owners and operators may be placed in a 

competitive disadvantage in obtaining installation personnel. If such a situation should occur, the 

smaller owners and operators may be forced to shut down wells or delay drilling new wells until 

installation personnel are made available. In light of concerns such as these, we adopted the 

phased-in approach described in the preamble to the final amendments, which would enable 

sources more time to plan and acquire the necessary equipment and labor needed. 

Comment: One commenter (4634) reports that the EPA does not consider impacts of the 

proposed regulations on stripper wells. According to the commenter, in order to lessen the 

burden on these operators (of stripper wells) and maintain production of the state's valuable 

resources, they strongly urge the EPA to provide a pathway by which such wells could exit the 

requirements of the rules. According to the commenter, the proposed regulations for storage 

vessels for crude oil and produced water associated with crude oil do not consider impacts of the 

proposed regulations on stripper wells. The commenter provides that a "stripper well" is a well 

that produces crude oil at very low rates. The commenter reports that the Interstate Oil & Gas 

Compact Commission defines a stripper oil well as one that produces less than 10 barrels of oil 

per day. 

The commenter (4634) reports that stripper oil wells represent a significant portion of the 

total number of oil wells. The commenter states that the United States Department of Energy 

estimates that in 2009 there were over 286,000 of these wells in the United States and that 

together they produced over 217 million barrels of oil (see 

http://www.eia.gov/pub/oilgas/petrosystemlustable.html (accessed May 22, 2013). The 

commenter refers to a table included as an attachment to their comments dated October 25, 2011, 

entitled "Texas 2009 Distribution of Wells by Production Rate Bracket," which indicates that 

almost 80 percent of all Texas oil wells produced less than or equal to 10 barrels of crude oil per 

day in 2009. According to the commenter, the production from those wells accounted for 30 

percent of Texas' annual oil production. The commenter reports that, although the average per 

well production was 2.4 barrels of oil per day, many of these stripper wells are connected to 

lease tank batteries that include storage vessels, such as crude oil vessels, produced water 

vessels, and treating/separation vessels. The commenter states that a majority of these stripper 

wells are owned and operated by small businesses that are families, not "firms." According to the 

commenter, the only business in which many of these small businesses engage in Texas is the 

operation of stripper oil wells. However, the commenter provides that in the EPA’s analysis of 

economic impact, the EPA included this group of small entities with all small businesses 

engaged in the activities encompassed by the proposed rules, thereby diluting the impact on 

stripper oil well operators. Therefore, the commenter believes that the economic impact analysis 

fails to adequately demonstrate the full impact on this category of small businesses in Texas and 
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many other states with a high percentage of stripper oil wells and a high percentage of family 

operations. 

The commenter (4634) provides that while the EPA proposes to adopt a threshold below 

which storage vessels would not be subject to the requirements of the proposed rule, operators of 

stripper wells still would be required to expend their limited funds to make such a determination. 

The commenter requests that, in order to lessen the economic burden on these operators and 

maintain production of the State's valuable natural resources, the EPA develop a tool, such as a 

reference table, by which these stripper well operators can more economically determine whether 

or not they are above or below the 6 tpy threshold, using readily available information, such as 

throughput volumes, type of hydrocarbon, and API gravity. In addition, the commenter states 

that, because the proposed regulations are structured such that, once regulated always regulated, 

a crude oil well that becomes a stripper well at some point in the future, still would be required to 

monitor, verify, and report emissions as required by the proposed regulations, increasing the risk 

of valuable state resources being unproduced. Again, in order to lessen the burden on these 

operators and maintain production of the state's valuable resources, the commenter urges the 

EPA to provide a pathway by which such wells could exit the requirements of the rules.

Response: We included stripper wells in our analysis of the number of potentially 

affected storage vessels supporting this action. Regarding the commenter’s inclusion of Interstate 

Oil & Gas Compact Commission’s definition of a stripper oil well as one that produces less than 

10 barrels of oil per day, we have determined that the storage vessel VOC emissions for such a 

well would be approximately 2 tpy, which is below the 6 tpy VOC emissions threshold. 

Additionally, only stripper wells constructed on or after August 23, 2011, may be subject to the 

rule and, as shown, it is unlikely that many will be subject to the rule because of the low 

production rates of these wells. Additionally, for affected storage vessels, once operators have 

demonstrated that the uncontrolled actual VOC emissions have remained less than 4 tpy for 12 

consecutive months, the operator may maintain the uncontrolled actual VOC emissions from the 

storage vessel affected facility at less than 4 tpy, resulting in reduced burden.

As stated in the preamble to the final amendments, we expect that owners and operators 

of storage vessel affected facilities would install the same or similar control technologies to meet 

the standards finalized in this action, as they would have chosen to comply with the 2012 NSPS. 

Therefore, we do not anticipate that the final amendments will result in significant changes in 

costs, benefits or economic impacts compared to the requirements in the 2012 NSPS. As such, 

we have certified that this action will not have a significant economic impact on a substantial 

number of small entities.

Regarding the development of a tool to assist stripper well operators to more 

economically determine whether or not they are above or below the 6 tpy threshold, the EPA 

does not limit the methodologies operators can use to determine their emissions. There are 

several tools currently available to owners and operators (see section 2.1.2.6) and it is up to each 

owner or operator to choose the most cost-effective tool for their operation. Therefore, we 

believe that operators can determine their emissions with relatively low effort, even for operators 

of stripper wells. We do not believe it is necessary or desirable for the EPA to create an 

additional tool.