Vol. 78 Monday, 

No. 184 September 23, 2013 

Part III 

Environmental Protection Agency 

40 CFR Part 60 

Oil and Natural Gas Sector: Reconsideration of Certain Provisions of New 

Source Performance Standards; Final Rule 


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58416 Federal Register / Vol. 78, No. 184 / Monday, September 23, 2013 / Rules and Regulations 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Part 60 

[EPA–HQ–OAR–2010–0505, FRL–9844–4] 

RIN 2060–AR75 

Oil and Natural Gas Sector: 

Reconsideration of Certain Provisions 

of New Source Performance Standards 

AGENCY: Environmental Protection 

Agency (EPA). 

ACTION: Final Amendments. 

SUMMARY: This action finalizes the 

amendments to new source performance 

standards for the oil and natural gas 

sector. The Administrator received 

petitions for reconsideration of certain 

aspects of the August 12, 2012, final 

standards. These amendments are a 

result of reconsideration of certain 

issues raised by petitioners related to 

implementation of storage vessel 

provisions. The final amendments 

provide clarity of notification and 

compliance dates, ensure control of all 

storage vessel affected facilities and 

update key definitions. This action also 

corrects technical errors that were 

inadvertently included in the final 

standards. 

DATES: This final rule is effective on 

September 23, 2013. 

ADDRESSES: The EPA has established a 

docket for this action under Docket ID 

No. EPA–HQ–OAR–2010–0505. All 

documents in the docket are listed on 

the http://www.regulations.gov Web 

site. Although listed in the index, some 

information is not publicly available, 

e.g., confidential business information 

or other information whose disclosure is 

restricted by statute. Certain other 

material, such as copyrighted material, 

is not placed on the Internet and will be 

publicly available only in hard copy 

form. Publicly available docket 

materials are available either 

electronically through http://

www.regulations.gov or in hard copy at 

the EPA’s Docket Center, Public Reading 

Room, EPA West Building, Room 

Number 3334, 1301 Constitution 

Avenue NW., Washington, DC 20004. 

The Public Reading Room is open from 

8:30 a.m. to 4:30 p.m., Monday through 

Friday, excluding legal holidays. The 

telephone number for the Public 

Reading Room is (202) 566–1744, and 

the telephone number for the Air Docket 

is (202) 566–1742. 

FOR FURTHER INFORMATION CONTACT: Mr. 

Bruce Moore, Sector Policies and 

Programs Division (E143–05), Office of 

Air Quality Planning and Standards, 

Environmental Protection Agency, 

Research Triangle Park, North Carolina 

27711, telephone number: (919) 541– 

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

email address: moore.bruce@epa.gov. 

SUPPLEMENTARY INFORMATION: 

Organization of This Document. The 

information presented in this preamble 

is organized as follows: 

I. Preamble Acronyms and Abbreviations 

II. General Information 

A. Executive Summary 

B. Does this reconsideration notice apply 

to me? 

C. How do I obtain a copy of this document 

and other related information? 

D. Judicial Review 

III. Summary of Final Amendments 

A. Initial Notification and Compliance 

Dates 

B. Group 1 and Group 2 Storage Vessel 

Emission Standards Applicability 

C. Group 1 Storage Vessel Affected Facility 

Control Requirements 

D. Alternative 4-tpy Uncontrolled Actual 

VOC Emission Rate 

E. Definition of Storage Vessel 

F. Definition of Storage Vessel Affected 

Facility 

G. Streamlined Compliance Monitoring 

Provisions 

H. Combustion Control Device 

Manufacturer Test Protocol 

I. Annual Report and Compliance 

Certification 

IV. Summary of Significant Changes Since 

Proposal 

A. Group 1 Storage Vessel Affected Facility 

Control Requirements and Applicability 

B. Applicability Dates and Compliance 

Dates 

C. Definition of Storage Vessel Affected 

Facility 

V. Summary of Significant Comments and 

Responses 

A. Major Comments Concerning 

Applicability Dates and Compliance 

Dates 

B. Major Comments Concerning the Storage 

Vessel Affected Facility Definition 

C. Major Comments Concerning Storage 

Vessel Control Requirements 

D. Major Comments Concerning Ongoing 

Compliance Requirements 

E. Major Comments Concerning Design 

Requirements 

F. Major Comments Concerning Impacts 

VI. Technical Corrections and Clarifications 

VII. Impacts of These Final Amendments 

A. What are the air impacts? 

B. What are the energy impacts? 

C. What are the compliance costs? 

D. What are the economic and employment 

impacts? 

E. What are the benefits of the proposed 

standards? 

VIII. Statutory and Executive Order Reviews 

A. Executive Order 12866: Regulatory 

Planning and Review and Executive 

Order 13563: Improving Regulation and 

Regulatory Review 

B. Paperwork Reduction Act 

C. Regulatory Flexibility Act 

D. Unfunded Mandates Reform Act 

E. Executive Order 13132: Federalism 

F. Executive Order 13175: Consultation 

and Coordination With Indian Tribal 

Governments 

G. Executive Order 13045: Protection of 

Children From Environmental Health 

and Safety Risks 

H. Executive Order 13211: Actions 

Concerning Regulations That 

Significantly Affect Energy Supply, 

Distribution, or Use 

I. National Technology Transfer and 

Advancement Act 

J. Executive Order 12898: Federal Actions 

To Address Environmental Justice in 

Minority Populations and Low-Income 

Populations 

K. Congressional Review Act 

I. Preamble Acronyms and 

Abbreviations 

Several acronyms and terms are 

included in this preamble. While this 

may not be an exhaustive list, to ease 

the reading of this preamble and for 

reference purposes, the following terms 

and acronyms are defined here: 

API American Petroleum Institute 

AVO Auditory, Visual and Olfactory 

BOE Barrels of Oil Equivalent 

bbl Barrel 

bpd Barrels Per Day 

BID Background Information Document 

BSER Best System of Emissions Reduction 

CAA Clean Air Act 

CFR Code of Federal Regulations 

CPMS Continuous Parametric Monitoring 

Systems 

EIA Energy Information Administration 

EPA Environmental Protection Agency 

GOR Gas to Oil Ratio 

HAP Hazardous Air Pollutant 

HPDI HPDI, LLC 

Mcf Thousand Cubic Feet 

NTTAA National Technology Transfer and 

Advancement Act of 1995 

NEI National Emissions Inventory 

NEMS National Energy Modeling System 

NESHAP National Emissions Standards for 

Hazardous Air Pollutants 

NSPS New Source Performance Standards 

OAQPS Office of Air Quality Planning and 

Standards 

OMB Office of Management and Budget 

PRA Paperwork Reduction Act 

PTE Potential to Emit 

RFA Regulatory Flexibility Act 

SISNOSE Significant Economic Impact on a 

Substantial Number of Small Entities 

tpy Tons per Year 

TTN Technology Transfer Network 

UMRA Unfunded Mandates Reform Act 

VCS Voluntary Consensus Standards 

VOC Volatile Organic Compounds 

VRU Vapor Recovery Unit 

II. General Information 

A. Executive Summary 

1. Purpose of This Regulatory Action 

The purpose of this action is to 

finalize amendments to the 40 CFR part 

60, subpart OOOO, Standards of 

Performance for Crude Oil and Natural 

Gas Production, Transmission and 


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1The 2012 NSPS proposal was published on 

August 23, 2011, and the proposed rule for this 

action was published on April 12, 2013. 

Distribution final rule promulgated 

under section 111(b) of the Clean Air 

Act (CAA), which was published on 

August 16, 2012 [77 FR 49490]. The 

amendments being finalized were 

proposed on April 12, 2012 [78 FR 

22126]. Specifically, this final rule 

action amends aspects of the 2012 new 

source performance standards (2012 

NSPS) to address select issues raised by 

different stakeholders through several 

administrative petitions for 

reconsideration of the 2012 NSPS. The 

select issues being reconsidered and 

addressed by this action are related 

primarily to implementation of the 

storage vessel provisions. 

2. Summary of Major Amendments to 

the NSPS 

This rule finalizes a number of 

aspects of the proposal but, after 

consideration of public comments 

received, it also makes certain changes, 

as described in this section. 

a. Initial Notification and Compliance 

Dates 

For Group 1 storage vessels (i.e., those 

the construction, reconstruction or 

modification of which began after 

August 23, 2011, and on or before April 

12, 2013),1 the final amendments 

require that owners/operators estimate 

emissions from the storage vessels to 

determine affected facility no later than 

October 15, 2013, and a notification be 

submitted with the facilities’ annual 

report due by January 15, 2014, to 

inform regulatory agencies of the 

existence and location of the Group 1 

storage vessel affected facilities. The 

final amendments retain the 

requirement that all Group 1 storage 

vessel affected facilities comply with 

the emission standards but, in a change 

from proposal, extend the compliance 

deadline to April 15, 2015. Since all 

Group 1 affected facilities are required 

to meet the emission standards, the final 

amendments do not require Group 1 

storage vessel affected facilities to track 

emission increase events, as we had 

proposed. 

For Group 2 storage vessel affected 

facilities (i.e., those the construction, 

reconstruction or modification of which 

began after April 12, 2013), the final 

amendments extend the compliance 

date to April 15, 2014 (or 60 days after 

startup, whichever is later), for 

implementing the emission standards, 

as proposed. 

In response to comments regarding 

the confusion about when the affected 

facility status for Group 1 storage 

vessels should be determined, we have 

also made clarifying changes to 

§ 60.5365(e) in the final amendments 

that clearly specify October 15, 2013, as 

the deadline for calculating potential 

volatile organic compound (VOC) 

emissions from Group 1 storage vessels 

for determining the affected facility 

status. 

b. Group 1 and Group 2 Storage Vessel 

Emission Standards Applicability 

We have amended § 60.5395 to more 

clearly specify that the requirements of 

the NSPS apply to Group 1 and Group 

2 storage vessel affected facilities (i.e., 

those with potential to emit (PTE) 6 or 

more tpy of VOC, as determined by the 

methods and dates specified in this final 

rule). We amended this language in 

response to several comments 

expressing confusion about whether the 

requirements applied to all Group 1 

storage vessels or just those with VOC 

emissions of 6 tpy or greater (i.e., 

affected facilities). 

c. Group 1 Storage Vessel Affected 

Facility Emission Standards and 

Compliance Dates 

A key feature of this action is that the 

final amendments require control of all 

storage vessel affected facilities 

constructed since the August 23, 2011, 

proposal date of the 2012 NSPS. This 

decision, as summarized in this section 

and discussed fully in sections IV.A and 

V.C of this preamble, was based on new 

information we received that indicates 

that the projected control device supply 

appears to be greater than we originally 

estimated. 

In the preamble to the proposed 

amendments, based on the information 

then available to the EPA, we developed 

an estimate of the supply of the type of 

combustors likely to be used by owners 

and operators to comply with the 

control requirements and concluded 

that control supply would not catch up 

with its demand under this rule until 

2016. To avoid delaying control until 

such time, we proposed that Group 1 

affected facilities notify the EPA of their 

presence and location by October 15, 

2013, but need not comply with the 95 

percent reduction requirement unless 

they experience an emission increase 

event. However, new information we 

received since proposal indicates that 

the combustor suppliers have the 

manufacturing capacity to meet the 

demand posed both by this regulation 

and a variety of state and local 

regulations that require the installation 

of control devices. Therefore, in the 

final amendments, we are not changing 

the requirement of the 2012 NSPS that 

Group 1 storage vessel affected facilities 

comply with the emission standard 

requirements. However, we have 

extended the current compliance 

deadline. For the reasons discussed in 

detail in section IV.A, these final 

amendments require that Group 2 

affected facilities comply with the 

emission standards by April 15, 2014, as 

we proposed, and that Group 1 affected 

facilities comply by April 15, 2015. 

d. Alternative 4-tpy Uncontrolled 

Actual VOC Emission Rate 

To help alleviate the control supply 

shortage believed to exist at the time, we 

had proposed that affected facilities 

meet the 95% reduction requirement or 

an uncontrolled actual VOC emission 

rate of less than 4 tpy, which would 

allow control devices to be removed 

from storage vessel affected sources 

below that emission rate and relocated 

to those that have just come on line and 

have PTE of 6 tpy VOC or more. As 

mentioned above, new information we 

received since proposal indicate that the 

combustor suppliers have the 

manufacturing capacity to meet the 

demand posed by this regulation, which 

in turn would suggest that a supply 

buffer may no longer be necessary. 

However, for the reasons provided in 

section V.C of this preamble, we are 

finalizing the amendment to the storage 

vessel emission standards as proposed 

due to questionable cost effectiveness, 

the secondary environmental impact 

and the energy impacts from the 

continued operation of the combustion 

control device at an inlet stream 

concentration of less than about 4 tpy. 

We were aware but had not highlighted 

these concerns in the proposed 

amendment because the perceived 

supply problem alone necessitated 

proposing the amendment. The 

resolution of the supply issue, however, 

shifts our focus back to these concerns. 

As explained in more detail in section 

V.C of this preamble, in light of the 

questionable cost effectiveness of 

additional control, the secondary 

environmental impact and the energy 

impacts we conclude that the best 

system of emissions reduction (BSER) 

for reducing VOC emissions from 

storage vessel affected facilities is not 

represented by continued control when 

their sustained uncontrolled emission 

rates fall below 4 tpy. We are therefore 

finalizing the amendment as proposed. 

Under the final amendments, 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 determinations of actual 


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emission rate for the 12 consecutive 

months immediately preceding the 

demonstration, that the storage vessel 

affected facility uncontrolled actual 

VOC emissions for each month during 

that 12-month period have been below 

4 tpy. The final amendments require 

that the owner or operator re-evaluate 

the uncontrolled actual VOC emissions 

on a monthly basis. If the results of the 

monthly determination show that the 

uncontrolled actual VOC emission rate 

is 4 tpy or more, the owner or operator 

would have 30 days to meet the 95 

percent control requirement. We discuss 

this further in section V.C of this 

preamble. 

e. Definition of Storage Vessel Affected 

Facility 

We have finalized the proposed 

amendments to the definition of 

‘‘storage vessel affected facility’’ in the 

final rule (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; and (3) to 

clarify that PTE does not include any 

vapor recovered and routed to a process. 

f. Streamlined Compliance Monitoring 

Provisions 

We received several comments 

regarding the streamlined compliance 

monitoring provisions; our review of the 

comments did not result in significant 

changes since proposal. These 

compliance monitoring provisions 

include inspections of covers, closedvent systems and control devices, 

performed at least monthly. We believe 

that these measures are sufficient to 

ensure that storage vessel affected 

facilities that have installed controls 

meet the 95 percent VOC reduction 

standard. Although the more stringent 

compliance monitoring provisions in 

the 2012 NSPS may provide better 

assurance of compliance, there are 

significant issues regarding their 

implementation, which have been 

raised in several administrative 

reconsideration petitions. We continue 

to evaluate the reconsideration issues 

related to compliance monitoring and 

intend to complete our reconsideration 

by the end of 2014. 

3. Cost and Benefits 

Owners and operators of storage 

vessel affected facilities are expected to 

install and operate the same or similar 

air pollution control technologies under 

these final amendments as would have 

been necessary to meet the previously 

finalized standards for the oil and 

natural gas sector under the 2012 NSPS. 

We project that these amendments will 

not result in a significant change in 

costs and or benefits compared to the 

2012 NSPS. The final amendments 

continue to require that all storage 

vessel affected facilities comply with 

the emission standards. Although the 

final amendments may not achieve the 

same level of emission reductions as the 

2012 NSPS, it was necessary to revise 

the standards due to the limitations of 

the 2012 rule. The revisions provided in 

the final amendments were needed for 

the reasons explained in this preamble, 

and we believe the rule provides 

significant benefits. We anticipate that, 

if there are any changes in costs for 

these units, such changes would likely 

be small relative to both the overall 

costs of the individual projects and the 

overall costs and benefits of the final 

rule. 

B. Does this reconsideration notice 

apply to me? 

Categories and entities potentially 

affected by today’s notice include: 

TABLE 1—INDUSTRIAL SOURCE CATEGORIES AFFECTED BY THIS ACTION

Category NAICS code 1 Examples of regulated entities 

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

211112 Natural Gas Liquid Extraction. 

221210 Natural Gas Distribution. 

486110 Pipeline Distribution of Crude Oil. 

486210 Pipeline Transportation of Natural Gas. 

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

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

1 North American Industry Classification System. 

This table is not intended to be 

exhaustive, but rather is meant to 

provide a guide for readers regarding 

entities likely to be affected by this 

action. If you have any questions 

regarding the applicability of this action 

to a particular entity, consult either the 

air permitting authority for the entity or 

your EPA regional representative as 

listed in 40 CFR 60.4 or 40 CFR 63.13 

(General Provisions). 

C. How do I obtain a copy of this 

document and other related 

information? 

In addition to being available in the 

docket, electronic copies of these 

proposed rules will be available on the 

Worldwide Web through the 

Technology Transfer Network (TTN). 

Following signature, a copy of each 

proposed rule will be posted on the 

TTN’s policy and guidance page for 

newly proposed or promulgated rules at 

the following address: http://

www.epa.gov/ttn/oarpg/. The TTN 

provides information and technology 

exchange in various areas of air 

pollution control. 

D. Judicial Review 

Under section 307(b)(1) of the CAA, 

judicial review of this final rule is 

available only by filing a petition for 

review in the U.S. Court of Appeals for 

the District of Columbia Circuit by 

November 22, 2013. Under section 

307(d)(7)(B) of the CAA, only an 

objection to this final rule that was 

raised with reasonable specificity 

during the period for public comment 

can be raised during judicial review. 

Moreover, under section 307(b)(2) of the 

CAA, the requirements established by 

this final rule may not be challenged 

separately in any civil or criminal 

proceedings brought by the EPA to 

enforce these requirements. Section 

307(d)(7)(B) of the CAA further provides 

that ‘‘[o]nly an objection to a rule or 

procedure which was raised with 

reasonable specificity during the period 

for public comment (including any 

public hearing) may be raised during 

judicial review.’’ This section also 

provides a mechanism for us to convene 

a proceeding for reconsideration, ‘‘[i]f 

the person raising an objection can 

demonstrate to the EPA that it was 


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impracticable to raise such objection 

within [the period for public comment] 

or if the grounds for such objection 

arose after the period for public 

comment (but within the time specified 

for judicial review) and if such objection 

is of central relevance to the outcome of 

the rule.’’ Any person seeking to make 

such a demonstration to us should 

submit a Petition for Reconsideration to 

the Office of the Administrator, U.S. 

EPA, Room 3000, Ariel Rios Building, 

1200 Pennsylvania Ave. NW., 

Washington, DC 20460, with a copy to 

both the person(s) listed in the 

preceding FOR FURTHER INFORMATION

CONTACT section, and the Associate 

General Counsel for the Air and 

Radiation Law Office, Office of General 

Counsel (Mail Code 2344A), U.S. EPA, 

1200 Pennsylvania Ave. NW., 

Washington, DC 20460. 

III. Summary of Final Amendments 

The final amendments include 

revisions to certain reconsidered aspects 

of the existing 2012 NSPS which 

primarily affect the implementation of 

the regulation of VOC emissions from 

storage vessels. A summary of the final 

amendments resulting from our 

reconsideration are provided in the 

following paragraphs. 

A. 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 

no later than April 15, 2014, (or 60 days 

after startup, whichever is later). 

The final amendments also make 

clarifying changes to § 60.5395 that 

clearly specify October 15, 2013, as the 

deadline for calculating potential VOC 

emissions from Group 1 storage vessels 

to determine affected facility status. 

B. Group 1 and Group 2 Storage Vessel 

Emission Standards 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). 

C. 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, 

and that Group 2 storage vessel affected 

facilities comply by April 15, 2014. 

D. Alterative 4-tpy Uncontrolled Actual 

VOC 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 reevaluate the uncontrolled actual VOC 

emissions on a monthly basis. If the 

results of the monthly determination 

show that the uncontrolled actual VOC 

emission rate is 4 tpy or more, the 

owner or operator would have 30 days 

to meet the 95 percent control 

requirement, unless the increase was 

associated with the fracturing or 

refracturing of a well feeding the storage 

vessel affected facility. In that case, 95 

percent control would be required as 

soon as liquids are routed from the 

fractured or refractured well to the 

storage vessel. We discuss this further in 

section V.C of this preamble. 

E. 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. 

F. 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 limit 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) clarify that ‘‘other 

mechanisms’’ (or non-federally 

enforceable mechanisms) must be 

legally and practically enforceable 

under federal, state, local or tribal 

authority; and (4) clarify that vapor from 

a storage vessel that is recovered and 

routed to a process is not to be counted 

in the PTE for purposes of determining 

affected facility status. 

We also 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 

a storage vessel’s return to service is 

associated with fracturing or 

refracturing of a well feeding the storage 

vessel, the storage vessel is subject to 

control requirements immediately upon 

returning to service. If, however, the 

storage vessel’s return to service is 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. 

G. 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. As mentioned above, 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. 

H. Combustion Control Device 

Manufacturer Test Protocol 

We have finalized amendments to the 

enclosed combustor 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). 

I. 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. 

IV. Summary of Significant Changes 

Since Proposal 

Section III summarized the 

amendments to the 2012 NSPS that the 


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EPA is finalizing in this rule. This 

section will discuss the key changes the 

EPA has made since the April 12, 2013, 

proposal. These changes are the result of 

the EPA’s consideration of the many 

substantive and thoughtful comments 

submitted on the proposal and other 

information received since proposal. We 

believe that the changes we have made 

sufficiently address concerns expressed 

by commenters and improve the clarity 

of the rule while improving or 

preserving public health and 

environmental protection required 

under the CAA. 

A. Group 1 Storage Vessel Affected 

Facility Control Requirements and 

Applicability 

We received comments requesting 

clarification regarding Group 1 storage 

vessel affected facility control 

requirement applicability. We also 

received comments on our estimate of 

the supply of combustors used to 

comply with the control requirements 

and our use of this estimate to 

determine the requirements for Group 1 

storage vessel affected facilities. 

To the extent that there was confusion 

regarding the applicability of Group 1 

storage vessel affected facility control 

requirements, we agree that there is a 

need for more clarity in the final 

amendments. To accomplish this, we 

have included amendments to 

§ 60.5395(b) that make it clear that these 

requirements apply only to Group 1 

storage vessel affected facilities 

(emphasis added) (i.e., those that have 

the PTE of 6 tpy VOC or more, as 

determined by the dates specified in the 

rule, as amended), not all Group 1 

storage vessels. Refer to section V.A of 

this preamble for further discussion of 

comments and responses pertaining to 

these changes. 

In the proposed amendments, based 

on the information then available to the 

EPA, we concluded that control supply 

would not catch up with its demand 

under this rule until 2016. To avoid 

delaying control until such time, we 

proposed that Group 1 affected facilities 

notify the EPA of their presence and 

location by October 15, 2013, but need 

not comply with the 95 percent 

reduction requirement unless they 

experience an emission increase event. 

Information we received since proposal 

indicate that the combustor suppliers 

have the manufacturing capacity to meet 

the demand posed both by this 

regulation and a variety of state and 

local regulations that require the 

installation of control devices even 

when accounting for the need to cover 

Group 1 well in advance of the 

projected 2016 date. Therefore, in the 

final amendments we did not finalize 

the proposed requirement for Group 1 

storage vessel affected facilities to be 

controlled only if there is an emission 

increase event. However, as explained 

in more detail below, we have concerns 

regarding the projections of potential 

combustor supply; the pace at which the 

combustor manufacturing industry can 

ramp up production and provide the 

necessary supply in the short-term; and 

the availability of trained personnel to 

install these devices on all affected 

facilities that will have already come on 

line by the current compliance date of 

October 15, 2013, as well as the 

additional approximately 1,100 new 

affected facilities per month that may 

need control. Consideration of these 

factors leads us to conclude that an 

adjustment to the compliance schedule 

is warranted. 

First, we note that there is a great 

variability in the projections of potential 

combustor supply, with one supplier’s 

projection greatly exceeding the other 

suppliers’ projections. Our revised 

conclusion regarding supply of control 

devices is largely based on this one 

supplier’s manufacturing capacity, 

which, if changed, could potentially 

affect sources’ ability to acquire and 

install control by the current 

compliance deadline (i.e., October 15, 

2013 or 60 days after startup, whichever 

is later). In light of the above, additional 

time is needed beyond October 15, 

2013, for compliance with the 95 

percent reduction requirement. 

Secondly, we share the concern raised 

by several commenters that, due to the 

large number of storage vessel affected 

facilities, some may not be able to 

secure the necessary trained personnel 

to install control devices by the current 

compliance deadline, especially in the 

near term. Under the 2012 NSPS, 

installation of controls would be 

required by the current compliance date 

of October 15, 2013, for over 20,000 

affected facilities that we estimate will 

have already come on line since the 

August 23, 2011, proposal date of the 

2012 NSPS, as well as the additional 

approximately 1,100 new affected 

facilities per month that will need to 

install control 60 days after start-up. 

Lastly, while the overall supply of 

combustors appears to be adequate, we 

have concerns about how quickly the 

combustor manufacturing industry can 

ramp up production and provide the 

necessary supply in the short-term. We 

are doubtful that, even at full current 

capacity, there would be sufficient 

control devices to meet the October 15, 

2013, compliance date. For the reasons 

stated above, we decided to take a 

phase-in compliance approach that 

requires the newer affected facilities 

(which would have higher emissions) to 

comply first. Accordingly, the final 

amendments require that Group 2 

affected facilities comply with the 

emission standards by April 15, 2014, as 

we proposed, and that Group 1 affected 

facilities comply by April 15, 2015. 

Refer to section V.C of this preamble 

for further discussion regarding these 

changes. 

In addition, we had proposed a list of 

examples of ‘‘events’’ that would trigger 

control requirements for Group 1 storage 

vessel affected facilities. As noted, all 

Group 1 storage vessel affected facilities 

must meet the control requirements by 

April 15, 2015. Therefore, we no longer 

need to look to events that may be 

presumed to increase emissions to 

determine which Group 1 storage vessel 

affected facilities are subject to control 

requirements. All proposed provisions 

related to tracking events have been 

removed from the final amendments, 

thereby simplifying the rule and 

avoiding additional burden and 

potential confusion. 

Refer to section V.A of this preamble 

for further discussion regarding these 

changes. 

B. Applicability Dates and Compliance 

Dates 

As discussed in section IV.A of this 

preamble, the EPA previously 

concluded that there will be an 

insufficient supply of combustion 

control devices for all storage vessel 

affected facilities until 2016, based on 

information available at proposal. To 

avoid postponing control for all storage 

vessels affected facilities until 2016, we 

proposed alternative measures for 

Group 1 and Group 2 storage vessel 

affected facilities. For Group 1 storage 

vessel affected facilities, we proposed to 

require initial notification by October 

15, 2013, to inform regulatory agencies 

of the existence and location of these 

storage vessels. We also proposed that 

Group 1 storage vessel affected facilities 

that undergo an event after April 12, 

2013, that could reasonably be expected 

to lead to an increase in VOC PTE 

would be subject to control 

requirements. For Group 2 storage 

vessel affected facilities, we proposed 

April 15, 2014, as the compliance date 

for implementing control requirements. 

In response to comments concerning 

Group 1 storage vessel control 

requirement applicability and 

compliance being tied to the ‘‘events’’ 

listed in § 60.5395(b)(2) and unclear 

notification and compliance dates for 

both Group 1 and Group 2 storage 

vessels, we have made changes to the 


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2Letter from Peter Tsirigotis to Matthew Todd, 

American Petroleum Institute. September 28, 2012. 

Docket Item No. EPA–HQ–OAR–2010–0505–4595. 

final amendments. For Group 1 storage 

vessels, we are requiring that the owner 

or operator determine whether the 

storage vessel is an affected facility no 

later than October 15, 2013. In the 

proposed amendments, owners or 

operators of Group 1 storage vessel 

affected facilities had to submit an 

initial notification of these storage 

vessels by October 15, 2013, as well as 

an initial annual report by January 15, 

2014. In the final amendments, the 

initial notification may be combined 

with the initial annual report to reduce 

the burden of submitting two 

notifications within a 90-day period. As 

discussed previously in section IV.A of 

this preamble, the final amendments 

retain the requirement in the 2012 NSPS 

that all Group 1 storage vessel affected 

facilities comply with emission 

standards, and specify that compliance 

must be achieved by April 15, 2015. 

Therefore, we have removed all 

provisions related to tracking emission 

increase events from the final 

amendments. 

For Group 2 storage vessel affected 

facilities, we are finalizing April 15, 

2014, (or 60 days after startup, 

whichever is later) as the compliance 

date for implementing control 

requirements. 

Refer to section V.A of this preamble 

for further discussion of comments and 

responses regarding these provisions. 

C. Definition of Storage Vessel Affected 

Facility 

We proposed to amend the definition 

of ‘‘storage vessel affected facility’’ to 

specify that the storage vessel must have 

a VOC PTE equal to or greater than 6 tpy 

to be an affected facility and to clarify 

that the owner or operator can take into 

account any legally and practically 

enforceable emission limit in an 

operating permit, or by another 

mechanism under state, local or tribal 

authority, when determining the VOC 

PTE. The proposed amendment also 

clarified that a storage vessel affected 

facility whose potential VOC emissions 

decrease to less than the threshold of 6 

tpy would remain an affected facility. 

We proposed this amendment to clarify 

that a storage vessel complying with the 

proposed uncontrolled actual VOC 

emission rate would remain an affected 

facility. 

We received comments opposing the 

revisions to the definition of ‘‘storage 

vessel affected facility’’ to the extent 

that it may allow storage vessel 

operators to account for non-federally 

enforceable emission limitations that 

may change in the future and are not 

enforceable by the EPA in the 

determination of VOC PTE. Upon 

evaluation, we believe that the 

commenters’ concern arises from 

language we used in the proposed 

amendments to § 60.5365(e) to define 

the storage vessel affected facility which 

could have been confusing due to the 

phrase ‘‘other mechanisms.’’ Therefore, 

the final amendments clarify that ‘‘other 

mechanisms’’ must be legally and 

practically enforceable under federal, 

state, local or tribal authority. 

We received public comments that 

requested that the 6 tpy threshold for 

storage vessel affected facilities be 

determined after application of a vapor 

recovery unit (VRU) (i.e., taking the 

VRU vapor recovery into account in the 

emissions determination) for Group 1 

and Group 2 storage vessels. 

In September 2012, in response to 

issues brought to the EPA’s attention 

after the publication of the 2012 NSPS, 

we clarified that we do not consider 

VRUs that route recovered gas and 

vapor back to the process to be control 

devices, which is consistent with their 

treatment under 40 CFR part 63, subpart 

HH.2

As long as certain operating 

requirements are met, we believe it is 

appropriate to take into account 

reductions in VOC emissions that result 

from the recovery of vapor and routing 

of it to a VRU when determining the 

VOC PTE from a storage vessel for 

purposes of determining affected facility 

status. Routing of vapor through a VRU 

to a process reduces VOC emissions 

without secondary environmental 

impacts (e.g., NOX emissions) and is 

responsible conservation of our energy 

resources. However, it does not totally 

eliminate VOC emissions, since the 

VRU cannot operate 100 percent of the 

time due to maintenance and repair 

down time. Our September 28, 2012, 

letter clarified that the cover and closed 

vent requirements must be met when 

VRU is used to meet the 95 percent 

reduction emission standards. That said, 

we previously determined that routing 

of vapor through a cover and properly 

operated closed-vent system would 

recover all vapor routed to the system as 

long as the VRU is operating (i.e., 95 

percent of the vapor being routed to a 

line when operating for 95 percent of 

the time). In light of the above, as long 

as the VRU is operated consistent with 

those requirements, we believe that it is 

appropriate to exclude 95 percent of the 

vapor that would otherwise be emitted 

if not recovered when determining PTE 

for purposes of determining affected 

facility status. As a result of this 

comment, and based on our prior 

clarification of this issue, the final 

amendments to § 60.5365(e) include a 

provision that ‘‘any vapor from the 

storage vessel that is recovered and 

routed to a process through a VRU 

designed and operated as specified in 

this section is not required to be 

included in the determination of VOC 

potential to emit for purposes of 

determining affected facility status.’’ 

Further, we have added language to 

§ 60.5365(e) that provides for this 

adjustment of PTE as long as (1) the 

storage vessel is operated in compliance 

with cover requirements in § 60.5411(b) 

and the closed-vent system 

requirements in § 60.5411(c), which has 

a requirement that the CVS (including 

the VRU) is operational at least 95 

percent of the time, and that the 

operator maintain records 

demonstrating compliance with these 

requirements. 

We were concerned that, should a 

VRU be removed or operated 

inconsistent with the conditions that 

were the basis for the PTE reduction 

following the PTE determination for 

assessing whether the storage vessel is 

an affected facility, emissions could 

increase without the storage vessel 

being subject to control. To address that 

possibility, we have added language to 

§ 60.5365(e) such that, in the event of 

removal of apparatus that recovers and 

routes vapor to a process or operation 

that is inconsistent with the conditions 

for qualifying for the PTE reduction, the 

owner or operator would be required to 

determine PTE from the storage vessel 

within 30 days of such removal or 

operation. If the PTE is determined to be 

6 tpy VOC or more, then the storage 

vessel would be an affected facility and 

subject to the control requirements in 

§ 60.5395. We believe this approach will 

help avoid circumvention of the NSPS. 

We received comment that storage 

vessel affected facilities that are 

removed from service should cease to be 

considered affected facilities. Although, 

for the reasons presented in section V.C 

of this preamble, we disagree with the 

commenter and 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 following 

removal from service that the storage 

vessel has been taken out of service. If 

a storage vessel’s return to service is 

associated with the fracturing or 

refracturing of a well feeding the storage 

vessel, the storage vessel is subject to 

control requirements immediately upon 

returning to service. If, however, the 

storage vessel’s return to service is not 


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3We had proposed to require such notification by 

October 15, 2013, but, in response to comment, we 

have extended this deadline slightly to January 15, 

2014, to allow Group 1 affected facilities to submit 

the notification with their annual report instead of 

separately. 

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. 

V. Summary of Significant Comments 

and Responses 

This section summarizes the 

significant comments on our proposed 

amendments and our response thereto. 

A. Major Comments Concerning 

Applicability Dates and Compliance 

Dates 

1. When do Group 1 storage vessels 

have to determine emissions? 

a. Applicability Determination 

Comment: One commenter requested 

that the final rule specify the date upon 

which the determination of the potential 

VOC emission rate should occur for the 

purpose of determining whether the 

storage vessel is an affected facility. 

According to the commenter, since the 

EPA has stipulated controls to not be 

cost effective for storage vessels emitting 

less than 6 tpy of VOC, and emission 

rates for storage vessels in the oil 

production segment tend to decrease as 

production declines, the commenter 

believes the determination should be 

made near to the date upon which 

controls would be required in order to 

minimize the potential to install 

controls on storage vessels for which 

production decline has rendered 

controls no longer cost effective. The 

commenter stated that the proposed 

revisions would require a determination 

by October 15, 2013, of whether 

individual Group 1 storage vessels are 

affected facilities, and thus October 15, 

2013, would be an appropriate date 

upon which determination of the 

potential VOC emission rate should be 

based. According to the commenter, this 

would remain consistent with the 

requirement for determining the 

potential VOC emission rate for Group 

2 storage vessels by April 15, 2014 or 30 

days after startup, whichever comes 

later. 

The commenter appears to suggest 

that, like Group 2, Group 1 storage 

vessel affected facilities located in the 

natural gas processing and natural gas 

transmission and storage segments 

should also be required to determine 

potential VOC emissions as the trigger 

for installing control instead of tracking 

events but to do so by April 15, 2015 

(instead of April 15, 2014, proposed for 

Group 2). According to the commenter, 

control of the relatively low number of 

Group 1 storage vessel affected facilities 

in these segments could likely be 

accommodated by this date. 

Another commenter pointed out that 

the proposed reconsideration rule does 

not establish the date for a Group 1 

storage vessel to determine its potential 

emissions. The commenter also 

recommended that notifications are only 

required for tanks that exceed the 6 tpy 

threshold on October 15, 2013. 

Although the publication date of the 

proposed reconsideration rule was April 

12, 2013, the commenter contends that 

the EPA is not required to, nor should 

it, establish the emissions determination 

date for the source category of Group 1 

storage vessels on that date. First, given 

the rapidly declining emissions at 

storage vessels following initial 

fracturing, the commenter believes that 

the expected emissions reduction to be 

gained from Group 1 storage vessels is 

likely to be limited. The commenter also 

states that the proposal date of April 12, 

2013, has passed and operators may not 

be able to accurately back-calculate 

emissions from that date. Moreover, the 

commenter contends that emissions 

from many of these storage vessels will 

be below the 6 tpy affected source 

threshold as of October 2013. Given 

EPA’s proposed approach, where 

storage vessel affected facilities whose 

emissions drop below 6 tpy remain 

subject to the standard, the commenter 

believes that many Group 1 storage 

vessels will be unnecessarily captured 

in the source category and required to 

indefinitely track ‘‘events’’ and perhaps 

install control devices even if their 

emissions never again exceed 6 tpy. 

Response: The final amendments to 

§ 60.5365(e) specify that Group 1 storage 

vessel affected facilities must determine 

potential VOC emissions by October 15, 

2013, for purposes of determining 

whether it is an affected facility. For the 

reasons provided in the Response to 

Public Comments on the Proposed 

Amendments document available in the 

docket, the final amended § 60.5365(e) 

requires that Group 1 affected facilities 

submit a notification with the first 

annual report by January 15, 2014, to 

inform regulatory agencies of their 

existence and locations. Determining 

potential emissions and affected source 

status early on is not only necessary for 

Group 1 affected facilities to comply 

with the notification requirement by 

January 15, 2014,3 it will also provide 

Group 1 affected facilities advance 

notice and time to secure the necessary 

control devices and schedule the 

installation personnel to perform the 

installation by April 15, 2015. We reject 

suggestions by some commenters that 

emission determination be conducted 

closer to the deadline for installing 

control because such delay would 

frustrate the reason for extending the 

compliance date for Group 1 affected 

facilities in the final amendments (i.e., 

to provide advance notice and time to 

secure the necessary control devices and 

schedule the installation personnel to 

perform installation). Further, the 

commenters apparently assumed, 

though incorrectly, that the EPA has 

concluded that control is not cost 

effective when VOC emissions are 

below 6 tpy. No such determination has 

been made by the EPA or demonstrated 

by commenters. On the contrary, as 

discussed in section V.C of this 

preamble, we have determined that 

continuing control at uncontrolled 

emission rates of 4 tpy or above is costeffective. For the reasons stated above, 

the final amendments specify October 

15, 2013, as the deadline for 

determining the VOC PTE for Group 1 

storage vessels. If the VOC PTE of the 

Group 1 storage vessel is 6 tpy or greater 

on October 15, 2013 (or an earlier date 

if the owner or operator chooses to make 

the determination prior to October 15, 

2013), then the storage vessel is a Group 

1 storage vessel affected facility and is 

subject to the NSPS, which for Group 1 

includes the notification requirement by 

January 15, 2014 (i.e., the date by which 

the first annual report is due), and the 

control requirement by April 15, 2015. 

We are not finalizing the proposed 

requirement that Group 1 storage vessels 

track events that may increase the VOC 

PTE of the storage vessel (refer to 

section V.A of this preamble) and install 

control should there be such event; this 

proposed Group 1 storage vessel 

requirement is no longer necessary since 

the final amendments retain the control 

requirement for all Group 1 storage 

vessel affected facilities. 

One of the commenters expressed 

concern that Group 1 storage vessels 

will have to indefinitely track events for 

these storage vessels and install controls 

even if VOC emissions do not exceed 6 

tpy. The final amendments do not 

include requirements for owners and 

operators to track events for Group 1 

storage vessels, so this comment is now 

moot. 

The EPA does not believe it is 

necessary to defer the date at which 

Group 1 storage vessels located in the 

natural gas processing and natural gas 

transmission and storage segments are 

required to determine emissions. The 

commenter was suggesting an 


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alternative to tracking events for storage 

vessels in these segments, and the final 

amendments do not include the 

proposed event tracking provisions. 

b. Determination After an Event 

Comment: One commenter sought 

clarification that the requirement to reestimate emissions when there is an 

event that could reasonably be expected 

to increase emissions does not apply to 

non-affected facilities. Two commenters 

requested that the EPA specify whether 

the VOC emissions increase for Group 1 

storage vessels are to be based on 

potential or actual emissions. Another 

commenter suggested that the EPA 

clarify that the baseline emissions used 

to determine whether a Group 1 storage 

vessel experiences an emission increase 

is the level of emissions immediately 

prior to the event. 

Response: In the final amendments, 

we have removed the requirement to 

track events for Group 1 storage vessels 

(refer to section IV.A of this preamble). 

Therefore, these concerns are now moot. 

2. Which Group 1 storage vessels are 

subject to the initial notification 

requirements and when are the 

notifications due? 

Comment: One commenter states that 

the definitions for ‘‘Group 1 storage 

vessel’’ and ‘‘storage vessel’’ in 

§ 60.5430 do not contain the 6 tpy 

threshold required for a ‘‘storage vessel 

affected facility’’ under § 60.5365(e). 

The commenter believes that the EPA’s 

intent is to only be notified by October 

15, 2013, of Group 1 storage vessels that 

exceed 6 tpy and for operators to 

monitor these vessels for a subsequent 

‘‘event’’ because any storage vessel 

under 6 tpy is not an affected facility 

and therefore should not be subject to 

requirements under the rule. The 

commenter further states that in 

§ 60.5395, the heading which premises 

paragraph (b)(1) states, ‘‘You must 

comply with the standards in this 

section for each storage vessel affected 

facility.’’ The commenter asserts that, 

based on the definition of Group 1 

storage vessel and the order of 

requirements in the above provisions, 

this requirement could be 

misinterpreted to mean that all storage 

vessels between those specified Group 1 

dates must be reported, regardless of 

their PTE. 

Another commenter agreed, stating 

that none of the storage vessel 

definitions contains the 6 tpy threshold 

that is included in the § 60.5365(e) 

definition of ‘‘storage vessel affected 

facility.’’ The commenter added that, as 

proposed, § 60.5395(b) seems to include 

requirements for ‘‘Group 1 storage 

vessel affected facilities’’ but the 

notification and event requirements in 

proposed § 60.5395(b)(1) and (2) apply 

to ‘‘Group 1 storage vessels’’ rather than 

‘‘Group 1 storage vessel affected 

facilities.’’ The commenter believes that 

these requirements may be 

misinterpreted to apply to all storage 

vessels containing an accumulation of 

crude oil, condensate, intermediate 

hydrocarbon liquids, or produced water, 

regardless of whether their potential 

emissions meet the 6 tpy threshold. 

Response: As proposed, 

§ 60.5395(a)(1) states that owners or 

operators of Group 1 storage vessel 

affected facilities must comply with 

paragraph § 60.5395(b). The commenters 

are correct in their interpretation that 

the § 60.5395(b) requirements apply 

only to Group 1 storage vessel affected 

facilities (i.e., those Group 1 storage 

vessels with potential VOC emissions of 

6 tpy or more), not all Group 1 storage 

vessels. For clarity, we have moved the 

affected facility determination 

requirements from § 60.5395 to 

§ 60.5365(e) and have only requirements 

that apply to affected facilities now in 

§ 60.5395. The final amendments to 

§ 60.5365(e) clarify our intent. 

We also proposed in § 60.5395(b) that 

owners or operators submit the initial 

notification of Group 1 storage vessel 

affected facilities by October 15, 2013. 

As discussed in section V.A of this 

preamble, the final amendments require 

that owners or operators determine the 

VOC PTE of Group 1 storage vessels by 

October 15, 2013, and submit the initial 

notification for Group 1 storage vessel 

affected facilities, which may be 

included in the first annual report, by 

January 15, 2014. The provisions in the 

final amendments to allow the initial 

notification of Group 1 storage vessel 

affected facilities to be submitted with 

the initial annual report are discussed 

further in the Response to Public 

Comments on the Proposed 

Amendments, available in the docket. 

3. Group 1 Storage Vessels That Become 

Affected Facilities on or After April 12, 

2013 

Comment: One commenter requested 

that Group 1 storage vessels that 

experience a triggering event should 

follow the same schedule for Group 2 

storage vessel affected facilities to 

install controls (by April 15, 2014, or 60 

days after startup, whichever is later), 

except that there could be a hard 

deadline for Group 1 storage vessel 

affected facilities along a natural gas 

pipeline. The commenter pointed to the 

preamble of the proposed amendments 

(FR 78 22131) that indicates the EPA’s 

intent was for Group 1 storage vessel 

affected facilities, after a triggering 

event, to become subject to the same 

control requirements as those in Group 

2, and that these controls would be 

required no later than 60 days after the 

event, or April 15, 2014, whichever is 

later. According to the commenter, this 

intent was overlooked in the proposed 

rule amendments. 

Two commenters added that the final 

rule should specify a compliance period 

for Group 1 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 requested that the storage 

vessel should be required to achieve 

compliance within 60 days after the 

event. 

Another commenter contended that 

almost all events that would increase 

emissions at Group 1 storage vessels are 

planned or are of a foreseeable nature. 

The commenter believes that it is 

feasible for storage vessel operators to 

install and operate controls 

simultaneously with the occurrence of 

such planned events. The commenter 

added that because emissions from 

storage vessels are likely to be highest 

immediately after the events listed in 

60.5395(b)(2), it is also essential for 

protection of public health that controls 

be implemented as soon as possible. 

Response: As explained in section 

IV.A of this preamble, the emission 

standards remain applicable to all 

Group 1 affected facilities, as in the 

2012 NSPS. Accordingly, we are not 

finalizing the proposed requirement to 

track emission increase events and meet 

the control requirement as a result of 

such events for Group 1 storage vessels 

affected facilities. Thus, comments/

issues relative to compliance schedule 

for Group 1 storage vessel affected 

facilities that experience an event are 

now moot. 

B. Major Comments Concerning the 

Storage Vessel Affected Facility 

Definition 

Comment: In the reconsideration 

proposal, the EPA proposed to include 

a VOC emissions threshold of 6 tpy to 

determine, in part, which storage 

vessels are affected facilities. 

Additionally, the proposal allowed 

operators to take into account 

requirements under a legally and 

practically enforceable limit in an 

operating permit or by other 

mechanism. One commenter opposed 

this proposal to the extent that it allows 

storage vessel operators to account for 

non-federally enforceable emission 

limitations. According to the 


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commenter, the inclusion of nonfederally enforceable limitations leads 

to oversight concerns, and some storage 

vessels would avoid the NSPS under the 

proposed threshold. 

Additionally, the commenter 

maintains that the CAA does not allow 

‘‘synthetic minor’’ programs to 

determine applicability of its NSPS 

regulations. The commenter states that 

the term ‘‘potential to emit’’ is not found 

in section 111 of the CAA but is a 

concept from CAA programs governing 

expressly defined major sources. As a 

result, the commenter states that the 

CAA does not specify that a minor 

source program run by the states or 

other entities should be a means to 

avoid NSPS regulations. According to 

the commenter, allowing non-federally 

enforceable standards to exempt sources 

from NSPS is problematic because states 

vary widely in the letter, 

implementation, and enforcement of 

their synthetic minor programs. 

Response: In the preamble to the 

proposed amendments we stated that 

our intent was that ‘‘a source can take 

into account any legal and practically 

enforceable emissions limit under 

federal, state, local or tribal authority 

when determining the VOC emission 

rate for purposes of [the 6 tpy] 

threshold’’ (78 FR 22132). The language 

we used in the proposed amendments to 

§ 60.5365(e) to define the storage vessel 

affected facility allows the owner or 

operator to ‘‘tak[e] into account 

requirements under a legally and 

practically enforceable limit in an 

operating permit or by other 

mechanism.’’ We agree with the 

commenter in so much as the term 

‘‘other mechanism’’ may be construed to 

include non-federally enforceable 

mechanisms that may have 

questionable, if any, enforceability 

provisions. Therefore, the final 

amendments removed the term ‘‘other 

mechanisms’’ and revised the provision 

to allow the owner or operator to ‘‘tak[e] 

into account requirements under a 

legally and practically enforceable limit 

in an operating permit or requirement 

under a Federal, state, local or tribal 

authority.’’ We believe that the 

amendment clarifies only legally and 

practically enforceable limits can be 

considered when a source determines 

its PTE. The EPA’s ability to require 

Federal enforceability rather than just 

legal and practical enforceability has 

been an issue since the DC Circuit 

decision in National Mining Assn. v. 

EPA, 59 F.3d 1351 (D.C. Cir. 1995). As 

we have yet to address this remand/

vacatur, the agency does not feel at this 

time that it can dictate Federal 

enforceability in this context. 

Concerning the comments on our use 

of PTE as an applicability threshold, 

that was based on our BSER 

determination made in the 2012 NSPS 

taking into account the control’s cost 

effectiveness. Section 111(a)(1) of the 

CAA specifically identifies cost of 

achieving reduction as a factor to 

consider in setting NSPS standards. 

Nothing in section 111 of the CAA 

prohibits the EPA from using PTE to 

reflect our cost consideration in 

establishing applicability thresholds 

under section 111. Petitioner failed to 

explain how the fact that PTE is often 

used in connection with determining 

major source status in other provisions 

of the CAA bars its use for determining 

applicability status under section 111. 

C. Major Comments Concerning Storage 

Vessel Control Requirements 

1. CAA Section 111 Requirements 

Comments: According to one 

commenter, section 111 of the CAA is 

fundamentally a technology-forcing 

provision that can and should be used 

to spur aggressive deployment of 

emission control technologies. The 

commenter contends that standards are 

to be set stringently, in order to force the 

development of new technology. If the 

EPA must phase in controls, and can 

otherwise justify such an approach 

under section 111, the commenter 

believes the EPA must do so in as 

limited a way possible, ensuring it does 

not disrupt incentives which would 

otherwise expand pollution control 

development. 

The commenter added that the courts 

have clarified that EPA’s selection of 

BSER is only limited by cost when 

industry demonstrates an ‘‘inability to 

adjust itself in a healthy economic 

fashion to the end sought by the Act as 

represented by the standards 

prescribed.’’ Further, the commenter 

states that creating deferrals meant to 

track control equipment supply is not 

technology-forcing, but marketfollowing. According to the commenter, 

this ignores the role of standard-setting 

in incentivizing higher production of 

control equipment. If EPA cites 

availability of control devices in 

deferring or reducing the stringency of 

an NSPS, the commenter contends that 

the EPA must offer a strong 

demonstration that supply constraints 

render the standard unachievable or 

prohibitively expensive for the industry 

as a whole. 

Response: As explained in section 

IV.A of this preamble, the EPA proposed 

to phase in the control requirement for 

storage vessel affected facilities based 

on its belief at the time that there would 

not be enough control devices to meet 

the demand of all storage vessel affected 

facilities by the October 15, 2013, 

compliance date in the 2012 NSPS or 

any time in the near future. Although 

new information received since our 

proposal indicates that control supply 

may not be an issue, the EPA is phasing 

in the storage vessel control requirement 

in the final amendments for the reasons 

provided in section IV.A. The phase-in 

approach has never been based on cost, 

as the commenter suggests; rather, as 

indicated in section IV.A of this 

preamble and in the preamble to the 

April 12, 2013, reconsideration 

proposal, the phase-in approach is 

intended to avoid setting a control 

requirement that cannot be met due to 

limitations associated with installing 

control devices. We do not believe that 

a standard that ignores such limitations 

accurately represents the BSER for these 

affected facilities. 

2. Group 1 Requirements 

a. No Control of Group 1 Storage Vessels 

Comment: According to one 

commenter the proposal to exempt 

Group 1 storage vessels that do not 

experience increases in emissions rests 

on questionable projections of estimated 

current and future supply of control 

devices, number of storage vessels and 

decline of oil and natural gas well 

production. The commenter contends 

that the EPA cited only unidentified oil 

and gas industry sources for the asserted 

level of control device production and 

provided no justification for forecasted 

rate of production increase or the 

production rate plateau of 1,400 units 

per month. The commenter believes that 

it is as or more likely that industry 

would continue to expand control 

device production in response to the 

proposed standards, but the proposed 

delays would slow control manufacture 

by removing demand. According to the 

commenter, the EPA could remove its 

artificial ceiling for control manufacture 

and accelerate the compliance deadline 

for Group 2 storage vessels and require 

most or all Group 1 storage vessels to 

control emissions by mid-2015. The 

commenter contended that the EPA 

must disclose the information 

underlying these forecasts to allow the 

public to evaluate their reasonableness 

and offer comments. 

The commenter added that the 

assumption of one storage vessel per 

well overestimates the number of new 

storage vessels and is unjustified. The 

commenter provided examples of 

increased use of multi-well pads. 

According to the commenter, the EPA 

uses the fact that oil and gas wells 


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decline in production over time as 

justification for exempting Group 1 

storage vessels from control 

requirements. The commenter states 

that the EPA’s forecast of control 

equipment availability implies no 

reduction in the number of storage 

vessels requiring control. This is 

contrary to the justification given for 

exempting Group 1 storage vessels from 

control requirements. According to 

estimates of a decline in production, the 

commenter believes that some Group 1 

storage vessels could remain a 

significant source of emissions. 

The commenter also contended that 

the EPA’s projections indicate that the 

supply of existing control devices will 

be adequate to meet the combined 

demands of Group 1 and 2 storage 

vessels by 2016. It is not clear to the 

commenter what portion of the 

estimated 20,000 Group 1 storage 

vessels would ultimately be subject to 

control, so it is unclear whether subpart 

OOOO would ever apply to those Group 

1 storage vessels with high emissions. 

Even assuming that emissions from 

these Group 1 storage vessels generally 

continue to decline over their remaining 

lives, the commenter believes that 

allowing this group of storage vessels to 

be uncontrolled would result in a large 

amount of excess emissions relative to 

the current rule. Conservative estimates 

by the commenter indicate that the 

proposal to leave Group 1 storage 

vessels unregulated would allow over 3 

million tpy VOC and 700,000 tpy of 

methane to be emitted. Taking into 

account the production decline, the 

commenter contends that an analysis of 

the Bakken shale formation indicates 

that in 2015 storage vessels could still 

be emitting about 30 percent of their 

initial emissions. For the reasons given 

above, the commenter believes that the 

Group 1 storage vessel exemption is 

arbitrary and falls short of section 111 

mandates that standards of performance 

reflect BSER. 

The commenter further contended 

that if EPA’s analysis indicates a 

sufficient supply of control devices will 

be available in the future, then Group 1 

storage vessels should be controlled 

within a reasonable time. The 

commenter states that a compliance 

deadline in mid 2015 would provide 

adequate time for all storage vessels 

currently subject to the proposed rule to 

come into compliance. To support this 

view, the commenter reasons that, if 

some fraction of the Group 1 storage 

vessels will no longer have emissions 

exceeding 6 tpy, the demand for control 

devices is likely to be lower than the 

EPA’s projections, given the 

opportunities to manifold closelyspaced storage vessels, the increased 

practice of multi-well pads which 

would share storage vessels, and the 

EPA’s statement in the preamble to the 

proposed rule that control device 

manufacturers are likely to be flexible in 

their ability to meet equipment demand 

increases in the future. 

Another commenter agrees that an 

alternate compliance schedule is 

necessary to accommodate the increased 

demand for control devices but 

recommended that Group 1 storage 

vessels that continue to have emissions 

greater than 6 tpy as of the Group 2 

compliance date be required to comply 

with the control requirements of the 

rule. 

Several commenters express concern 

that the increased demand for control 

devices will lead to delays in getting the 

devices installed and that additional 

time to comply with the proposed 

standards is required. One commenter 

states that the companies that supply 

the services to comply with the 

proposed amendments will have their 

time monopolized by the large oil and 

gas companies, leading to a shortage of 

these services for small oil and gas 

companies. Another commenter 

similarly expresses concern that small 

independent producers will experience 

a shortage of service personnel because 

the smaller producers have less leverage 

and buying power than large producers. 

Response: In the preamble to the 

proposed amendments, we discussed 

our rationale for requiring controls only 

on those Group 1 storage vessel affected 

facilities that have an event that would 

likely lead to an increase in the 

potential to emit VOC (78 FR 22130). 

Our decision to require controls only on 

Group 1 storage vessels that experience 

such an event was based, in large part, 

on our understanding at that time and 

the information then available of the 

supply of combustors that likely would 

be used to comply with the control 

requirements. As we understood the 

combustor manufacturing industry at 

the time of proposal, the total capacity 

to produce combustors was 

approximately 300 units per month, 

which was based on information from 

six combustor manufacturers, and that 

the industry had the capability of 

increasing that capacity by about 100 

units per month. 

In response to comments questioning 

our combustor supply analysis, we 

reassessed the production capacity of 

the combustor manufacturing industry. 

We were able to confirm the data for 

some of the six manufacturers for which 

we had data at proposal, which leads us 

to believe the data as a whole for these 

manufacturers are reasonable (i.e., 

current capacity on average of about 600 

units per year for each company). In 

addition, we were able to identify five 

additional combustor manufacturers. Of 

these five, three provided production 

capacity estimates that were in line with 

the data we originally had for the six 

companies, one provided production 

estimates that were significantly higher 

than any of the other companies, and 

one did not provide any data. We 

averaged the production capacity of the 

nine similar companies to complete the 

missing data from the one facility that 

did not provide data. We then summed 

the capacity of these 11 companies to 

determine total current manufacturing 

capacity of combustors, which was 

approximately 2,300 units per month. 

We also estimated future capacity of 

the combustor manufacturers based on 

information provided by the 

manufacturers for anticipated future 

increases in production capacity. Based 

on this information, we estimated future 

capacity to be as high as approximately 

3,000 units per month by April 15, 

2015. 

The new information described above 

(for further details, see the 

memorandum entitled Combustor 

Supply and Demand Analysis, available 

in the docket) seems to indicate that the 

combustor suppliers have the 

manufacturing capacity to meet the 

demand posed by all (i.e., both Group 1 

and Group 2) storage vessel affected 

facilities required to comply with 

emission standards in the 2012 NSPS. 

Therefore, in the final amendments, we 

continue to require that Group 1 storage 

vessel affected facilities comply with 

the emission standard requirements. 

However, we have extended the current 

compliance deadline for the reasons 

stated below. 

While the overall projected supply of 

combustors appears to be adequate, we 

do not have information as to whether 

the combustor manufacturers are 

producing at the projected capacity and, 

if not, how quickly they can ramp up 

production to provide the necessary 

supply for the 2012 NSPS. More 

importantly, we note that there is a great 

variability in the projections of 

combustor supply, where one supplier’s 

projection greatly exceeds the other 

suppliers’ projections and accounts for 

a significant portion of the supply. To 

gauge the sensitivity of this one 

company on the combustor supply, we 

revisited our supply analysis assuming 

this company could manufacture 

combustors only at the highest 

manufacturing rate reported by any of 

the other combustor manufacturers. We 

found that under this scenario the 

supply of combustors never satisfies the 


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demand. Thus, this one manufacturer is 

critical in meeting the overall demand 

imposed by the 2012 NSPS. 

Because this company plays such an 

important role in meeting the combustor 

supply, any factor that may delay or 

slow their production may significantly 

affect the ability of Group 1 and Group 

2 storage vessel affected facilities to 

achieve compliance by the current 

compliance deadline in the 2012 NSPS 

(i.e., October 15, 2013, or 60 days after 

startup, whichever is later). In light of 

the above, we believe it is prudent to 

allow more time for compliance to lift 

the pressure on the demand of control 

devices, especially in the short term. 

Under the 2012 NSPS, compliance is 

required by October 15, 2013, for an 

estimated over 20,000 storage vessel 

affected facilities that will have come on 

line since the August 23, 2011, (the 

proposal date of the 2012 NSPS), and an 

additional 1,100 new affected facilities 

per month will need to install control 60 

days after start-up. Extending the 

current compliance deadline would 

allow the market to more easily absorb 

any events that may cause combustor 

manufacturing to fall short of the 

projected production capacity. 

In addition to the supply issues 

described above, commenters raise the 

concern about not being able to secure 

the necessary trained personnel to 

install control devices by the current 

compliance deadline. In light of the 

large number of storage vessel affected 

facilities (estimated over 20,000 by 

October 15, 2013, with an additional 

1,000 per month after that), and given 

the wide geographic distribution of oil 

and gas wells across the United States, 

we believe that the commenters raise a 

legitimate concern. In particular, we are 

concerned about how a potential 

shortage of trained personnel may 

impact small businesses. The 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 

and influence. This may result in a 

situation where small owners and 

operators may be placed in a 

disadvantage to their larger competitors 

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 the issues described above 

that may hinder storage vessel affected 

facilities’ ability to comply by the 

current October 15, 2013, deadline, we 

do not believe it is reasonable to retain 

that compliance date. Instead, in the 

final amendments, we take a phase-in 

compliance approach that first 

addresses newer affected facilities 

(which would have higher emissions) 

while assuring that all affected facilities 

have time to acquire and schedule 

installation of control. The final 

amendments establish Group 1 and 

Group 2 affected facilities, as proposed, 

where Group 1 are those affected 

facilities that came on line on or before 

April 12, 2013, and Group 2 are those 

that come on line after that date. The 

final amendments require that Group 2 

comply by April 15, 2014 (or 60 days 

after start-up, whichever is later), a 6- 

month extension from the current 

October 15, 2013, deadline for these 

newer affected facilities. The final 

amendments require that Group 1 

comply by April 15, 2015. Were we to 

require that both groups comply by 

April 15, 2014, an estimated 30,000 

affected facilities would be competing to 

acquire and install control by that date; 

as a result, the 6 month extension would 

do little to ease the demand for control 

or skilled personnel to install control 

should either become an issue in the 

near future. Also, requiring Group 1 to 

comply by April 15, 2014 would likely 

affect Group 2’s ability to comply, thus 

undermining our goal to address the 

newer storage affected facilities sooner. 

Lastly, considering the large number of 

Group 1 affected facilities (which we 

estimate to be around 19,400), we 

believe that requiring all Group 1 

affected facilities to comply by April 15, 

2015 is reasonable. In light of the issues 

discussed above, we do not expect that 

these affected facilities would wait until 

near that deadline and risk 

noncompliance; rather, we believe that 

the deadline provides Group 1 advance 

notice and allows them time to plan for 

acquiring and scheduling installation of 

control device by that date. Therefore, 

in the final amendments, we have 

specified that all Group 1 storage vessel 

affected facilities must comply by April 

15, 2015, and that Group 2 storage 

vessel affected facilities must comply by 

April 15, 2014, or 60 days after startup, 

whichever is later. 

b. Clarification of ‘‘Events’’ That May 

Increase Emissions 

Comment: Several commenters 

request that the EPA more clearly define 

the types of events that would trigger 

emission increases for Group 1 storage 

vessels. Seven commenters request that 

the EPA limit the examples to a finite 

list of events to remove ambiguity. One 

commenter states that the ‘‘events’’ that 

trigger control requirements for Group 1 

tanks should be more specific for 

storage vessels at well sites. According 

to the commenter, only the events 

described in § 60.5395(b)(2)(i) through 

(iii) of the proposed amendments 

should be considered triggering events 

for storage vessels that store reservoir 

fluids (i.e., at well sites, tank batteries, 

centralized production facilities). 

One commenter requested that the 

EPA delete the list of examples of events 

that would increase emissions from the 

rule language and provide that control 

requirements are triggered by a change 

that, in the owner’s/operator’s 

judgment, is one that could reasonably 

be expected to increase VOC emissions. 

One commenter suggests that the EPA 

should clarify the illustrative list of 

emission-increasing events to include 

well maintenance activities, such as 

liquids unloading, various well 

workover procedures, and any other 

well maintenance activities which 

increase production. 

Response: As discussed in section 

IV.A of this preamble, the final 

amendments do not change the 

requirement in the 2012 NSPS that all 

storage vessel affected facilities, 

including those we define as Group 1 

affected facilities, to meet the emission 

standards, although the amendments 

extend the time for compliance. Since 

all Group 1 storage vessel affected 

facilities remain subject to control 

requirements, there is no need to track 

events in order to determine which 

Group 1 storage vessel affected facilities 

are subject to control requirements, we 

are not finalizing the proposed 

provisions related to events in the final 

amendments. 

c. At what emission rate are Group 1 

storage vessels that experience an event 

required to install controls? 

Comment: Three commenters request 

that the EPA clarify that Group 1 storage 

vessels that experience an event that 

results in an increase in emissions 

would not be required to install controls 

if the VOC emissions are below the 6- 

tpy emission threshold. Two 

commenters recommend that the 6 tpy 

threshold be included either in the 

definition of ‘‘Group 1 storage vessels’’ 

in § 60.5430 or be explicitly listed as a 

condition in the requirement under 

§ 60.5395(b)(1). 

One commenter states that if 

emissions from a Group 1 storage vessel 

affected facility decrease below 6 tpy 

due to production decline, and it was 

determined even after a potentially 

triggering event that emissions had not 

returned to a level above 6 tpy, the 

storage vessel should not become 

subject to Group 2 controls. This view 

is generally supported by two additional 

commenters. The commenter refers to 

§ 60.5410(i) which specifies that the 


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requirement for installing Group 2-level 

controls is further limited to Group 1 

storage vessel affected facilities for 

which the potential VOC emission rate 

is 6 tpy or greater after the triggering 

event. According to the commenter, this 

6 tpy threshold is reasonable and 

appropriate because the EPA concluded 

in the initial rulemaking that Group 2 

controls would not be cost effective for 

storage vessels emitting less than 6 tpy 

of VOC. 

The commenter adds that based on 

statements in the preamble (78 FR 

22132) and regulatory language in 

§ 60.5410(i), this 6 tpy threshold should 

be repeated in § 60.5395. 

Response: As discussed in the 

previous comment response, the final 

amendments do not require that Group 

1 storage vessels track events. Therefore, 

these comments are now moot. 

3. Alternative 4-tpy Uncontrolled Actual 

VOC Emission Rate 

Comment: One commenter states that 

the proposed 4 tpy emission rate, below 

which controls would not be required, 

is not BSER and would allow large and 

unjustifiable emissions increases. 

According to the commenter, the 95 

percent control limit ensures that actual 

emissions do not exceed 0.2 tpy. Under 

the proposal, a storage vessel could emit 

up to 4 tpy indefinitely which is nearly 

a 3.8 tpy increase above the emissions 

that would be allowed under the 

proposed NSPS. 

According to the commenter, once 

control devices are removed, it is more 

likely that unplanned events will cause 

significant emissions spikes, further 

increasing air pollution. For example, if 

an operator diverts a sudden surge of 

VOC-containing liquids to a storage 

vessel for which the operator has 

removed controls under the proposed 

mass-based limit, there will be no way 

to control the resulting emissions spike. 

The commenter contends that the result 

is that transient but significant 

emissions events may become more 

common at storage vessels using the 

proposed mass-based limits. 

The commenter adds that even if it is 

assumed that the proposed emission 

rate would apply for a single year of a 

given group of storage vessels’ lives, the 

proposal would allow tens of thousands 

of tons of pollution in that year. If 

storage vessels operate longer, or 

decline more slowly after passing the 4 

tpy threshold, the amount of additional 

air emissions will be even higher. 

The commenter could find no 

authority in the CAA for abandoning 

BSER controls after they have been 

installed. Having already determined 

that 95 percent control is BSER, the 

commenter states that the EPA provided 

no justification of the basic premise or 

the level of the proposed emission rate. 

The emission rate has not been 

demonstrated to alleviate any control 

device shortage, and control devices 

that would become available due to the 

emission rate are unlikely to be 

available for more than a decade after 

the proposal is finalized. 

The commenter contends that the 

EPA has not shown that the proposed 4 

tpy limit corresponds to BSER. To make 

such a demonstration, the commenter 

believes, it would be necessary for the 

EPA to show that control technology has 

not been demonstrated below the 4 tpy 

emission rate, meaning that such 

sources can properly escape control, or 

that controls are not cost-effective for 

the industry as a whole below such an 

emission rate. According to the 

commenter, controls clearly are 

available for storage vessels with 

emissions of 4 tpy and below, so there 

is no justification for the 4 tpy emission 

rate on control technology availability 

grounds. Additionally, the commenter 

contends that significant VOC emissions 

can be captured below the proposed 

threshold. With respect to cost, the 

commenter believes recent information 

indicates the annualized cost of storage 

vessel combustors has declined 

substantially since subpart OOOO was 

finalized, significantly enhancing the 

cost effectiveness of controlling VOC 

emissions from storage vessels with a 

PTE of 4 tpy or less. The commenter 

provides information from a Colorado 

Department of Public Health and 

Environment (DPHE) pending 

rulemaking showing that the annualized 

combustor costs are around $15,900/yr, 

as compared to the previous value of 

$19,600/yr, resulting in a cost 

effectiveness of $4200/ton at 4 tpy. 

Further, the commenter believes that 

the EPA’s control costs overestimate 

actual costs because the EPA does not 

take into account savings that would be 

experienced when controls are shared 

among storage vessels. As a result, 

controls are more affordable at lower 

uncontrolled emissions thresholds. 

According to the commenter, if the EPA 

sets a very low emission threshold at 

which removal and reuse is permissible, 

more vessels would have to buy new 

control devices, raising control costs 

again. Thus, the commenter believes 

that the EPA’s analysis does not 

compare this variation, or considered 

the appropriate way to design such a 

system in light of the variation. 

According to the commenter, the EPA 

states in the proposal that control device 

manufacture will lag the growing 

population of storage vessels for a few 

years and used this rationale to 

separately waive controls for Group 1 

storage vessels and assure adequate 

supply of control devices for Group 2 

storage vessels. The commenter 

contends that the EPA further states that 

allowing affected storage vessels to 

remove controls under the proposed 

emission rate would help alleviate the 

control device shortage. According to 

the commenter, the EPA’s justification 

that imposing the emission rate is due 

to uncertainty in their control 

technology projections and that an 

additional exemption would ‘‘help 

build a buffer’’ against this uncertainty 

is not a cognizable justification for a 

section 111 standard under the CAA. 

Further, the commenter does not believe 

that the EPA has demonstrated either 

the necessity or appropriateness of the 

proposed emission rate. 

The commenter states that the EPA’s 

concerns about ‘‘buffering’’ technology 

supply could only justify this departure 

from the existing standard if the 

proposed emission rate was also 

demonstrated to be BSER. According to 

the commenter, the EPA determined 

that requiring storage vessels with 

uncontrolled emissions greater than 6 

tpy to achieve 95 percent control of 

those emissions reflects BSER and is 

cost effective. The commenter states that 

if these controls were maintained on a 

storage vessel as its emissions declined 

over time, total uncontrolled emissions 

would continue to fall. But under the 

proposed emission rate, the commenter 

contends that emissions could instead 

jump sharply after the threshold has 

been crossed. The commenter believes 

that this reversal in the emissions trend 

does not reflect BSER because it does 

not reflect the best demonstrated system 

of emissions control. According to the 

commenter, it is instead what happens 

when BSER controls are removed. 

The commenter adds that for the 

EPA’s ‘‘buffer’’ rationale to hold up, 

operators must be able to costeffectively and regularly remove used 

control devices, store them as needed, 

and transfer them to new storage vessels 

at a rate which will meaningfully 

address the control device shortage 

which the EPA projects. The commenter 

asserts that the EPA provided no 

evidence showing operators would be 

able to do this, or would choose to do 

so. According to the commenter, storage 

vessels installed now would in all 

likelihood not take advantage of the 

proposal until the 15th year of operation 

(based on decline curve data provided 

by the commenter showing that it would 

take up to 15 years for well production 

to decline to a level to produce 

uncontrolled storage vessel emissions of 


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4 tpy). As a result, the commenter 

believes that the proposed emission rate 

would not generate any control devices 

for transfer for more than a decade, 

which is long after the EPA estimates 

adequate control devices will be 

available. Thus, according to the 

commenter’s analysis, even if control 

devices could be transferred, such 

transfers will not buffer a short-term 

shortage. That shortage, if it exists, will 

long have passed. Instead, the 

commenter believes that the proposed 

emission rate would simply increase air 

pollution. 

The commenter further states that 

even if the EPA were to actually require 

operators to build the buffer it desires, 

the EPA offers no evidence that such a 

buffer is required indefinitely. 

Elsewhere in the proposal, the 

commenter contends, the EPA expresses 

its view that control device 

manufacturers will respond to the 

standards by manufacturing enough 

control devices to meet the demand 

imposed by the standards, perhaps after 

an initial delay. The commenter points 

out that past experience shows that 

control devices become available if they 

are required, and this technologyforcing function is central to how 

section 111 is intended to work. By 

instead allowing operators to avoid 

purchasing new controls, and to remove 

them from other sources and reuse 

them, the commenter contends that the 

EPA permanently limits the market for 

new control technology, while also 

allowing excess emissions. The result 

will be fewer controls in the long-term, 

and more pollution. 

The commenter believes that the 

Wyoming guidance the EPA mentions in 

the proposal does not comply with 

section 111 standards, and contends 

that the EPA does not offer evidence 

that it has avoided excess pollution. 

Another commenter believes the 

EPA’s choice of an uncontrolled 

emission rate of 4 tpy as the emission 

rate is arbitrary and unsupported. The 

commenter states that the EPA provided 

no engineering basis, credible health 

benefit estimate, or other justification 

for why the 4 tpy emission rate is 

appropriate. 

The commenter also states that the 

EPA did not provide any justification or 

analysis demonstrating whether control 

at 4 tpy is cost effective. The commenter 

states a cost effectiveness analysis was 

performed for the 6 tpy applicability 

threshold, but no such information is 

provided for the proposed 4 tpy 

emission rate. The commenter opined 

that this approach will create situations 

of great inequity where neighboring 

facilities may have identical PTE VOC 

emissions from a single storage vessel or 

battery, but very different regulatory 

burdens. The commenter provides an 

example where a site with emissions of 

5.95 tpy is not subject to any of the 

notification, reporting, or control 

requirements of this NSPS. However, a 

neighboring site with initial production 

emissions of 6.1 tpy must notify, 

control, monitor, record, and report to 

comply with the NSPS. The commenter 

provides that, as natural production 

declines occur, after a year of 

uncontrolled emissions of 3.95 tpy 

(below the 4 tpy threshold) the 

additional controls may be removed, but 

the burden of reporting and 

recordkeeping continues indefinitely for 

this site. 

The commenter also states that this 

approach may also drive companies to 

design their sites in a way that results 

in increased emissions overall, defeating 

the goal of the rule itself. For example, 

according to the commenter, to avoid 

applicability of the rule as a whole, new 

sites will likely be designed with more 

tanks such that no single tank will 

exceed the 6 tpy applicability threshold 

but emissions from the larger number of 

small tanks may have higher overall 

emissions. The commenter believes that 

this in turn may exacerbate the shortage 

of storage tanks that already exists and 

may further delay production due to the 

lack of tank availability. Further, the 

commenter states that the proposed 

emission rate may lead to hastily 

constructed tanks that may not be as 

soundly designed and constructed 

creating potential concerns for public 

health and safety as well as air quality. 

The commenter contends that the 

EPA focused on the concept of any 

planned event that has the potential to 

increase emissions to or above 4 tpy. 

However, according to the commenter, 

this does not account for any potential 

short-term activities that may trigger 

reinstallation of controls such as 

degassing, refilling, inspection or 

maintenance when emissions in the 

long-term would otherwise remain 

below the 4 tpy level. The commenter 

states that this may result in the delay 

of appropriate maintenance or other 

actions that would otherwise be 

conducted. Building on the example of 

neighboring sites described above, the 

commenter states that, if the second site 

wanted to confirm tank integrity by 

inspection and cleaning, one-time 

emissions may raise the annual 

uncontrolled PTE to over 4 tpy, thus 

triggering not only reinstallation of 

controls but all associated monitoring, 

recordkeeping and reporting 

requirements. 

Several commenters believe that a 

more appropriate approach would be to 

allow the removal of controls if a storage 

vessel has had uncontrolled actual 

emissions that remain below 6 tpy VOCs 

for 6 months. The commenters also 

believe that this initial determination is 

sufficient and that no further monitoring 

should be required unless otherwise 

required under § 60.5395(b)(2). 

According to the commenters, wells 

experiencing natural production decline 

are unlikely to ever experience an 

increase in emissions, but instead will 

continue to experience an emissions 

decrease. The commenters state that this 

continuing natural decline also supports 

the contention that 6 months is a 

sufficient timeframe to monitor 

emissions before removing controls. 

One commenter adds that the 

proposed approach would require 

owners/operators to make a one-time 

commitment of what a tank will contain 

to the extent that potential emissions 

will ever exceed 6 tpy. The commenter 

believes that this inappropriately 

extends the ‘‘once in, always in’’ policy 

beyond its previous applications. While 

it appears that EPA would allow vessels 

to come in and out of regulation based 

on whether they contain crude oil, 

condensate, intermediate hydrocarbon 

liquids, or produced water at a given 

time, the commenter contended that the 

proposal would create a one-time 

determination of potential emissions 

that forever captures a tank, regardless 

of whether it continues to hold the 

materials that would bring it within 

regulation. In proposing low emitting 

storage vessels remain subject to the 

rule indefinitely, the commenter 

believes that the EPA is imposing 

unnecessary and burdensome control, 

recordkeeping, and reporting 

requirements on many storage vessels. 

Should EPA retain this ‘‘once in, always 

in’’ requirement, the commenter 

recommends that it should affirm that 

storage vessels no longer holding VOCcontaining liquids or that are taken out 

of service are no longer an affected 

source. 

Concerning re-installation of controls, 

several commenters state that the 

threshold should be 6 tpy instead of 4 

tpy based on the EPA’s cost 

effectiveness determination. 

Response: To help alleviate the 

control supply shortage believed to exist 

at the time, we had proposed to amend 

the storage vessel emission standards to 

require compliance with either the 95 

percent reduction requirement or an 

uncontrolled actual VOC emission rate 

of less than 4 tpy, which would allow 

control devices to be removed from 

storage vessel affected facilities below 


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that emission rate and relocated to those 

that have just come on line and have the 

VOC PTE of 6 tpy or more. As 

previously mentioned, new information 

we received since proposal indicates 

that the combustor suppliers have the 

manufacturing capacity to meet the 

demand posed by this NSPS, which in 

turn suggests that a supply buffer may 

no longer be necessary. However, for the 

reasons stated below, we have amended 

the storage vessel emission standards as 

proposed due to the cost effectiveness of 

continuing control and the increasing 

environmental disbenefits and energy 

impacts from the continued operation of 

the combustion control device at an 

inlet stream VOC concentration of less 

than 4 tpy. 

As shown in the memo entitled Cost 

and Secondary Environmental Impacts 

Associated with Controlling Storage 

Vessels under the Oil and Natural Gas 

Sector New Source Performance 

Standards, available in the docket, our 

analysis indicates that the cost of 

controls for each storage vessel affected 

facility at a VOC emission rate of 4 tpy 

is approximately $5,100 per ton. This 

cost increases to approximately $6,900 

per ton at an emission rate of 3 tpy, and 

to approximately $10,000 per ton at 2 

tpy. For comparison, we note that, in a 

previous NSPS rulemaking [72 FR 

64864 (November 16, 2007)], we had 

concluded that a VOC control option 

was not cost effective at a cost of 

$5,700/ton, which calls into question 

the cost effectiveness of continuing 

control of storage vessel affected 

facilities at an emission rate below 4 

tpy. 

One commenter recommends that, if 

we retain the uncontrolled VOC 

emission rate, it should be set no higher 

than 0.3 tpy (representing the emission 

rate of a 6 tpy VOC emission stream 

controlled at 95 percent) rather than 4 

tpy. We emphasize that the 4 tpy 

uncontrolled VOC emission rate is not 

based on equivalency to the 95 percent 

reduction, nor do we think such 

conversion to an emission limit is 

appropriate considering it would result 

in a range of emission limits depending 

on the baseline uncontrolled emissions. 

The 0.3 tpy suggested by the commenter 

only represents the limit for sources 

with PTE of 6 tpy while those with 

higher PTE would have higher limits 

that equate to 95 percent reduction. 

Further, at the commenter’s suggested 

emission rate of 0.3 tpy, the cost would 

be approximately $70,000 per ton of 

emission reduction, which we do not 

consider to be cost effective. 

One commenter questioned the basis 

of our control cost estimates and 

pointed to a recent update by Colorado 

DPHE, an earlier version of which we 

used as the basis for our cost estimate, 

which indicated a lower cost of control. 

We point out that the lower cost in the 

revised Colorado analysis is primarily 

due to a lower cost (by approximately 

half) of the fuel for the pilot flame. Our 

assumption is that gas prices will 

remain relatively stable over time and 

question whether this lower fuel cost is 

applicable to all areas of the U.S. 

outside Colorado and whether such 

costs will be maintained in the long 

term. We also point out that the 

Colorado analysis did not include costs 

for a surveillance system or data 

management system, which were 

included in our analysis. Finally, the 

Colorado analysis showed an increase in 

capital cost of about $2,000 over the 

capital costs in our analysis. For these 

reasons, we believe our costs, if 

anything, may underestimate costs 

rather than overestimate as the 

commenter claims. We made no changes 

to our cost analysis based on this 

comment. 

Another commenter suggested that 

our cost estimate overestimates costs 

because we did not take into account 

savings that would result when control 

devices are shared by storage vessels. 

The comment is incorrect. In our 

analysis, we assumed that there would 

be one control device used per well site. 

We also acknowledged that there are 

likely multiple storage vessels per well 

site, all of which would be routed to a 

single control device. 

In addition to cost effectiveness, we 

evaluated the secondary impact from 

continuing control below 4 tpy. As 

shown in the memo entitled Cost and 

Secondary Environmental Impacts 

Associated with Controlling Storage 

Vessels under the Oil and Natural Gas 

Sector New Source Performance 

Standards, available in the docket, on a 

nationwide basis, the combustion of the 

pilot flame fuel and the combustion of 

the VOC vapor in the storage vessel vent 

stream will result in increases in NOX, 

CO, CO2, and methane emissions, most 

notably CO2 emissions. We estimate that 

the operation of each combustion 

control device on a VOC storage vessel 

vent stream flow rate of 3 tpy will result 

in the following secondary emissions: 

54 tpy of carbon dioxide (CO2), 0.14 tpy 

of carbon monoxide (CO) and 0.028 tpy 

of nitrogen oxides (NOX). 

We also evaluated the energy impacts 

associated with continuing control 

below 4 tpy. The discussion here for 

secondary energy and environmental 

impacts is on the basis of one 

combustion control device. As of the 

date of publication of this preamble, we 

estimate that there are approximately 

20,000 storage vessel affected facilities 

that require combustion control devices 

and that the number is projected to 

increase by about 11,000 per year. We 

also estimate that on average, from 2014 

through 2020, approximately 8,000 

storage vessel affected facilities per year 

will experience VOC emissions decline 

to below 4 tpy. Our information 

indicates that the fuel usage (primarily 

methane) for the pilot flame on a single 

combustion control device may be 

approximately 12 tpy (based on a fuel 

flow rate of 70 scf/hr for the pilot flame, 

or about 613 Mcf per year). Thus, at a 

storage vessel VOC emission rate of 4 

tpy, a combustion device would have to 

combust an amount of fuel gas about 3 

times the mass of the VOC vapor from 

the tank being controlled simply to keep 

the pilot flame operating. This ratio 

increases even further for VOC emission 

rates less than 4 tpy. Considering the 

nationwide energy impact of continuing 

to operate the pilot flame of an 

extremely large number of combustion 

control devices for VOC flow rates far 

lower than the pilot flame fuel flow 

rates, we question whether this is a 

responsible use of our energy resources. 

In light of the cost-effectiveness, the 

secondary environmental impacts and 

the energy impacts, we have concluded 

that the BSER for reducing VOC 

emissions from storage vessel affected 

facilities is not represented by 

continued control when their sustained 

uncontrolled emission rates fall below 4 

tpy. For the reason stated above, we 

have amended the storage vessel 

emission standards to require that, at all 

times, affected facilities comply with 

either the 95 percent reduction 

requirement or an uncontrolled actual 

VOC emission rate of less than 4, as 

proposed. Under the final amendments, 

an owner or operator may comply with 

the uncontrolled VOC emission rate 

instead of the 95 percent control 

requirement where it can be 

demonstrated that, based on records of 

monthly determinations of VOC 

emissions for the 12 consecutive months 

immediately preceding the 

demonstration, that the storage vessel 

affected facility uncontrolled actual 

VOC emissions each month during that 

12-month period are below 4 tpy. The 

final amendments require that the 

owner or operator re-evaluate the 

uncontrolled VOC emissions on a 

monthly basis. For the same reasons 

discussed below in this section in our 

response to comments concerning 

storage vessels that are taken out of 

service, the 4 tpy alternative emission 

standards in the final amendments at 

§ 60.5395(d)(2) require control to be 


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applied in either of two cases. First, if 

a well feeding a storage vessel affected 

facility undergoes fracturing or 

refracturing, the owner or operator must 

comply with the 95 percent reduction 

requirements in § 60.5395(d)(1) as soon 

as liquids from the well following 

fracturing or refracturing are routed to 

the storage vessel affected facility, 

regardless of the last monthly emissions 

determination. On the other hand, if a 

monthly emissions determination 

required in § 60.5395(d)(2) indicates 

that VOC emissions from a storage 

vessel affected facility have increased to 

4 tpy or greater, and the increase is not 

associated with fracturing or 

refracturing of a well feeding the storage 

vessel, then the owner or operator must 

apply 95 percent control according to 

§ 60.5395(d)(1) within 30 days of the 

monthly calculation. 

One commenter stated that the 4 tpy 

uncontrolled VOC emission rate does 

not represent BSER. As previously 

explained, due to the cost effectiveness, 

the secondary environmental impact 

and energy impact, the 4 tpy emission 

rate likely represents a point below 

which continued control ceases to be 

the BSER for reducing VOC emissions 

from storage vessel affected facilities. 

One commenter asserted that some 

maintenance events at neighboring sites 

may cause short-term spikes in VOC 

emissions of 4 tpy or more, thereby 

triggering control for at least another 12 

months. As discussed above, the final 

amendments provide for two alternative 

emission standards, either of which 

must be met at all times. However, the 

2012 NSPS contains affirmative defense 

provisions that may be considered in 

cases where malfunctions occur causing 

emissions to exceed the standard. 

Planned activities are expected to be 

conducted in compliance with the 

emission standards. 

We also made changes to the final 

amendments to clarify our intent that 

the uncontrolled VOC emission rate is 

available for all storage vessel affected 

facilities. In the proposed amendments, 

§ 60.5395(d)(2) conditionally allowed 

the owner or operator to meet an 

uncontrolled actual VOC emission rate 

so long as the monthly actual 

uncontrolled emission rate remained 

below 4 tpy. However, in the proposed 

amendments we included the following 

qualifier in § 60.5395(d)(2): ‘‘provided 

that you have been using a control 

device and have demonstrated that the 

VOC emissions have been below 4 tpy 

without considering control for at least 

the 12 consecutive months immediately 

preceding the demonstration.’’ 

We now believe that this qualifier 

places undue restriction on the use of 

the emission rate. Under the qualifier, 

Group 1 affected facilities that had 

uncontrolled emission below 4 tpy by 

the amended compliance date would 

not be able to avail itself of this option. 

We see no reason for such limitation 

and have therefore removed the 

qualifier language in the final 

amendments. 

Concerning a commenter’s assertion 

that one storage vessel with PTE of just 

over 6 tpy would be subject to control, 

recordkeeping and reporting 

requirements but that a storage vessel 

with PTE of just under 6 tpy would not 

be subject to any requirements, we 

respond that applicability thresholds 

exist for many rules and that subpart 

OOOO is not unique in that regard. 

With regard to the assertion that owners 

and operators may try to circumvent the 

NSPS by installing multiple small 

throughput storage vessels to keep 

individual tank emissions below the 6 

tpy threshold, this comment pertains to 

the 2012 NSPS and not the proposed 

reconsideration, since changes to that 

threshold were not proposed. In 

response to the commenter’s concern 

about transient emissions above 4 tpy 

that are caused by operator actions, 

storage vessels that increase emissions 

to at least the 4 tpy actual VOC 

emissions limit are subject to the control 

requirements. Owners and operators 

must ensure that they are aware of 

emissions increases that may occur after 

an activity and take appropriate action 

to control those emissions as required 

by the NSPS. With regard to 

uncontrolled VOC emissions of 6 tpy for 

6 consecutive months being a more 

appropriate uncontrolled actual VOC 

emission limit, we have explained in 

section IV.B our rationale for the 4 tpy 

emission limit. In addition, we have 

never determined that control below 6 

tpy is not cost-effective; to the contrary, 

we have determined that control at 4 tpy 

and above is cost-effective. Furthermore, 

we are concerned that setting the 

emission limit to allow removal of 

control if uncontrolled emissions are 

below 6 tpy for 6 consecutive months 

does not provide for reasonable 

certainty that emissions would not be 

controlled to the maximum extent 

possible that is still cost-effective and 

that does not create undue secondary 

impacts. Moreover, a full 12 months of 

sustained monthly uncontrolled actual 

emissions estimates below the 4 tpy 

limit will reasonably ensure that 

emissions fluctuations will not cause 

excursions above the limit, requiring 

controls to be reapplied. In the context 

of once in always in, the EPA has not 

extended this policy by providing that 

storage vessel affected facilities that 

subsequently reduce PTE to below 6 tpy 

remain affected facilities. The EPA 

historically has never let facilities in 

and out of affected facility status and is 

consistent in subpart OOOO. Having 

storage vessels remain affected facilities 

when emissions decline allows 

regulatory agencies to track emissions of 

these storage vessels and to monitor 

compliance if they increase. Further, 

operators are not restricted as to what 

they store in a tank; if the contents are 

crude oil, condensate, hydrocarbon 

intermediates or produced water, and 

the storage vessel has PTE of at least 6 

tpy, it is a storage vessel affected facility 

and subject to subpart OOOO. In 

addition, in response to a comment that 

a tank is forever an affected facility 

regardless of its future contents, we 

disagree. If a tank ceases to be used for 

a purpose other than to hold an 

accumulation of any of the materials 

listed above, then it ceases to fit the 

definition of storage vessel under 

subpart OOOO and is therefore no 

longer an affected facility subject to the 

standards. 

One commenter requests that we 

clarify that a storage vessel affected 

facility that is taken out of service 

ceases to be an affected facility under 

the NSPS. On the contrary, the storage 

vessel remains to be an affected facility, 

although we realize that there may be 

undue burden associated with control 

and monitoring, recordkeeping and 

reporting requirements for storage 

vessels that are not in service. However, 

if a storage vessel affected facility that 

is out of service is returned to service, 

an emissions determination is necessary 

to see whether it can continue 

compliance with the 4 tpy uncontrolled 

emission rate or it must now install 

control to meet the 95 percent reduction 

requirement. In the 2012 NSPS, we 

concluded that we need to provide 

sufficient time for determining 

emissions and, if necessary, installing 

control. See 77 FR 49490, at 49526 

(August 16, 2012). Accordingly, the 

2012 NSPS provide 30 days for 

determining emissions and an 

additional 30 days to make control 

operational. We believe that a similar 

time frame is needed for a dormant 

storage vessel returned to service to 

demonstrate continued compliance with 

the 4 tpy uncontrolled emission rate or 

to install control to meet the 95 percent 

reduction requirement. After all, these 

storage vessels may very well have very 

low emissions upon startup and should 

not be forced to install control 

immediately without an opportunity to 

demonstrate that they can continue 


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compliance with the 4 tpy uncontrolled 

emission rate. However, we are 

concerned that a dormant storage vessel 

that is returned to service associated 

with the fracturing or refracturing of a 

well feeding it is likely to release 

substantial amounts of vapor if not 

controlled right away due to the initially 

high liquid flow and flash emissions 

from freshly fractured or refractured 

wells. We also believe that potential 

emissions associated with fracturing 

and refracturing of a well are unlikely 

to meet the 4 tpy uncontrolled emission 

rate. We are therefore not providing the 

time period described above for storage 

vessels returned to service associated 

with fracturing or refracturing of a well. 

In light of these considerations, we have 

added language at § 60.5395(f) of the 

final amendments to address storage 

vessel affected facilities that are 

removed from service. After taking a 

storage vessel affected facility out of 

service, owners or operators are 

required provide notification in their 

next annual report that the storage 

vessel has been taken out of service. If 

a storage vessel’s return to service is 

associated with fracturing or 

refracturing of a well feeding the storage 

vessel, the storage vessel must comply 

with control requirements in 

§ 60.5395(d) immediately upon 

returning to service. If, however, the 

storage vessel’s return to service is 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 in 

§ 60.5395(d) within 60 days of being 

returned to service. 

D. Major Comments Concerning 

Ongoing Compliance Requirements 

1. Burden of Monitoring and Testing 

Requirements 

Comment: One commenter states that 

the monitoring and testing requirements 

for storage vessels in the 2012 NSPS are 

overly complex and stringent given the 

large number of units affected and the 

remoteness of some wells sites. The 

commenter supports the EPA’s intent to 

reduce the monitoring and testing 

burden on affected sources by means of 

the streamlined monitoring provisions 

in the proposed amendments. However, 

the commenter contends that many of 

these ‘‘streamlined’’ provisions remain 

overly burdensome due to the large 

number of affected vessels and the 

remoteness of the well sites at which 

they are installed. In particular, the 

commenter believes that § 60.5416 

should only require an annual auditory, 

visual and olfactory (AVO) inspection of 

the vessel and control device, and that 

Method 22 observation should be 

required only if smoke is observed by 

the operator. 

Another commenter states that, as 

proposed, the monthly inspections and 

obligations for prompt repairs can be 

accomplished with existing personnel 

and not add significantly to the cost of 

compliance while ensuring that the 

required emissions controls are 

operating properly. 

Response: In this action, 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. 

In response to the comment stating 

that the streamlined monitoring 

provisions are still too burdensome, the 

EPA has re-evaluated the Method 22 

requirements in the proposed 

reconsideration rule and continues to 

believe that an observation time of 

fifteen minutes with a one minute 

smoke allowance for all combustion 

controls is appropriate. For 

manufacturer-tested enclosed 

combustors, the required frequency of 

the Method 22 test is quarterly. For all 

other combustion controls, the required 

frequency of the Method 22 test is 

monthly. A ‘‘smoke/no smoke’’ 

determination is essentially what 

Method 22 requires. Method 22 simply 

requires the observer to note how long 

emissions were seen over a period of 

time (15 minutes for monthly testing, 1 

hour for quarterly testing). If smoke is 

seen for more than a specified amount 

of time, it is a violation. We have 

information indicating that personnel 

are on-site at each well at least monthly. 

Since the Method 22 observation does 

not require highly trained personnel to 

conduct the test, we believe the 

personnel already on-site are capable of 

performing the test. Thus, we do not 

agree with the commenter that the 

monitoring provisions in the 

reconsideration proposal would result 

in undue burden, or that they are 

inappropriate considering the 

remoteness of the well sites. We have 

therefore finalized those provisions. 

2. Streamlined Compliance Monitoring 

Comment: Several commenters 

commented on the proposed 

streamlined compliance monitoring 

requirements for closed vent systems 

and control devices installed to reduce 

VOC emissions from storage vessels. 

Four commenters request that the EPA 

make the streamlined compliance 

monitoring requirements permanent. 

One of these commenters states that 

monitoring requirements imposed by 

the 2012 NSPS would be particularly 

onerous for small, independent 

operators that cannot afford the number 

of employees-hours required to travel to 

distant well sites with such high 

frequency. According to the 

commenters, their suggested changes to 

the proposed amendments would meet 

the goal of proper monitoring of 

emissions without requiring such a large 

amount of human and capital resources. 

Two commenters oppose the 

streamlined monitoring requirements 

and request that the EPA reinstate the 

more rigorous requirements in the 2012 

NSPS. One commenter states that 

portions of the streamlined monitoring 

requirements are unnecessary and 

burdensome. 

Another commenter expresses 

concern that the proposed amendments 

replace instrument-based monitoring of 

control devices and closed vent systems 

(CVS) with less reliable methods. 

Effective monitoring of the integrity and 

performance of emission control devices 

is vital to ensuring compliance with 

emissions limitations under section 111, 

according to the commenter, and is 

evident in the radically revised number 

of storage vessels with emissions 

exceeding 6 tpy. 

The commenter pointed out that the 

current subpart OOOO requirements for 

continuous parametric monitoring 

system (CPMS) and Method 22 testing, 

as well as Method 21 monitoring, build 

on other long-standing EPA regulations, 

including storage vessel standards 

under subpart HH and the NSPS for 

volatile organic liquid storage vessels, 

subpart Kb. The commenter added that 

they are also consistent with the 

proposed Uniform Standards for CVS 

and storage vessels. According to the 

commenter, the EPA went in the wrong 

direction by proposing to eliminate the 

CPMS requirements, shorten the 

Method 22 visible emissions testing, 

and allow operators to inspect CVS 

using OVA inspections. 

The commenter states that previous 

agency studies indicate that instrumentbased monitoring is cost-effective and 

more sensitive than sensory inspections, 

suggesting that if anything subpart 

OOOO should extend such monitoring 

to all roof fittings that could emit VOC. 

The commenter contends that the EPA 

provided no information in the 

proposed reconsideration that questions 


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the findings of the Uniform Standards 

on relative effectiveness or cost of 

instrument monitoring of storage vessel 

components. The commenter also points 

to the Fort Berthold Indian Reservation 

Federal Implementation Plan (FBIR FIP) 

where the EPA required continuous 

parametric monitoring of enclosed 

combustors, utility flares, and other 

control devices. Also in the FBIR FIP 

according to the commenter, the EPA 

rejected reducing the Method 22 

observation period to 1 hour to mitigate 

burdensome compliance costs as an 

option that was not suitable. The 

commenter does not believe the EPA 

provided specific information to 

warrant a different approach. 

The commenter adds that the EPA did 

not demonstrate that the proposed 

changes are necessary to mitigate cost 

and burdens raised by industry. The 

commenter states that the EPA cited 

general personnel and infrastructure 

concerns in the preamble but did not 

provide an analysis of the anticipated 

costs of implementing monitoring. In 

proposing to determine that the current 

monitoring requirements were 

infeasible, the commenter contends that 

the EPA did not indicate whether it took 

into account the reduced monitoring 

costs associated with the Group 1 

exemption for storage vessels that do 

not undergo an emissions-increasing 

event and the deferral of the Group 2 

storage vessel compliance date. 

Further, the commenter states that 

there is no indication as to whether 

Method 21 inspections, CPMS and full 

Method 22 testing would be infeasible at 

storage vessels at or near manned 

facilities. As a result, the commenter 

contends that the EPA’s streamlined 

monitoring requirements appear to be 

overly broad as well as inadequately 

supported. 

Another commenter adds that 

periodic monitoring of closed-vent 

systems and control devices is a very 

important part of controlling the air 

quality in the nation. The commenter 

asserts that most well sites are located 

far away from cities and sometimes it 

can be bothersome to drive back and 

forth in order to accomplish testing and 

monitoring processes. The commenter 

believes that the best way to encourage 

operators to use the appropriate models 

is by not letting them install equipment 

without proper documentation, and to 

fine them, or even stop onsite 

operations in case they do not obey the 

requirement. 

Response: In today’s action, the EPA 

is finalizing the streamlined compliance 

monitoring requirements, as proposed, 

with minor clarifying changes. In 

finalizing these provisions, the EPA has 

made no determination on the cost or 

feasibility of the compliance monitoring 

provisions in the 2012 NSPS, as some 

commenters appear to suggest. We also 

agree with the commenters about those 

provisions’ reliability and effectiveness. 

However, as we explained in the 

preamble to the proposed amendments 

(78 FR 22134), significant issues 

regarding their implementation have 

been raised in the administrative 

petitions for reconsideration of the 2012 

NSPS, which we are continuing to 

evaluate. We intend to complete our 

reconsideration of these requirements, 

along with any other issues for which 

we intend to grant reconsideration, by 

the end of 2014. We do not believe it is 

appropriate to impose these monitoring 

requirements on affected facilities while 

we are still evaluating their 

implementation issues. However, to 

avoid delaying compliance, we have 

proposed and are finalizing in today’s 

action a set of streamlined compliance 

monitoring requirements. We believe 

that they are adequate to assure 

compliance. Several commenters urge 

us to retain the monitoring provisions in 

the 2012 NSPS for the reasons 

summarized above, but none of them 

claim that the streamlined provisions 

laid out in the proposal are inadequate 

to assure compliance. In light of the 

above, we are finalizing the streamlined 

compliance monitoring requirements, as 

proposed, with minor clarifying 

changes. 

E. Major Comments Concerning Design 

Requirements 

Comment: Three commenters support 

the inclusion of design parameters in 

the final amendments. One commenter 

states that design parameters are 

important to reduce the possibility for 

an unintended loophole in the rule 

language which might result in 

potentially significant emissions. The 

commenter adds that their agency has 

observed the highest emission rates 

corresponding to flash VOC emissions 

while liquids are being added to an 

existing storage vessel and believes 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 contends 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. 

Another commenter supported this 

view and states that the final 

amendments must ensure that vapor 

collection systems and control devices 

will reduce 95 percent of VOCs during 

all phases of operation, including when 

air pressure significantly increases 

during loading. The commenter 

contends that where systems are 

currently in place to control condensate 

tank emissions at natural gas 

exploration and production sites, they 

are sometimes inadequate for 

controlling the high-pressure vapor 

produced when the tanks receive a slug 

of condensate. The commenter points 

out that the EPA has noted in this 

rulemaking that the feasibility of 

meeting the storage-vessel standards 

with a vapor recovery unit may be 

affected by ‘‘fluctuations in vapor 

loading caused by surges in throughput 

and flash emissions from the storage 

vessel.’’ The commenter provides 

several possible approaches to assure 

equipment is properly designed to meet 

the storage vessel standards. 

One of the commenters adds that the 

inclusion of design requirements would 

provide enforceable provisions that 

would assist permitting agencies in 

regulating sources. 

Eight commenters generally opposed 

the inclusion of design requirements in 

the final amendments. One commenter 

states that the EPA has already 

established BSER for affected storage 

vessels as the reduction of VOC 

emissions by 95 percent or greater and 

established work practice standards for 

the closed vent system to any control 

device or vapor recovery system. 

According to the commenter, these work 

practice standards address potential 

equipment design and maintenance 

issues that could affect the proper 

collection of and destruction or recovery 

of VOC emissions from storage vessels. 

The commenter asserts that a storage 

vessel, closed vent system, and control 

device that are not properly designed 

would not be able to meet the work 

practice standards and minimum 

control device destruction efficiency 

already required in the proposed rule; 

therefore, any process design standards 

would only be duplicative requirements 

and result in more burden to industry 

and state agencies responsible for 

compliance. 

The commenter maintains that the 

EPA should not attempt to expand any 

NSPS regulations by specifically 

regulating the process or mechanical 

design of storage vessels or the closed 

vent system to control devices or vapor 

recovery systems. The commenter 

further states that owners and operators 

are responsible for designing process 

equipment based on individual site 

process conditions and safety 

considerations. According to the 


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commenter, it would be a massive 

undertaking for the EPA to attempt to 

write regulations regarding the specific 

‘‘proper’’ design of storage vessels and 

closed vent systems. The commenter 

expresses doubt that the EPA could 

provide enough flexibility in process 

and mechanical design of equipment 

regulations to cover all the unique 

process conditions at individual 

facilities. 

One commenter adds that overprescriptive regulations on storage 

vessel design could stifle technological 

innovation, including new tank designs 

that emit less than current storage 

vessels. Additionally, according to the 

commenter, storage vessels are 

specifically designed in accordance 

with federal safety standards and these 

specifications should not be potentially 

compromised under any circumstances. 

Further, the commenter states that it is 

in the best economic interest of all 

operators to procure properly designed 

equipment and operate storage vessels 

efficiently. Lastly, the commenter states 

that, under the CAA, operators already 

have a general duty requirement to 

‘‘maintain and operate any affected 

facility including air pollution control 

equipment in a manner consistent with 

good air pollution control practices for 

minimizing emissions.’’ 

One commenter does not believe that 

the EPA has the authority under NSPS 

to require a particular technology or 

design as a performance standard. The 

commenter contends that the EPA 

should not mandate a particular 

technology, but rather allow companies 

to choose the technology to best meet 

the emission standard. 

One state agency commenter believes 

that specifying design requirements in 

regulations will stifle innovation and 

create a plateau for new products. The 

commenter believes that such 

restrictions will not allow for economic 

or technological creation of new 

methods or equipment. The commenter 

further states that, as the industry grows 

and changes, so too should the facilities 

and equipment associated with it, but 

prescriptive design requirements would 

not allow this to happen. Also, 

according to the commenter, due to high 

variability of materials and situations in 

the field it seems illogical and 

inappropriate to deem only certain 

designs of facilities and equipment 

acceptable or not. The commenter 

contends that design requirements 

specified by rule could cause certain 

facilities or regions to be unable to 

implement engineering solutions 

necessary to account for site- or regionspecific conditions. 

Response: The EPA appreciates the 

information provided by these 

commenters in response to the EPA’s 

solicitation of comment on whether the 

NSPS should include design 

requirements for storage vessels, closed 

vent system and control devices. In the 

preamble to the proposed rule, we had 

solicited comment on whether the EPA 

should require that storage vessel 

installations and associated controls be 

sized and designed properly for specific 

applications to minimize excess 

emissions due to improperly sized and 

designed storage vessels or control 

systems. We did not solicit comment on 

whether the EPA should require specific 

technology or design parameters. 

Accordingly, because the 

reconsideration proposal did not 

include any specific design 

requirements for storage vessels and 

associated closed vent systems and 

control device, no such requirement is 

included in the final amendments. 

F. Major Comments Concerning Impacts 

Comment: One commenter contends 

that the EPA failed to assess the air 

quality impacts of its proposed 

amendments and the EPA must provide 

further analysis of air quality impacts to 

support that the proposed revised 

standards is BSER. According to the 

commenter’s analysis, Group 1 storage 

vessels that do not experience an event 

that would increase emissions would 

result in an increase from the final 

NSPS in VOC emissions of over 3 

million tpy and methane emissions of 

over 700,000 tpy. In addition, the 

commenter states that the six-month 

delay of the compliance date for Group 

2 storage vessels results in an increases 

of 450,000 tpy of VOC emissions and 

100,000 tpy of methane emissions. The 

commenter added that the removal of a 

control device from sources whose 

uncontrolled emissions drop below 4 

tpy would result in an emission increase 

of 3.8 tpy VOC per vessel. Assuming 

that the 11,600 new vessels the EPA 

projects would qualify for the 

uncontrolled actual VOC emission rate, 

emissions would increase by 23,000 tpy 

VOC and 5,000 tpy methane. The 

commenter also contends that the 

removal of the control device would 

result in sources left uncontrolled 

during any unplanned events that 

would generate significant emissions. 

Additionally, the commenter states that 

using their decline curve analysis, new 

sources would not qualify for 

uncontrolled actual VOC emission rate 

for at least 14 years, and the increase in 

pollution is not justified by the EPA’s 

control device availability concerns. 

Response: As we discussed in section 

IV.A of this preamble, we are not 

finalizing our proposal to subject only 

those Group 1 storage vessels that 

experience an event to the emission 

standards. Thus, all Group 1 storage 

vessel affected facilities will be subject 

to the emission standards, as required 

under the 2012 NSPS. We believe this 

addresses the commenters’ concerns 

about any increase in emissions based 

on our proposal to require Group 1 to 

control only if there is a subsequent 

emission increase event. The 

commenter is also concerned with 

emission increase from delayed 

compliance. However, we believe that 

the extended deadlines in the final 

amendments are justified for the reasons 

stated in section IV.A, and we are 

phasing the compliance deadlines to 

address facilities with projected higher 

emissions more quickly. 

We have also provided further 

analysis of air quality impacts, as the 

commenter suggests, as well as the cost 

effectiveness and energy impact 

associated with the proposed 

uncontrolled emission rate of less than 

4 tpy. As discussed in more detail in 

section V.C of this preamble, 4 tpy 

likely represents a point below which 

control ceases to be the BSER for 

reducing VOC emissions from storage 

vessel affected facilities due to the cost 

effectiveness, the secondary 

environmental impact and energy 

impact. 

VI. Technical Corrections and 

Clarifications 

The EPA is finalizing corrections to 

recordkeeping and reporting 

requirements for all affected facilities. In 

addition, the final amendments include 

corrections that are editorial in nature, 

such as typographical and grammatical 

errors, as well as incorrect crossreferences. 

VII. Impacts of These Final 

Amendments 

Our analysis shows that owners and 

operators of storage vessel affected 

facilities would choose to install and 

operate the same or similar air pollution 

control technologies under the proposed 

standards as would have been necessary 

to meet the previously finalized 

standards. We project that this rule will 

result in no significant change in costs, 

emission reductions, or benefits. Even if 

there were changes in costs for these 

units, such changes would likely be 

small relative to both the overall costs 

of the individual projects and the 

overall costs and benefits of the final 

rule. Since we believe that owners and 

operators would put on the same 


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controls for this revised final rule that 

they would have for the original final 

rule, there should not be any 

incremental costs related to this 

proposed revision. 

A. What are the air impacts? 

We believe that owners and operators 

of storage vessel affected facilities will 

install the same or similar control 

technologies to comply with the revised 

standards finalized in this action as they 

would have installed to comply with the 

previously finalized standards. 

Accordingly, we believe that this final 

rule will not result in significant 

changes in emissions of any of the 

regulated pollutants. 

B. What are the energy impacts? 

This final rule is not anticipated to 

have an effect on the supply, 

distribution, or use of energy. As 

previously stated, we believe that 

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. 

C. What are the compliance costs? 

We believe there will be no significant 

change in compliance costs as a result 

of this final 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. 

However, we note that there likely will 

be reductions of costs imposed on 

owners and operators associated with 

the streamlined compliance monitoring 

procedures provided in the final 

amendments. 

D. What are the economic and 

employment impacts? 

Because 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 

previously finalized standards, we do 

not anticipate that this final rule will 

result in significant changes in 

emissions, energy impacts, costs, 

benefits, or economic impacts. Likewise, 

we believe this rule will not have any 

impacts on the price of electricity, 

employment or labor markets, or the 

U.S. economy. 

E. What are the benefits of the proposed 

standards? 

As previously stated, the EPA 

anticipates the oil and natural gas sector 

will not incur significant compliance 

costs or savings as a result of this rule 

and we do not anticipate any significant 

emission changes resulting from this 

rule. Therefore, there are no direct 

monetized benefits or disbenefits 

associated with this rule. 

VIII. Statutory and Executive Order 

Reviews 

A. Executive Order 12866: Regulatory 

Planning and Review and Executive 

Order 13563: Improving Regulation and 

Regulatory Review 

This action is not a ‘‘significant 

regulatory action’’ under the terms of 

Executive Order 12866 (58 FR 51735, 

October 4, 1993) and is therefore not 

subject to review under Executive 

Orders 12866 and 13563 (76 FR 3821, 

January 21, 2011). 

An RIA was prepared for the April 

2012 NSPS and can be found at: 

http://www.epa.gov/ttn/ecas/regdata/

RIAs/oil_natural_gas_final_neshap_

nsps_ria.pdf. This final rule will not 

result in a significant change in costs, 

emission reductions, or benefits in 2015 

(the year of full implementation of the 

2012 NSPS being amended with this 

action). 

B. Paperwork Reduction Act 

This action does not impose any new 

information collection burden. This 

action does not change the information 

collection requirements previously 

finalized under the 2012 NSPS and, as 

a result, does not impose any additional 

burden on industry. However, OMB has 

previously approved the information 

collection requirements contained in the 

existing regulations (see 77 FR 49490) 

under the provisions of the Paperwork 

Reduction Act, 44 U.S.C. 3501 et seq. 

and has assigned OMB control number 

2060–0673). The OMB control numbers 

for the EPA’s regulations are listed in 40 

CFR part 9 and 48 CFR chapter 15. 

C. Regulatory Flexibility Act 

The Regulatory Flexibility Act (RFA) 

generally requires an agency to prepare 

a regulatory flexibility analysis of any 

rule subject to notice and comment 

rulemaking requirements under the 

Administrative Procedure Act or any 

other statute unless the agency certifies 

that the rule will not have a significant 

economic impact on a substantial 

number of small entities. Small entities 

include small businesses, small 

organizations, and small governmental 

jurisdictions. 

For purposes of assessing the impacts 

of this rule on small entities, a small 

entity is defined as: (1) A small business 

in the oil or natural gas industry whose 

parent company has no more than 500 

employees (or revenues of less than $7 

million for firms that transport natural 

gas via pipeline); (2) a small 

governmental jurisdiction that is a 

government of a city, county, town, 

school district, or special district with a 

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

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

owned and operated and is not 

dominant in its field. 

After considering the economic 

impacts of today’s final rule on small 

entities, I certify that this action will not 

have a significant economic impact on 

a substantial number of small entities. 

The EPA has determined that none of 

the small entities will experience a 

significant impact because these final 

amendments will not impose additional 

compliance costs on owners or 

operators of affected facilities. 

D. Unfunded Mandates Reform Act 

This action contains no federal 

mandates under the provisions of Title 

II of the Unfunded Mandates Reform 

Act of 1995 (UMRA), 2 U.S.C. 1531– 

1538 for State, local, or tribal 

governments or the private sector. This 

action imposes no enforceable duty on 

any state, local or tribal governments or 

the private sector. Therefore, this action 

is not subject to the requirements of 

sections 202 or 205 of the UMRA. 

This action is also not subject to the 

requirements of section 203 of UMRA 

because it contains no regulatory 

requirements that might significantly or 

uniquely affect small governments. This 

action contains no requirements that 

apply to small governments nor does it 

impose obligations upon them. 

E. Executive Order 13132: Federalism 

This action does not have federalism 

implications. It will not have substantial 

direct effects on the states, on the 

relationship between the national 

government and the states, or on the 

distribution of power and 

responsibilities among the various 

levels of government, as specified in 

Executive Order 13132. This final rule 

is a reconsideration of an existing rule 

and imposes no new impacts or costs. 

Thus, Executive Order 13132 does not 

apply to this action. 

In the spirit of Executive Order 13132, 

and consistent with the EPA policy to 

promote communications between the 

EPA and state and local governments, 

the EPA specifically solicited comment 

on the proposed action from state and 

local officials. 


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F. Executive Order 13175: Consultation 

and Coordination With Indian Tribal 

Governments 

This action does not have tribal 

implications, as specified in Executive 

Order 13175 (65 FR 67249, November 9, 

2000). It will not have substantial direct 

effect on tribal governments, on the 

relationship between the federal 

government and tribal governments or 

on the distribution of power and 

responsibilities between the federal 

government and tribal governments, as 

specified in Executive Order 13175. 

Thus, Executive Order 13175 does not 

apply to this action. 

In the spirit of Executive Order 13175, 

and consistent with the EPA policy to 

promote communications between the 

EPA and tribal governments, the EPA 

specifically solicited comment on the 

proposed action from tribal officials. 

The EPA notes that significant oil and 

natural gas development is occurring on 

some tribal lands and has been mindful 

of this in consideration of these final 

amendments. 

G. Executive Order 13045: Protection of 

Children From Environmental Health 

and Safety Risks 

This action is not subject to EO 13045 

(62 FR 19885, April 23, 1997) because 

it is not economically significant as 

defined in EO 12866, and because the 

agency does not believe the 

environmental health risks or safety 

risks addressed by this action present a 

disproportionate risk to children. This 

final rule will not result in a significant 

change in emission reductions and 

benefits in 2015, the year of full 

implementation of the 2012 NSPS being 

amended with this action. Therefore, 

health and risk assessments were not 

conducted. 

The public was invited to submit 

comments or identify peer-reviewed 

studies and data that assess effects of 

early life exposure to HAP from oil and 

natural gas sector activities. 

H. Executive Order 13211: Actions 

Concerning Regulations That 

Significantly Affect Energy Supply, 

Distribution, or Use 

This action is not subject to Executive 

Order 13211 (66 FR 28355 (May 22, 

2001)), because it is not a significant 

regulatory action under Executive Order 

12866. 

I. National Technology Transfer and 

Advancement Act 

Section 12(d) of the National 

Technology Transfer and Advancement 

Act of 1995 (‘‘NTTAA’’), Public Law 

104–113, 12(d) (15 U.S.C. 272 note) 

directs the EPA to use voluntary 

consensus standards in its regulatory 

activities unless to do so would be 

inconsistent with applicable law or 

otherwise impractical. Voluntary 

consensus standards are technical 

standards (e.g., materials specifications, 

test methods, sampling procedures, and 

business practices) that are developed or 

adopted by voluntary consensus 

standards bodies. The NTTAA directs 

the EPA to provide Congress, through 

OMB, explanations when the agency 

decides not to use available and 

applicable voluntary consensus 

standards. 

This final rule does not involve 

technical standards. Therefore, the EPA 

is not considering the use of any 

voluntary consensus standards. 

J. Executive Order 12898: Federal 

Actions To Address Environmental 

Justice in Minority Populations and 

Low-Income Populations 

Executive Order (EO) 12898 (59 FR 

7629 (Feb. 16, 1994)) establishes federal 

executive policy on environmental 

justice. Its main provision directs 

federal agencies, to the greatest extent 

practicable and permitted by law, to 

make environmental justice part of their 

mission by identifying and addressing, 

as appropriate, disproportionately high 

and adverse human health or 

environmental effects of their programs, 

policies, and activities on minority 

populations and low-income 

populations in the United States. 

The EPA has determined that this 

final rule will not have 

disproportionately high and adverse 

human health or environmental effects 

on minority, low-income, or indigenous 

populations because it does not affect 

the level of human health or 

environmental protection for all affected 

populations. This final rule is a 

reconsideration of an existing rule and 

imposes no new impacts or costs. 

Therefore, this final rule would not have 

any disproportionately high and adverse 

human health or environmental effects 

on any population, including any 

minority, low income or indigenous 

populations. 

K. Congressional Review Act 

The Congressional Review Act, 5 

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

Business Regulatory Enforcement 

Fairness Act of 1996, generally provides 

that before a rule may take effect, the 

agency promulgating the rule must 

submit a rule report, which includes a 

copy of the rule, to each House of 

Congress and to the Comptroller General 

of the United States. The EPA will 

submit a report containing this rule and 

other required information to the U.S. 

Senate, the U.S. House of 

Representatives, and the Comptroller 

General of the United States prior to 

publication of the rule in the Federal 

Register. A major rule cannot take effect 

until 60 days after it is published in the 

Federal Register. This action is not a 

‘‘major rule’’ as defined by 5 U.S.C. 

804(2). This rule will be effective 

September 23, 2013. 

List of Subjects in 40 CFR Part 60 

Administrative practice and 

procedure, Air pollution control, 

Intergovernmental relations, Reporting 

and recordkeeping. 

Dated: August 2, 2013. 

Gina McCarthy, 

Administrator. 

For the reasons set out in the 

preamble, title 40, chapter I of the Code 

of Federal Regulations is amended as 

follows: 

PART 60—STANDARDS OF 

PERFORMANCE FOR NEW 

STATIONARY SOURCES 

■ 1. The authority citation for part 60 

continues to read as follows: 

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

Subpart OOOO—[Amended] 

■ 2. Section 60.5365 is amended by 

revising paragraphs (e) and (h)(4) to read 

as follows: 

§ 60.5365 Am I subject to this subpart? 

* * * * * 

(e) Each storage vessel affected 

facility, which is a single storage vessel 

located in the oil and natural gas 

production segment, natural gas 

processing segment or natural gas 

transmission and storage segment, and 

has the potential for VOC emissions 

equal to or greater than 6 tpy as 

determined according to this section by 

October 15, 2013 for Group 1 storage 

vessels and by April 15, 2014, or 30 

days after startup (whichever is later) for 

Group 2 storage vessels. A storage vessel 

affected facility that subsequently has 

its potential for VOC emissions decrease 

to less than 6 tpy shall remain an 

affected facility under this subpart. The 

potential for VOC emissions must be 

calculated using a generally accepted 

model or calculation methodology, 

based on the maximum average daily 

throughput determined for a 30-day 

period of production prior to the 

applicable emission determination 

deadline specified in this section. The 

determination may take into account 

requirements under a legally and 

practically enforceable limit in an 

operating permit or other requirement 


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established under a Federal, State, local 

or tribal authority. Any vapor from the 

storage vessel that is recovered and 

routed to a process through a VRU 

designed and operated as specified in 

this section is not required to be 

included in the determination of VOC 

potential to emit for purposes of 

determining affected facility status, 

provided you comply with the 

requirements in paragraphs (e)(1) 

through (4) of this section. 

(1) You meet the cover requirements 

specified in § 60.5411(b). 

(2) You meet the closed vent system 

requirements specified in § 60.5411(c). 

(3) You maintain records that 

document compliance with paragraphs 

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

(4) In the event of removal of 

apparatus that recovers and routes vapor 

to a process, or operation that is 

inconsistent with the conditions 

specified in paragraphs (e)(1) and (2) of 

this section, you must determine the 

storage vessel’s potential for VOC 

emissions according to this section 

within 30 days of such removal or 

operation. 

* * * * * 

(h) * * * 

(4) A gas well facility initially 

constructed after August 23, 2011, is 

considered an affected facility 

regardless of this provision. 

■ 3. Section 60.5380 is amended by 

revising paragraphs (a)(2), (b), and (c) to 

read as follows: 

§ 60.5380 What standards apply to 

centrifugal compressor affected facilities? 

* * * * * 

(a) * * * 

(2) If you use a control device to 

reduce emissions, you must equip the 

wet seal fluid degassing system with a 

cover that meets the requirements of 

§ 60.5411(b), that is connected through 

a closed vent system that meets the 

requirements of § 60.5411(a) and routed 

to a control device that meets the 

conditions specified in § 60.5412(a), (b) 

and (c). As an alternative to routing the 

closed vent system to a control device, 

you may route the closed vent system to 

a process. 

(b) You must demonstrate initial 

compliance with the standards that 

apply to centrifugal compressor affected 

facilities as required by § 60.5410(b). 

(c) You must demonstrate continuous 

compliance with the standards that 

apply to centrifugal compressor affected 

facilities as required by § 60.5415(b). 

* * * * * 

■ 4. Section 60.5390 is amended by: 

■ a. Revising the introductory text; 

■ b. Revising paragraph (a); and 

■ c. Revising paragraph (c). 

The revisions read as follows: 

§ 60.5390 What standards apply to 

pneumatic controller affected facilities? 

For each pneumatic controller 

affected facility you must comply with 

the VOC standards, based on natural gas 

as a surrogate for VOC, in either 

paragraph (b)(1) or (c)(1) of this section, 

as applicable. Pneumatic controllers 

meeting the conditions in paragraph (a) 

of this section are exempt from this 

requirement. 

(a) The requirements of paragraph 

(b)(1) or (c)(1) of this section are not 

required if you determine that the use 

of a pneumatic controller affected 

facility with a bleed rate greater than the 

applicable standard is required based on 

functional needs, including but not 

limited to response time, safety and 

positive actuation. However, you must 

tag such pneumatic controller with the 

month and year of installation, 

reconstruction or modification, and 

identification information that allows 

traceability to the records for that 

pneumatic controller, as required in 

§ 60.5420(c)(4)(ii). 

* * * * * 

(c)(1) Each pneumatic controller 

affected facility constructed, modified 

or reconstructed on or after October 15, 

2013, at a location between the 

wellhead and a natural gas processing 

plant or the point of custody transfer to 

an oil pipeline must have a bleed rate 

less than or equal to 6 standard cubic 

feet per hour. 

(2) Each pneumatic controller affected 

facility at a location between the 

wellhead and a natural gas processing 

plant or the point of custody transfer to 

an oil pipeline must be tagged with the 

month and year of installation, 

reconstruction or modification, and 

identification information that allows 

traceability to the records for that 

controller as required in 

§ 60.5420(c)(4)(iii). 

* * * * * 

■ 5. Section 60.5395 is revised to read 

as follows: 

§ 60.5395 What standards apply to storage 

vessel affected facilities? 

Except as provided in paragraph (h) of 

this section, you must comply with the 

standards in this section for each storage 

vessel affected facility. 

(a)(1) If you are the owner or operator 

of a Group 1 storage vessel affected 

facility, you must comply with 

paragraph (b) of this section. 

(2) If you are the owner or operator of 

a Group 2 storage vessel affected 

facility, you must comply with 

paragraph (c) of this section. 

(b) Requirements for Group 1 storage 

vessel affected facilities. If you are the 

owner or operator of a Group 1 storage 

vessel affected facility, you must 

comply with paragraphs (b)(1) and (2) of 

this section. 

(1) You must submit a notification 

identifying each Group 1 storage vessel 

affected facility, including its location, 

with your initial annual report as 

specified in § 60.5420(b)(6)(iv). 

(2) You must comply with paragraphs 

(d) through (g) of this section. 

(c) Requirements for Group 2 storage 

vessel affected facilities. If you are the 

owner or operator of a Group 2 storage 

vessel affected facility, you must 

comply with paragraphs (d) through (g) 

of this section. 

(d) You must comply with the control 

requirements of paragraph (d)(1) of this 

section unless you meet the conditions 

specified in paragraph (d)(2) of this 

section. 

(1) Reduce VOC emissions by 95.0 

percent according to the schedule 

specified in (d)(1)(i) and (ii) of this 

section. 

(i) For each Group 2 storage vessel 

affected facility, you must achieve the 

required emissions reductions by April 

15, 2014, or within 60 days after startup, 

whichever is later. 

(ii) For each Group 1 storage vessel 

affected facility, you must achieve the 

required emissions reductions by April 

15, 2015. 

(2) Maintain the uncontrolled actual 

VOC emissions from the storage vessel 

affected facility at less than 4 tpy 

without considering control. Prior to 

using the uncontrolled actual VOC 

emission rate for compliance purposes, 

you must demonstrate that the 

uncontrolled actual VOC emissions 

have remained less than 4 tpy as 

determined monthly for 12 consecutive 

months. After such demonstration, you 

must determine the uncontrolled actual 

VOC emission rate each month. The 

uncontrolled actual VOC emissions 

must be calculated using a generally 

accepted model or calculation 

methodology. Monthly calculations 

must be based on the average 

throughput for the month. Monthly 

calculations must be separated by at 

least 14 days. You must comply with 

paragraph (d)(1) of this section if your 

storage vessel affected facility meets the 

conditions specified in paragraphs 

(d)(2)(i) or (ii) of this section. 

(i) If a well feeding the storage vessel 

affected facility undergoes fracturing or 

refracturing, you must comply with 

paragraph (d)(1) of this section as soon 

as liquids from the well following 

fracturing or refracturing are routed to 

the storage vessel affected facility. 


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(ii) If the monthly emissions 

determination required in this section 

indicates that VOC emissions from your 

storage vessel affected facility increase 

to 4 tpy or greater and the increase is 

not associated with fracturing or 

refracturing of a well feeding the storage 

vessel affected facility, you must 

comply with paragraph (d)(1) of this 

section within 30 days of the monthly 

calculation. 

(e) Control requirements. (1) Except as 

required in paragraph (e)(2) of this 

section, if you use a control device to 

reduce emissions from your storage 

vessel affected facility, 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), and you must route 

emissions to a control device that meets 

the conditions specified in § 60.5412(c) 

and (d). As an alternative to routing the 

closed vent system to a control device, 

you may route the closed vent system to 

a process. 

(2) If you use a floating roof to reduce 

emissions, you must meet the 

requirements of § 60.112b(a)(1) or (2) 

and the relevant monitoring, inspection, 

recordkeeping, and reporting 

requirements in 40 CFR part 60, subpart 

Kb. 

(f) Requirements for storage vessel 

affected facilities that are removed from 

service. If you are the owner or operator 

of a storage vessel affected facility that 

is removed from service, you must 

comply with paragraphs (f)(1) and (2) of 

this section. 

(1) You must submit a notification in 

your next annual report, identifying all 

storage vessel affected facilities removed 

from service during the reporting 

period. 

(2) If the storage vessel affected 

facility identified in paragraph (f)(1) of 

this section is returned to service, you 

must comply with paragraphs (f)(2)(i) 

through (iii) of this section. 

(i) If returning your storage vessel 

affected facility to service is associated 

with fracturing or refracturing of a well 

feeding the storage vessel affected 

facility, you must comply with 

paragraph (d) of this section 

immediately upon returning the storage 

vessel to service. 

(ii) If returning your storage vessel 

affected facility to service is not 

associated with a well that was 

fractured or refractured, you must 

comply with paragraphs (f)(2)(ii)(A) and 

(B) of this section. 

(A) You must determine emissions as 

specified in § 60.5365(e) within 30 days 

of returning your storage vessel affected 

facility to service. 

(B) If the uncontrolled VOC emissions 

without considering control from your 

storage vessel affected facility are 4 tpy 

or greater, you must comply with 

paragraph (d) of this section within 60 

days of returning to service. 

(iii) You must submit a notification in 

your next annual report identifying each 

storage vessel affected facility that has 

been returned to service. 

(g) Compliance, notification, 

recordkeeping, and reporting. You must 

comply with paragraphs (g)(1) through 

(3) of this section. 

(1) You must demonstrate initial 

compliance with standards as required 

by § 60.5410(h) and (i). 

(2) You must demonstrate continuous 

compliance with standards as required 

by § 60.5415(e)(3). 

(3) You must perform the required 

notification, recordkeeping and 

reporting as required by § 60.5420. 

(h) Exemptions. This subpart does not 

apply to storage vessels subject to and 

controlled in accordance with the 

requirements for storage vessels in 40 

CFR part 60, subpart Kb, 40 CFR part 63, 

subparts G, CC, HH, or WW. 

■ 6. Section 60.5410 is amended by: 

■ a. Revising the introductory text; 

■ b. Revising paragraphs (a)(3) and (4); 

■ c. Revising paragraphs (b)(2) through 

(5); 

■ d. Revising paragraphs (b)(7) and (8); 

■ e. Removing and reserving paragraph 

(c)(2); 

■ f. Revising paragraphs (d) 

introductory text, (d)(1), (d)(2), and 

(d)(4); 

■ g. Removing and reserving paragraph 

(e); and 

■ h. Adding paragraphs (h) and (i). 

The revisions and additions read as 

follows: 

§ 60.5410 How do I demonstrate initial 

compliance with the standards for my gas 

well affected facility, my centrifugal 

compressor affected facility, my 

reciprocating compressor affected facility, 

my pneumatic controller affected facility, 

my storage vessel affected facility, and my 

equipment leaks and sweetening unit 

affected facilities at onshore natural gas 

processing plants? 

You must determine initial 

compliance with the standards for each 

affected facility using the requirements 

in paragraphs (a) through (i) of this 

section. The initial compliance period 

begins on October 15, 2012, or upon 

initial startup, whichever is later, and 

ends no later than one year after the 

initial startup date for your affected 

facility or no later than one year after 

October 15, 2012. The initial 

compliance period may be less than one 

full year. 

(a) * * * 

(3) You must maintain a log of records 

as specified in § 60.5420(c)(1)(i) through 

(iv) for each well completion operation 

conducted during the initial compliance 

period. 

(4) For each gas well affected facility 

subject to both § 60.5375(a)(1) and (3), 

as an alternative to retaining the records 

specified in § 60.5420(c)(1)(i) through 

(iv), you may maintain records of one or 

more digital photographs with the date 

the photograph was taken and the 

latitude and longitude of the well site 

imbedded within or stored with the 

digital file showing the equipment for 

storing or re-injecting recovered liquid, 

equipment for routing recovered gas to 

the gas flow line and the completion 

combustion device (if applicable) 

connected to and operating at each gas 

well completion operation that occurred 

during the initial compliance period. As 

an alternative to imbedded latitude and 

longitude within the digital photograph, 

the digital photograph may consist of a 

photograph of the equipment connected 

and operating at each well completion 

operation with a photograph of a 

separately operating GIS device within 

the same digital picture, provided the 

latitude and longitude output of the GIS 

unit can be clearly read in the digital 

photograph. 

(b) * * * 

(2) If you use a control device to 

reduce emissions, you must equip the 

wet seal fluid degassing system with a 

cover that meets the requirements of 

§ 60.5411(b) that is connected through a 

closed vent system that meets the 

requirements of § 60.5411(a) and is 

routed to a control device that meets the 

conditions specified in § 60.5412(a), (b) 

and (c). As an alternative to routing the 

closed vent system to a control device, 

you may route the closed vent system to 

a process. 

(3) You must conduct an initial 

performance test as required in 

§ 60.5413 within 180 days after initial 

startup or by October 15, 2012, 

whichever is later, and you must 

comply with the continuous compliance 

requirements in § 60.5415(b)(1) through 

(3). 

(4) You must conduct the initial 

inspections required in § 60.5416(a) and 

(b). 

(5) You must install and operate the 

continuous parameter monitoring 

systems in accordance with § 60.5417(a) 

through (g), as applicable. 

* * * * * 

(7) You must submit the initial annual 

report for your centrifugal compressor 

affected facility as required in 

§ 60.5420(b)(3) for each centrifugal 

compressor affected facility. 


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(8) You must maintain the records as 

specified in § 60.5420(c)(2). 

(c) * * * 

(2) [Reserved] 

* * * * * 

(d) To achieve initial compliance with 

emission standards for your pneumatic 

controller affected facility you must 

comply with the requirements specified 

in paragraphs (d)(1) through (6) of this 

section, as applicable. 

(1) You must demonstrate initial 

compliance by maintaining records as 

specified in § 60.5420(c)(4)(ii) of your 

determination that the use of a 

pneumatic controller affected facility 

with a bleed rate greater than 6 standard 

cubic feet of gas per hour is required as 

specified in § 60.5390(a). 

(2) You own or operate a pneumatic 

controller affected facility located at a 

natural gas processing plant and your 

pneumatic controller is driven by a gas 

other than natural gas and therefore 

emits zero natural gas. 

* * * * * 

(4) You must tag each new pneumatic 

controller affected facility according to 

the requirements of § 60.5390(b)(2) or 

(c)(2). 

* * * * * 

(e) [Reserved] 

* * * * * 

(h) For each storage vessel affected 

facility, you must comply with 

paragraphs (h)(1) through (5) of this 

section. For a Group 1 storage vessel 

affected facility, you must demonstrate 

initial compliance by April 15, 2015, 

except as otherwise provided in 

paragraph (i) of this section. For a Group 

2 storage vessel affected facility, you 

must demonstrate initial compliance by 

April 15, 2014, or within 60 days after 

startup, whichever is later. 

(1) You must determine the potential 

VOC emission rate as specified in 

§ 60.5365(e). 

(2) You must reduce VOC emissions 

in accordance with § 60.5395(d). 

(3) If you use a control device to 

reduce emissions, or if you route 

emissions to a process, you must 

demonstrate initial compliance by 

meeting the requirements in 

§ 60.5395(e). 

(4) You must submit the information 

required for your storage vessel affected 

facility as specified in § 60.5420(b). 

(5) You must maintain the records 

required for your storage vessel affected 

facility, as specified in § 60.5420(c)(5) 

through (8) and § 60.5420(c)(12) and 

(13) for each storage vessel affected 

facility. 

(i) For each Group 1 storage vessel 

affected facility, you must submit the 

notification specified in § 60.5395(b)(2) 

with the initial annual report specified 

in § 60.5420(b)(6). 

■ 7. Section 60.5411 is amended by: 

■ a. Revising the section heading; 

■ b. Revising paragraphs (a) 

introductory text, (a)(1), and (a)(3)(i)(A); 

■ c. Revising the heading of paragraph 

(b), and paragraphs (b)(1) and (b)(2)(iv); 

■ d. Adding paragraph (b)(3); and 

■ e. Adding paragraph (c). 

The revisions and additions read as 

follows: 

§ 60.5411 What additional requirements 

must I meet to determine initial compliance 

for my covers and closed vent systems 

routing materials from storage vessels and 

centrifugal compressor wet seal degassing 

systems? 

* * * * * 

(a) Closed vent system requirements 

for centrifugal compressor wet seal 

degassing systems. (1) You must design 

the closed vent system to route all gases, 

vapors, and fumes emitted from the 

material in the wet seal fluid degassing 

system to a control device or to a 

process that meets the requirements 

specified in § 60.5412(a) through (c). 

* * * * * 

(3) * * * 

(i) * * * 

(A) You must properly install, 

calibrate, maintain, and operate a flow 

indicator at the inlet to the bypass 

device that could divert the stream away 

from the control device or process to the 

atmosphere that is capable of taking 

periodic readings as specified in 

§ 60.5416(a)(4) and sounds an alarm 

when the bypass device is open such 

that the stream is being, or could be, 

diverted away from the control device 

or process to the atmosphere. 

* * * * * 

(b) Cover requirements for storage 

vessels and centrifugal compressor wet 

seal degassing systems. (1) The cover 

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

access hatches, sampling ports, pressure 

relief valves and gauge wells) shall form 

a continuous impermeable barrier over 

the entire surface area of the liquid in 

the storage vessel or wet seal fluid 

degassing system. 

(2) * * * 

(iv) To vent liquids, gases, or fumes 

from the unit through a closed-vent 

system designed and operated in 

accordance with the requirements of 

paragraph (a) or (c) of this section to a 

control device or to a process. 

(3) Each storage vessel thief hatch 

shall be weighted and properly seated. 

You must select gasket material for the 

hatch based on composition of the fluid 

in the storage vessel and weather 

conditions. 

(c) Closed vent system requirements 

for storage vessel affected facilities 

using a control device or routing 

emissions to a process. (1) You must 

design the closed vent system to route 

all gases, vapors, and fumes emitted 

from the material in the storage vessel 

to a control device that meets the 

requirements specified in § 60.5412(c) 

and (d), or to a process. 

(2) You must design and operate a 

closed vent system with no detectable 

emissions, as determined using 

olfactory, visual and auditory 

inspections. Each closed vent system 

that routes emissions to a process must 

be operational 95 percent of the year or 

greater. 

(3) You must meet the requirements 

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

of this section if the closed vent system 

contains one or more bypass devices 

that could be used to divert all or a 

portion of the gases, vapors, or fumes 

from entering the control device or to a 

process. 

(i) Except as provided in paragraph 

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

comply with either paragraph 

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

bypass device. 

(A) You must properly install, 

calibrate, maintain, and operate a flow 

indicator at the inlet to the bypass 

device that could divert the stream away 

from the control device or process to the 

atmosphere that sounds an alarm, or, 

initiates notification via remote alarm to 

the nearest field office, when the bypass 

device is open such that the stream is 

being, or could be, diverted away from 

the control device or process to the 

atmosphere. 

(B) You must secure the bypass device 

valve installed at the inlet to the bypass 

device in the non-diverting position 

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

configuration. 

(ii) Low leg drains, high point bleeds, 

analyzer vents, open-ended valves or 

lines, and safety devices are not subject 

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

of this section. 

■ 8. Section 60.5412 is amended by: 

■ a. Revising paragraphs (a) 

introductory text, (a)(1) introductory 

text, and (a)(2); 

■ b. Revising paragraph (b); 

■ c. Revising paragraphs (c) 

introductory text and (c)(1); and 

■ d. Adding paragraph (d). 

The revisions and addition read as 

follows: 

§ 60.5412 What additional requirements 

must I meet for determining initial 

compliance with control devices used to 

comply with the emission standards for my 

storage vessel or centrifugal compressor 

affected facility? 

* * * * * 


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(a) Each control device used to meet 

the emission reduction standard in 

§ 60.5380(a)(1) for your centrifugal 

compressor affected facility must be 

installed according to paragraphs (a)(1) 

through (3) of this section. As an 

alternative, you may install a control 

device model tested under § 60.5413(d), 

which meets the criteria in 

§ 60.5413(d)(11) and § 60.5413(e). 

(1) Each combustion device (e.g., 

thermal vapor incinerator, catalytic 

vapor incinerator, boiler, or process 

heater) must be designed and operated 

in accordance with one of the 

performance requirements specified in 

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

section. 

* * * * * 

(2) Each vapor recovery device (e.g., 

carbon adsorption system or condenser) 

or other non-destructive control device 

must be designed and operated to 

reduce the mass content of VOC in the 

gases vented to the device by 95.0 

percent by weight or greater as 

determined in accordance with the 

requirements of § 60.5413. As an 

alternative to the performance testing 

requirements, you may demonstrate 

initial compliance by conducting a 

design analysis for vapor recovery 

devices according to the requirements of 

§ 60.5413(c). 

* * * * * 

(b) You must operate each control 

device installed on your centrifugal 

compressor affected facility in 

accordance with the requirements 

specified in paragraphs (b)(1) and (2) of 

this section. 

(1) You must operate each control 

device used to comply with this subpart 

at all times when gases, vapors, and 

fumes are vented from the wet seal fluid 

degassing system affected facility, as 

required under § 60.5380(a), through the 

closed vent system to the control device. 

You may vent more than one affected 

facility to a control device used to 

comply with this subpart. 

(2) For each control device monitored 

in accordance with the requirements of 

§ 60.5417(a) through (g), you must 

demonstrate compliance according to 

the requirements of § 60.5415(b)(2), as 

applicable. 

(c) For each carbon adsorption system 

used as a control device to meet the 

requirements of paragraph (a)(2) or 

(d)(2) of this section, you must manage 

the carbon in accordance with the 

requirements specified in paragraphs 

(c)(1) or (2) of this section. 

(1) Following the initial startup of the 

control device, you must replace all 

carbon in the control device with fresh 

carbon on a regular, predetermined time 

interval that is no longer than the 

carbon service life established according 

to § 60.5413(c)(2) or (3) or according to 

the design required in paragraph (d)(2) 

of this section, for the carbon adsorption 

system. You must maintain records 

identifying the schedule for replacement 

and records of each carbon replacement 

as required in § 60.5420(c)(10) and (12). 

* * * * * 

(d) Each control device used to meet 

the emission reduction standard in 

§ 60.5395(d) for your storage vessel 

affected facility must be installed 

according to paragraphs (d)(1) through 

(3) of this section, as applicable. As an 

alternative, you may install a control 

device model tested under § 60.5413(d), 

which meets the criteria in 

§ 60.5413(d)(11) and § 60.5413(e). 

(1) Each enclosed combustion device 

(e.g., thermal vapor incinerator, catalytic 

vapor incinerator, boiler, or process 

heater) must be designed to reduce the 

mass content of VOC emissions by 95.0 

percent or greater. You must follow the 

requirements in paragraphs (d)(1)(i) 

through (iii) of this section. 

(i) Ensure that each enclosed 

combustion device is maintained in a 

leak free condition. 

(ii) Install and operate a continuous 

burning pilot flame. 

(iii) Operate the enclosed combustion 

device with no visible emissions, except 

for periods not to exceed a total of one 

minute during any 15 minute period. A 

visible emissions test using section 11 of 

EPA Method 22, 40 CFR part 60, 

appendix A, must be performed at least 

once every calendar month, separated 

by at least 15 days between each test. 

The observation period shall be 15 

minutes. Devices failing the visible 

emissions test must follow 

manufacturer’s repair instructions, if 

available, or best combustion 

engineering practice as outlined in the 

unit inspection and maintenance plan, 

to return the unit to compliant 

operation. All inspection, repair and 

maintenance activities for each unit 

must be recorded in a maintenance and 

repair log and must be available for 

inspection. Following return to 

operation from maintenance or repair 

activity, each device must pass a 

Method 22, 40 CFR part 60, appendix A, 

visual observation as described in this 

paragraph. 

(2) Each vapor recovery device (e.g., 

carbon adsorption system or condenser) 

or other non-destructive control device 

must be designed and operated to 

reduce the mass content of VOC in the 

gases vented to the device by 95.0 

percent by weight or greater. A carbon 

replacement schedule must be included 

in the design of the carbon adsorption 

system. 

(3) You must operate each control 

device used to comply with this subpart 

at all times when gases, vapors, and 

fumes are vented from the storage vessel 

affected facility 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. 

■ 9. Section 60.5413 is amended by: 

■ a. Revising the introductory text; 

■ b. Revising paragraph (a)(7); 

■ c. Revising paragraph (d); and 

■ d. Adding paragraph (e). 

The revisions and addition read as 

follows: 

§ 60.5413 What are the performance 

testing procedures for control devices used 

to demonstrate compliance at my storage 

vessel or centrifugal compressor affected 

facility? 

This section applies to the 

performance testing of control devices 

used to demonstrate compliance with 

the emissions standards for your 

centrifugal compressor affected facility. 

You must demonstrate that a control 

device achieves the performance 

requirements of § 60.5412(a) using the 

performance test methods and 

procedures specified in this section. For 

condensers, you may use a design 

analysis as specified in paragraph (c) of 

this section in lieu of complying with 

paragraph (b) of this section. In 

addition, this section contains the 

requirements for enclosed combustion 

device performance tests conducted by 

the manufacturer applicable to both 

storage vessel and centrifugal 

compressor affected facilities. 

(a) * * * 

(7) A control device whose model can 

be demonstrated to meet the 

performance requirements of 

§ 60.5412(a) through a performance test 

conducted by the manufacturer, as 

specified in paragraph (d) of this 

section. 

* * * * * 

(d) Performance testing for 

combustion control devices— 

manufacturers’ performance test. (1) 

This paragraph applies to the 

performance testing of a combustion 

control device conducted by the device 

manufacturer. The manufacturer must 

demonstrate that a specific model of 

control device achieves the performance 

requirements in paragraph (d)(11) of this 

section by conducting a performance 

test as specified in paragraphs (d)(2) 

through (10) of this section. You must 

submit a test report for each combustion 

control device in accordance with the 


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requirements in paragraph (d)(12) of this 

section. 

(2) Performance testing must consist 

of three one-hour (or longer) test runs 

for each of the four firing rate settings 

specified in paragraphs (d)(2)(i) through 

(iv) of this section, making a total of 12 

test runs per test. Propene (propylene) 

gas must be used for the testing fuel. All 

fuel analyses must be performed by an 

independent third-party laboratory (not 

affiliated with the control device 

manufacturer or fuel supplier). 

(i) 90–100 percent of maximum 

design rate (fixed rate). 

(ii) 70–100–70 percent (ramp up, 

ramp down). Begin the test at 70 percent 

of the maximum design rate. During the 

first 5 minutes, incrementally ramp the 

firing rate to 100 percent of the 

maximum design rate. Hold at 100 

percent for 5 minutes. In the 10–15 

minute time range, incrementally ramp 

back down to 70 percent of the 

maximum design rate. Repeat three 

more times for a total of 60 minutes of 

sampling. 

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

down). Begin the test at 30 percent of 

the maximum design rate. During the 

first 5 minutes, incrementally ramp the 

firing rate to 70 percent of the maximum 

design rate. Hold at 70 percent for 5 

minutes. In the 10–15 minute time 

range, incrementally ramp back down to 

30 percent of the maximum design rate. 

Repeat three more times for a total of 60 

minutes of sampling. 

(iv) 0–30–0 percent (ramp up, ramp 

down). Begin the test at the minimum 

firing rate. During the first 5 minutes, 

incrementally ramp the firing rate to 30 

percent of the maximum design rate. 

Hold at 30 percent for 5 minutes. In the 

10–15 minute time range, incrementally 

ramp back down to the minimum firing 

rate. Repeat three more times for a total 

of 60 minutes of sampling. 

(3) All models employing multiple 

enclosures must be tested 

simultaneously and with all burners 

operational. Results must be reported 

for each enclosure individually and for 

the average of the emissions from all 

interconnected combustion enclosures/

chambers. Control device operating data 

must be collected continuously 

throughout the performance test using 

an electronic Data Acquisition System. 

A graphic presentation or strip chart of 

the control device operating data and 

emissions test data must be included in 

the test report in accordance with 

paragraph (d)(12) of this section. Inlet 

fuel meter data may be manually 

recorded provided that all inlet fuel data 

readings are included in the final report. 

(4) Inlet testing must be conducted as 

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

(ii) of this section. 

(i) The inlet gas flow metering system 

must be located in accordance with 

Method 2A, 40 CFR part 60, appendix 

A–1, (or other approved procedure) to 

measure inlet gas flow rate at the control 

device inlet location. You must position 

the fitting for filling fuel sample 

containers a minimum of eight pipe 

diameters upstream of any inlet gas flow 

monitoring meter. 

(ii) Inlet flow rate must be determined 

using Method 2A, 40 CFR part 60, 

appendix A–1. Record the start and stop 

reading for each 60-minute THC test. 

Record the gas pressure and temperature 

at 5-minute intervals throughout each 

60-minute test. 

(5) Inlet gas sampling must be 

conducted as specified in paragraphs 

(d)(5)(i) through (ii) of this section. 

(i) At the inlet gas sampling location, 

securely connect a Silonite-coated 

stainless steel evacuated canister fitted 

with a flow controller sufficient to fill 

the canister over a 3-hour period. Filling 

must be conducted as specified in 

paragraphs (d)(5)(i)(A) through (C) of 

this section. 

(A) Open the canister sampling valve 

at the beginning of each test run, and 

close the canister at the end of each test 

run. 

(B) Fill one canister across the three 

test runs such that one composite fuel 

sample exists for each test condition. 

(C) Label the canisters individually 

and record sample information on a 

chain of custody form. 

(ii) Analyze each inlet gas sample 

using the methods in paragraphs 

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

You must include the results in the test 

report required by paragraph (d)(12) of 

this section. 

(A) Hydrocarbon compounds 

containing between one and five atoms 

of carbon plus benzene using ASTM 

D1945–03. 

(B) Hydrogen (H2), carbon monoxide 

(CO), carbon dioxide (CO2), nitrogen 

(N2), oxygen (O2) using ASTM D1945– 

03. 

(C) Higher heating value using ASTM 

D3588–98 or ASTM D4891–89. 

(6) Outlet testing must be conducted 

in accordance with the criteria in 

paragraphs (d)(6)(i) through (v) of this 

section. 

(i) Sample and flow rate must be 

measured in accordance with 

paragraphs (d)(6)(i)(A) through (B) of 

this section. 

(A) The outlet sampling location must 

be a minimum of four equivalent stack 

diameters downstream from the highest 

peak flame or any other flow 

disturbance, and a minimum of one 

equivalent stack diameter upstream of 

the exit or any other flow disturbance. 

A minimum of two sample ports must 

be used. 

(B) Flow rate must be measured using 

Method 1, 40 CFR part 60, appendix A– 

1 for determining flow measurement 

traverse point location, and Method 2, 

40 CFR part 60, appendix A–1 for 

measuring duct velocity. If low flow 

conditions are encountered (i.e., 

velocity pressure differentials less than 

0.05 inches of water) during the 

performance test, a more sensitive 

manometer must be used to obtain an 

accurate flow profile. 

(ii) Molecular weight and excess air 

must be determined as specified in 

paragraph (d)(7) of this section. 

(iii) Carbon monoxide must be 

determined as specified in paragraph 

(d)(8) of this section. 

(iv) THC must be determined as 

specified in paragraph (d)(9) of this 

section. 

(v) Visible emissions must be 

determined as specified in paragraph 

(d)(10) of this section. 

(7) Molecular weight and excess air 

determination must be performed as 

specified in paragraphs (d)(7)(i) through 

(iii) of this section. 

(i) An integrated bag sample must be 

collected during the Method 4, 40 CFR 

part 60, appendix A–3, moisture test 

following the procedure specified in 

(d)(7)(i)(A) through (B) of this section. 

Analyze the bag sample using a gas 

chromatograph-thermal conductivity 

detector (GC–TCD) analysis meeting the 

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

through (D) of this section. 

(A) Collect the integrated sample 

throughout the entire test, and collect 

representative volumes from each 

traverse location. 

(B) Purge the sampling line with stack 

gas before opening the valve and 

beginning to fill the bag. Clearly label 

each bag and record sample information 

on a chain of custody form. 

(C) The bag contents must be 

vigorously mixed prior to the gas 

chromatograph analysis. 

(D) The GC–TCD calibration 

procedure in Method 3C, 40 CFR part 

60, appendix A, must be modified by 

using EPA Alt–045 as follows: For the 

initial calibration, triplicate injections of 

any single concentration must agree 

within 5 percent of their mean to be 

valid. The calibration response factor for 

a single concentration re-check must be 

within 10 percent of the original 

calibration response factor for that 

concentration. If this criterion is not 

met, repeat the initial calibration using 

at least three concentration levels. 


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(ii) Calculate and report the molecular 

weight of oxygen, carbon dioxide, 

methane, and nitrogen in the integrated 

bag sample and include in the test 

report specified in paragraph (d)(12) of 

this section. Moisture must be 

determined using Method 4, 40 CFR 

part 60, appendix A–3. Traverse both 

ports with the Method 4, 40 CFR part 

60, appendix A–3, sampling train 

during each test run. Ambient air must 

not be introduced into the Method 3C, 

40 CFR part 60, appendix A–2, 

integrated bag sample during the port 

change. 

(iii) Excess air must be determined 

using resultant data from the EPA 

Method 3C tests and EPA Method 3B, 40 

CFR part 60, appendix A, equation 3B– 

1. 

(8) Carbon monoxide must be 

determined using Method 10, 40 CFR 

part 60, appendix A. Run the test 

simultaneously with Method 25A, 40 

CFR part 60, appendix A–7 using the 

same sampling points. An instrument 

range of 0–10 parts per million by 

volume-dry (ppmvd) is recommended. 

(9) Total hydrocarbon determination 

must be performed as specified by in 

paragraphs (d)(9)(i) through (vii) of this 

section. 

(i) Conduct THC sampling using 

Method 25A, 40 CFR part 60, appendix 

A–7, except that the option for locating 

the probe in the center 10 percent of the 

stack is not allowed. The THC probe 

must be traversed to 16.7 percent, 50 

percent, and 83.3 percent of the stack 

diameter during each test run. 

(ii) A valid test must consist of three 

Method 25A, 40 CFR part 60, appendix 

A–7, tests, each no less than 60 minutes 

in duration. 

(iii) A 0–10 parts per million by 

volume-wet (ppmvw) (as propane) 

measurement range is preferred; as an 

alternative a 0–30 ppmvw (as carbon) 

measurement range may be used. 

(iv) Calibration gases must be propane 

in air and be certified through EPA 

Protocol 1—‘‘EPA Traceability Protocol 

for Assay and Certification of Gaseous 

Calibration Standards,’’ September 

1997, as amended August 25, 1999, 

EPA–600/R–97/121(or more recent if 

updated since 1999). 

(v) THC measurements must be 

reported in terms of ppmvw as propane. 

(vi) THC results must be corrected to 

3 percent CO2, as measured by Method 

3C, 40 CFR part 60, appendix A–2. You 

must use the following equation for this 

diluent concentration correction: 

Where: 

Cmeas = The measured concentration of the 

pollutant. 

CO2meas = The measured concentration of the 

CO2 diluent. 

3 = The corrected reference concentration of 

CO2 diluent. 

Ccorr = The corrected concentration of the 

pollutant. 

(vii) Subtraction of methane or ethane 

from the THC data is not allowed in 

determining results. 

(10) Visible emissions must be 

determined using Method 22, 40 CFR 

part 60, appendix A. The test must be 

performed continuously during each 

test run. A digital color photograph of 

the exhaust point, taken from the 

position of the observer and annotated 

with date and time, must be taken once 

per test run and the 12 photos included 

in the test report specified in paragraph 

(d)(12) of this section. 

(11) Performance test criteria. (i) The 

control device model tested must meet 

the criteria in paragraphs (d)(11)(i)(A) 

through (D) of this section. These 

criteria must be reported in the test 

report required by paragraph (d)(12) of 

this section. 

(A) Method 22, 40 CFR part 60, 

appendix A, results under paragraph 

(d)(10) of this section with no indication 

of visible emissions. 

(B) Average Method 25A, 40 CFR part 

60, appendix A, results under paragraph 

(d)(9) of this section equal to or less 

than 10.0 ppmvw THC as propane 

corrected to 3.0 percent CO2. 

(C) Average CO emissions determined 

under paragraph (d)(8) of this section 

equal to or less than 10 parts ppmvd, 

corrected to 3.0 percent CO2. 

(D) Excess combustion air determined 

under paragraph (d)(7) of this section 

equal to or greater than 150 percent. 

(ii) The manufacturer must determine 

a maximum inlet gas flow rate which 

must not be exceeded for each control 

device model to achieve the criteria in 

paragraph (d)(11)(iii) of this section. The 

maximum inlet gas flow rate must be 

included in the test report required by 

paragraph (d)(12) of this section. 

(iii) A control device meeting the 

criteria in paragraph (d)(11)(i)(A) 

through (D) of this section must 

demonstrate a destruction efficiency of 

95 percent for VOC regulated under this 

subpart. 

(12) The owner or operator of a 

combustion control device model tested 

under this paragraph must submit the 

information listed in paragraphs 

(d)(12)(i) through (vi) in the test report 

required by this section in accordance 

with § 60.5420(b)(8). 

(i) A full schematic of the control 

device and dimensions of the device 

components. 

(ii) The maximum net heating value of 

the device. 

(iii) The test fuel gas flow range (in 

both mass and volume). Include the 

maximum allowable inlet gas flow rate. 

(iv) The air/stream injection/assist 

ranges, if used. 

(v) The test conditions listed in 

paragraphs (d)(12)(v)(A) through (O) of 

this section, as applicable for the tested 

model. 

(A) Fuel gas delivery pressure and 

temperature. 

(B) Fuel gas moisture range. 

(C) Purge gas usage range. 

(D) Condensate (liquid fuel) 

separation range. 

(E) Combustion zone temperature 

range. This is required for all devices 

that measure this parameter. 

(F) Excess combustion air range. 

(G) Flame arrestor(s). 

(H) Burner manifold. 

(I) Pilot flame indicator. 

(J) Pilot flame design fuel and 

calculated or measured fuel usage. 

(K) Tip velocity range. 

(L) Momentum flux ratio. 

(M) Exit temperature range. 

(N) Exit flow rate. 

(O) Wind velocity and direction. 

(vi) The test report must include all 

calibration quality assurance/quality 

control data, calibration gas values, gas 

cylinder certification, strip charts, or 

other graphic presentations of the data 

annotated with test times and 

calibration values. 

(e) Continuous compliance for 

combustion control devices tested by the 

manufacturer in accordance with 

paragraph (d) of this section. This 

paragraph applies to the demonstration 

of compliance for a combustion control 

device tested under the provisions in 

paragraph (d) of this section. Owners or 

operators must demonstrate that a 

control device achieves the performance 

requirements in (d)(11) of this section 

by installing a device tested under 

paragraph (d) of this section and 

complying with the criteria specified in 

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

section. 

(1) The inlet gas flow rate must be 

equal to or less than the maximum 

specified by the manufacturer. 

(2) A pilot flame must be present at 

all times of operation. 

(3) Devices must be operated with no 

visible emissions, except for periods not 

to exceed a total of 2 minutes during 

any hour. A visible emissions test using 

Method 22, 40 CFR part 60, appendix A, 

must be performed each calendar 

quarter. The observation period must be 

1 hour and must be conducted 

according to EPA Method 22, 40 CFR 

part 60, appendix A. 


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(4) Devices failing the visible 

emissions test must follow 

manufacturer’s repair instructions, if 

available, or best combustion 

engineering practice as outlined in the 

unit inspection and maintenance plan, 

to return the unit to compliant 

operation. All repairs and maintenance 

activities for each unit must be recorded 

in a maintenance and repair log and 

must be available for inspection. 

(5) Following return to operation from 

maintenance or repair activity, each 

device must pass an EPA Method 22, 40 

CFR part 60, appendix A, visual 

observation as described in paragraph 

(e)(3) of this section. 

(6) If the owner or operator operates 

a combustion control device model 

tested under this section, an electronic 

copy of the performance test results 

required by this section shall be 

submitted via email to Oil_and_Gas_

PT@EPA.GOV unless the test results for 

that model of combustion control device 

are posted at the following Web site: 

epa.gov/airquality/oilandgas/. 

■ 10. Section 60.5415 is amended by: 

■ a. Revising paragraphs (b) 

introductory text and (b)(2); 

■ b. Revising paragraph (e) introductory 

text; 

■ c. Removing and reserving paragraphs 

(e)(1) and (2); 

■ d. Adding paragraph (e)(3); and 

■ e. Revising paragraph (h)(1) 

introductory text. 

The revisions and addition read as 

follows: 

§ 60.5415 How do I demonstrate 

continuous compliance with the standards 

for my gas well affected facility, my 

centrifugal compressor affected facility, my 

stationary reciprocating compressor 

affected facility, my pneumatic controller 

affected facility, my storage vessel affected 

facility, and my affected facilities at onshore 

natural gas processing plants? 

* * * * * 

(b) For each centrifugal compressor 

affected facility, you must demonstrate 

continuous compliance according to 

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

section. 

* * * * * 

(2) For each control device used to 

reduce emissions, you must 

demonstrate continuous compliance 

with the performance requirements of 

§ 60.5412(a) using the procedures 

specified in paragraphs (b)(2)(i) through 

(vii) of this section. If you use a 

condenser as the control device to 

achieve the requirements specified in 

§ 60.5412(a)(2), you must demonstrate 

compliance according to paragraph 

(b)(2)(viii) of this section. You may 

switch between compliance with 

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

section and compliance with paragraph 

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

least 1 year of operation in compliance 

with the selected approach. You must 

provide notification of such a change in 

the compliance method in the next 

annual report, as required in 

§ 60.5420(b), following the change. 

(i) You must operate below (or above) 

the site specific maximum (or 

minimum) parameter value established 

according to the requirements of 

§ 60.5417(f)(1). 

(ii) You must calculate the daily 

average of the applicable monitored 

parameter in accordance with 

§ 60.5417(e) except that the inlet gas 

flow rate to the control device must not 

be averaged. 

(iii) Compliance with the operating 

parameter limit is achieved when the 

daily average of the monitoring 

parameter value calculated under 

paragraph (b)(2)(ii) of this section is 

either equal to or greater than the 

minimum monitoring value or equal to 

or less than the maximum monitoring 

value established under paragraph 

(b)(2)(i) of this section. When 

performance testing of a combustion 

control device is conducted by the 

device manufacturer as specified in 

§ 60.5413(d), compliance with the 

operating parameter limit is achieved 

when the criteria in § 60.5413(e) are 

met. 

(iv) You must operate the continuous 

monitoring system required in § 60.5417 

at all times the affected source is 

operating, except for periods of 

monitoring system malfunctions, repairs 

associated with monitoring system 

malfunctions, and required monitoring 

system quality assurance or quality 

control activities (including, as 

applicable, system accuracy audits and 

required zero and span adjustments). A 

monitoring system malfunction is any 

sudden, infrequent, not reasonably 

preventable failure of the monitoring 

system to provide valid data. 

Monitoring system failures that are 

caused in part by poor maintenance or 

careless operation are not malfunctions. 

You are required to complete 

monitoring system repairs in response 

to monitoring system malfunctions and 

to return the monitoring system to 

operation as expeditiously as 

practicable. 

(v) You may not use data recorded 

during monitoring system malfunctions, 

repairs associated with monitoring 

system malfunctions, or required 

monitoring system quality assurance or 

control activities in calculations used to 

report emissions or operating levels. 

You must use all the data collected 

during all other required data collection 

periods to assess the operation of the 

control device and associated control 

system. 

(vi) Failure to collect required data is 

a deviation of the monitoring 

requirements, except for periods of 

monitoring system malfunctions, repairs 

associated with monitoring system 

malfunctions, and required quality 

monitoring system quality assurance or 

quality control activities (including, as 

applicable, system accuracy audits and 

required zero and span adjustments). 

(vii) If you use a combustion control 

device to meet the requirements of 

§ 60.5412(a) and you demonstrate 

compliance using the test procedures 

specified in § 60.5413(b), you must 

comply with paragraphs (b)(2)(vii)(A) 

through (D) of this section. 

(A) A pilot flame must be present at 

all times of operation. 

(B) Devices must be operated with no 

visible emissions, except for periods not 

to exceed a total of 2 minutes during 

any hour. A visible emissions test using 

section 11. of Method 22, 40 CFR part 

60, appendix A, must be performed each 

calendar quarter. The observation 

period must be 1 hour and must be 

conducted according to section 11. of 

EPA Method 22, 40 CFR part 60, 

appendix A. 

(C) Devices failing the visible 

emissions test must follow 

manufacturer’s repair instructions, if 

available, or best combustion 

engineering practice as outlined in the 

unit inspection and maintenance plan, 

to return the unit to compliant 

operation. All repairs and maintenance 

activities for each unit must be recorded 

in a maintenance and repair log and 

must be available for inspection. 

(D) Following return to operation 

from maintenance or repair activity, 

each device must pass a Method 22, 40 

CFR part 60, appendix A, visual 

observation as described in paragraph 

(b)(2)(vii)(B) of this section. 

(viii) If you use a condenser as the 

control device to achieve the percent 

reduction performance requirements 

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

demonstrate compliance using the 

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

through (E) of this section. 

(A) You must establish a site-specific 

condenser performance curve according 

to § 60.5417(f)(2). 

(B) You must calculate the daily 

average condenser outlet temperature in 

accordance with § 60.5417(e). 

(C) You must determine the 

condenser efficiency for the current 

operating day using the daily average 

condenser outlet temperature calculated 

under paragraph (b)(2)(viii)(B) of this 


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section and the condenser performance 

curve established under paragraph 

(b)(2)(viii)(A) of this section. 

(D) Except as provided in paragraphs 

(b)(2)(viii)(D)(1) and (2) of this section, 

at the end of each operating day, you 

must calculate the 365-day rolling 

average TOC emission reduction, as 

appropriate, from the condenser 

efficiencies as determined in paragraph 

(b)(2)(viii)(C) of this section. 

(1) After the compliance dates 

specified in § 60.5370, if you have less 

than 120 days of data for determining 

average TOC emission reduction, you 

must calculate the average TOC 

emission reduction for the first 120 days 

of operation after the compliance dates. 

You have demonstrated compliance 

with the overall 95.0 percent reduction 

requirement if the 120-day average TOC 

emission reduction is equal to or greater 

than 95.0 percent. 

(2) After 120 days and no more than 

364 days of operation after the 

compliance date specified in § 60.5370, 

you must calculate the average TOC 

emission reduction as the TOC emission 

reduction averaged over the number of 

days between the current day and the 

applicable compliance date. You have 

demonstrated compliance with the 

overall 95.0 percent reduction 

requirement, if the average TOC 

emission reduction is equal to or greater 

than 95.0 percent. 

(E) If you have data for 365 days or 

more of operation, you have 

demonstrated compliance with the TOC 

emission reduction if the rolling 365- 

day average TOC emission reduction 

calculated in paragraph (b)(2)(viii)(D) of 

this section is equal to or greater than 

95.0 percent. 

* * * * * 

(e) You must demonstrate continuous 

compliance according to paragraph 

(e)(3) of this section for each storage 

vessel affected facility, for which you 

are using a control device or routing 

emissions to a process to meet the 

requirement of § 60.5395(d)(1). 

(1) [Reserved] 

(2) [Reserved] 

(3) For each storage vessel affected 

facility, you must comply with 

paragraphs (e)(3)(i) and (ii) of this 

section. 

(i) You must reduce VOC emissions as 

specified in § 60.5395(d). 

(ii) For each control device installed 

to meet the requirements of 

§ 60.5395(d), you must demonstrate 

continuous compliance with the 

performance requirements of 

§ 60.5412(d) for each storage vessel 

affected facility using the procedure 

specified in paragraph (e)(3)(ii)(A) and 

either (e)(3)(ii)(B) or (e)(3)(ii)(C) of this 

section. 

(A) You must comply with 

§ 60.5416(c) for each cover and closed 

vent system. 

(B) You must comply with 

§ 60.5417(h) for each control device. 

(C) Each closed vent system that 

routes emissions to a process must be 

operated as specified in § 60.5411(c)(2). 

* * * * * 

(h) * * * 

(1) To establish the affirmative 

defense in any action to enforce such a 

standard, you must timely meet the 

reporting requirements in 

§ 60.5415(h)(2), and must prove by a 

preponderance of evidence that: 

* * * * * 

■ 11. Section 60.5416 is amended by: 

■ a. Revising the introductory text; 

■ b. Revising paragraphs (a) 

introductory text, (a)(1)(ii), (a)(2)(iii), 

and (a)(3)(ii); 

■ c. Revising paragraphs (b) 

introductory text, (b)(9) introductory 

text, and (b)(11); and 

■ d. Adding paragraph (c). 

The revisions and addition read as 

follows: 

§ 60.5416 What are the initial and 

continuous cover and closed vent system 

inspection and monitoring requirements for 

my storage vessel and centrifugal 

compressor affected facility? 

For each closed vent system or cover 

at your storage vessel or centrifugal 

compressor affected facility, you must 

comply with the applicable 

requirements of paragraphs (a) through 

(c) of this section. 

(a) Inspections for closed vent systems 

and covers installed on each centrifugal 

compressor affected facility. Except as 

provided in paragraphs (b)(11) and (12) 

of this section, you must inspect each 

closed vent system according to the 

procedures and schedule specified in 

paragraphs (a)(1) and (2) of this section, 

inspect each cover according to the 

procedures and schedule specified in 

paragraph (a)(3) of this section, and 

inspect each bypass device according to 

the procedures of paragraph (a)(4) of 

this section. 

(1) * * * 

(ii) Conduct annual visual inspections 

for defects that could result in air 

emissions. Defects include, but are not 

limited to, visible cracks, holes, or gaps 

in piping; loose connections; liquid 

leaks; or broken or missing caps or other 

closure devices. You must monitor a 

component or connection using the test 

methods and procedures in paragraph 

(b) of this section to demonstrate that it 

operates with no detectable emissions 

following any time the component is 

repaired or replaced or the connection 

is unsealed. You must maintain records 

of the inspection results as specified in 

§ 60.5420(c)(6). 

(2) * * * 

(iii) Conduct annual visual 

inspections for defects that could result 

in air emissions. Defects include, but are 

not limited to, visible cracks, holes, or 

gaps in ductwork; loose connections; 

liquid leaks; or broken or missing caps 

or other closure devices. You must 

maintain records of the inspection 

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

(3) * * * 

(ii) You must initially conduct the 

inspections specified in paragraph 

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

installation of the cover. Thereafter, you 

must perform the inspection at least 

once every calendar year, except as 

provided in paragraphs (b)(11) and (12) 

of this section. You must maintain 

records of the inspection results as 

specified in § 60.5420(c)(7). 

* * * * * 

(b) No detectable emissions test 

methods and procedures. If you are 

required to conduct an inspection of a 

closed vent system or cover at your 

centrifugal compressor affected facility 

as specified in paragraphs (a)(1), (2), or 

(3) of this section, you must meet the 

requirements of paragraphs (b)(1) 

through (13) of this section. 

* * * * * 

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

defect is detected, you must repair the 

leak or defect as soon as practicable 

according to the requirements of 

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

section, except as provided in paragraph 

(b)(10) of this section. 

* * * * * 

(11) Unsafe to inspect requirements. 

You may designate any parts of the 

closed vent system or cover as unsafe to 

inspect if the requirements in 

paragraphs (b)(11)(i) and (ii) of this 

section are met. Unsafe to inspect parts 

are exempt from the inspection 

requirements of paragraphs (a)(1) 

through (3) of this section. 

(i) You determine that the equipment 

is unsafe to inspect because inspecting 

personnel would be exposed to an 

imminent or potential danger as a 

consequence of complying with 

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

section. 

(ii) You have a written plan that 

requires inspection of the equipment as 

frequently as practicable during safe-toinspect times. 

* * * * * 

(c) Cover and closed vent system 

inspections for storage vessel affected 

facilities. If you install a control device 


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or route emissions to a process, you 

must inspect each closed vent system 

according to the procedures and 

schedule specified in paragraphs (c)(1) 

of this section, inspect each cover 

according to the procedures and 

schedule specified in paragraph (c)(2) of 

this section, and inspect each bypass 

device according to the procedures of 

paragraph (c)(3) of this section. You 

must also comply with the requirements 

of (c)(4) through (7) of this section. 

(1) For each closed vent system, you 

must conduct an inspection at least 

once every calendar month as specified 

in paragraphs (c)(1)(i) through (iii) of 

this section. 

(i) You must maintain records of the 

inspection results as specified in 

§ 60.5420(c)(6). 

(ii) Conduct olfactory, visual and 

auditory inspections for defects that 

could result in air emissions. Defects 

include, but are not limited to, visible 

cracks, holes, or gaps in piping; loose 

connections; liquid leaks; or broken or 

missing caps or other closure devices. 

(iii) Monthly inspections must be 

separated by at least 14 calendar days. 

(2) For each cover, you must conduct 

inspections at least once every calendar 

month as specified in paragraphs 

(c)(2)(i) through (iii) of this section. 

(i) You must maintain records of the 

inspection results as specified in 

§ 60.5420(c)(7). 

(ii) Conduct olfactory, visual and 

auditory inspections for defects that 

could result in air emissions. Defects 

include, but are not limited to, visible 

cracks, holes, or gaps in the cover, or 

between the cover and the separator 

wall; broken, cracked, or otherwise 

damaged seals or gaskets on closure 

devices; and broken or missing hatches, 

access covers, caps, or other closure 

devices. In the case where the storage 

vessel is buried partially or entirely 

underground, you must inspect only 

those portions of the cover that extend 

to or above the ground surface, and 

those connections that are on such 

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

access hatches, gauge wells, etc.) and 

can be opened to the atmosphere. 

(iii) Monthly inspections must be 

separated by at least 14 calendar days. 

(3) For each bypass device, except as 

provided for in § 60.5411(c)(3)(ii), you 

must meet the requirements of 

paragraphs (c)(3)(i) or (ii) of this section. 

(i) Set the flow indicator to sound an 

alarm at the inlet to the bypass device 

when the stream is being diverted away 

from the control device or process to the 

atmosphere. You must maintain records 

of each time the alarm is sounded 

according to § 60.5420(c)(8). 

(ii) If the bypass device valve installed 

at the inlet to the bypass device is 

secured in the non-diverting position 

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

configuration, visually inspect the seal 

or closure mechanism at least once 

every month to verify that the valve is 

maintained in the non-diverting 

position and the vent stream is not 

diverted through the bypass device. You 

must maintain records of the 

inspections and records of each time the 

key is checked out, if applicable, 

according to § 60.5420(c)(8). 

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

defect is detected, you must repair the 

leak or defect as soon as practicable 

according to the requirements of 

paragraphs (c)(4)(i) through (iii) of this 

section, except as provided in paragraph 

(c)(5) of this section. 

(i) A first attempt at repair must be 

made no later than 5 calendar days after 

the leak is detected. 

(ii) Repair must be completed no later 

than 30 calendar days after the leak is 

detected. 

(iii) Grease or another applicable 

substance must be applied to 

deteriorating or cracked gaskets to 

improve the seal while awaiting repair. 

(5) Delay of repair. Delay of repair of 

a closed vent system or cover for which 

leaks or defects have been detected is 

allowed if the repair is technically 

infeasible without a shutdown, or if you 

determine that emissions resulting from 

immediate repair would be greater than 

the fugitive emissions likely to result 

from delay of repair. You must complete 

repair of such equipment by the end of 

the next shutdown. 

(6) Unsafe to inspect requirements. 

You may designate any parts of the 

closed vent system or cover as unsafe to 

inspect if the requirements in 

paragraphs (c)(6)(i) and (ii) of this 

section are met. Unsafe to inspect parts 

are exempt from the inspection 

requirements of paragraphs (c)(1) and 

(2) of this section. 

(i) You determine that the equipment 

is unsafe to inspect because inspecting 

personnel would be exposed to an 

imminent or potential danger as a 

consequence of complying with 

paragraphs (c)(1) or (2) of this section. 

(ii) You have a written plan that 

requires inspection of the equipment as 

frequently as practicable during safe-toinspect times. 

(7) Difficult to inspect requirements. 

You may designate any parts of the 

closed vent system or cover as difficult 

to inspect, if the requirements in 

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

section are met. Difficult to inspect parts 

are exempt from the inspection 

requirements of paragraphs (c)(1) and 

(2) of this section. 

(i) You determine that the equipment 

cannot be inspected without elevating 

the inspecting personnel more than 2 

meters above a support surface. 

(ii) You have a written plan that 

requires inspection of the equipment at 

least once every 5 years. 

■ 12. Section 60.5417 is amended by: 

■ a. Revising paragraph (a); 

■ b. Revising paragraph (b) introductory 

text; 

■ c. Revising paragraph (c) introductory 

text; 

■ d. Revising paragraphs (d)(1)(viii)(A) 

and (B); 

■ e. Revising paragraph (d)(2); 

■ f. Revising paragraph (f)(1)(iii); 

■ g. Revising paragraph (g)(6)(ii); and 

■ h. Adding paragraph (h). 

The revisions and addition read as 

follows: 

§ 60.5417 What are the continuous control 

device monitoring requirements for my 

storage vessel or centrifugal compressor 

affected facility? 

* * * * * 

(a) For each control device used to 

comply with the emission reduction 

standard for centrifugal compressor 

affected facilities in § 60.5380, you must 

install and operate a continuous 

parameter monitoring system for each 

control device as specified in 

paragraphs (c) through (g) of this 

section, except as provided for in 

paragraph (b) of this section. If you 

install and operate a flare in accordance 

with § 60.5412(a)(3), you are exempt 

from the requirements of paragraphs (e) 

and (f) of this section. 

(b) You are exempt from the 

monitoring requirements specified in 

paragraphs (c) through (g) of this section 

for the control devices listed in 

paragraphs (b)(1) and (2) of this section. 

* * * * * 

(c) If you are required to install a 

continuous parameter monitoring 

system, you must meet the 

specifications and requirements in 

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

section. 

* * * * * 

(d) * * * 

(1) * * * 

(viii) * * * 

(A) The continuous monitoring 

system must measure gas flow rate at 

the inlet to the control device. The 

monitoring instrument must have an 

accuracy of ±2 percent or better. The 

flow rate at the inlet to the combustion 

device must not exceed the maximum or 

minimum flow rate determined by the 

manufacturer. 

(B) A monitoring device that 

continuously indicates the presence of 


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the pilot flame while emissions are 

routed to the control device. 

(2) An organic monitoring device 

equipped with a continuous recorder 

that measures the concentration level of 

organic compounds in the exhaust vent 

stream from the control device. The 

monitor must meet the requirements of 

Performance Specification 8 or 9 of 40 

CFR part 60, appendix B. You must 

install, calibrate, and maintain the 

monitor according to the manufacturer’s 

specifications. 

* * * * * 

(f) * * * 

(1) * * * 

(iii) If you operate a control device 

where the performance test requirement 

was met under § 60.5413(d) to 

demonstrate that the control device 

achieves the applicable performance 

requirements specified in § 60.5412(a), 

then your control device inlet gas flow 

rate must not exceed the maximum or 

minimum inlet gas flow rate determined 

by the manufacturer. 

* * * * * 

(g) * * * 

(6) * * * 

(ii) Failure of the quarterly visible 

emissions test conducted under 

§ 60.5413(e)(3) occurs. 

(h) For each control device used to 

comply with the emission reduction 

standard in § 60.5395(d)(1) for your 

storage vessel affected facility, you must 

demonstrate continuous compliance 

according to paragraphs (h)(1) through 

(h)(3) of this section. You are exempt 

from the requirements of this paragraph 

if you install a control device model 

tested in accordance with 

§ 60.5413(d)(2) through (10), which 

meets the criteria in § 60.5413(d)(11), 

the reporting requirement in 

§ 60.5413(d)(12), and meet the 

continuous compliance requirement in 

§ 60.5413(e). 

(1) For each combustion device you 

must conduct inspections at least once 

every calendar month according to 

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

section. Monthly inspections must be 

separated by at least 14 calendar days. 

(i) Conduct visual inspections to 

confirm that the pilot is lit when vapors 

are being routed to the combustion 

device and that the continuous burning 

pilot flame is operating properly. 

(ii) Conduct inspections to monitor 

for visible emissions from the 

combustion device using section 11 of 

EPA Method 22, 40 CFR part 60, 

appendix A. The observation period 

shall be 15 minutes. Devices must be 

operated with no visible emissions, 

except for periods not to exceed a total 

of 1 minute during any 15 minute 

period. 

(iii) Conduct olfactory, visual and 

auditory inspections of all equipment 

associated with the combustion device 

to ensure system integrity. 

(iv) For any absence of pilot flame, or 

other indication of smoking or improper 

equipment operation (e.g., visual, 

audible, or olfactory), you must ensure 

the equipment is returned to proper 

operation as soon as practicable after the 

event occurs. At a minimum, you must 

perform the procedures specified in 

paragraphs (h)(1)(iv)(A) and (B) of this 

section. 

(A) You must check the air vent for 

obstruction. If an obstruction is 

observed, you must clear the obstruction 

as soon as practicable. 

(B) You must check for liquid 

reaching the combustor. 

(2) For each vapor recovery device, 

you must conduct inspections at least 

once every calendar month to ensure 

physical integrity of the control device 

according to the manufacturer’s 

instructions. Monthly inspections must 

be separated by at least 14 calendar 

days. 

(3) Each control device must be 

operated following the manufacturer’s 

written operating instructions, 

procedures and maintenance schedule 

to ensure good air pollution control 

practices for minimizing emissions. 

Records of the manufacturer’s written 

operating instructions, procedures, and 

maintenance schedule must be available 

for inspection as specified in 

§ 60.5420(c)(13). 

■ 13. Section 60.5420 is amended by: 

■ a. Revising paragraph (a) introductory 

text; 

■ b. Revising paragraph (a)(1); 

■ c. Revising paragraph (b) introductory 

text; 

■ d. Revising paragraph (b)(3)(iii); 

■ e. Revising paragraph (b)(4)(i); 

■ f. Revising paragraph (b)(5) 

introductory text; 

■ g. Revising paragraph (b)(5)(i); 

■ h. Revising paragraph (b)(6) 

introductory text; 

■ i. Revising paragraphs (b)(6)(i) and (ii); 

■ j. Adding paragraphs (b)(6)(iv) 

through (vii); 

■ k. Revising paragraph (b)(7); 

■ l. Adding paragraph (b)(8); 

■ m. Revising paragraph (c) 

introductory text; 

■ n. Revising paragraph (c)(1)(v); 

■ o. Revising paragraph (c)(4)(ii); 

■ p. Revising paragraph (c)(5); 

■ q. Revising paragraphs (c)(6) through 

(11); and 

■ r. Adding paragraphs (c)(12) and (13). 

The revisions and additions read as 

follows: 

§ 60.5420 What are my notification, 

reporting, and recordkeeping 

requirements? 

(a) You must submit the notifications 

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

this section if you own or operate one 

or more of the affected facilities 

specified in § 60.5365 that was 

constructed, modified, or reconstructed 

during the reporting period. 

(1) If you own or operate a gas well, 

pneumatic controller, centrifugal 

compressor, reciprocating compressor or 

storage vessel affected facility you are 

not required to submit the notifications 

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

* * * * * 

(b) Reporting requirements. You must 

submit annual reports containing the 

information specified in paragraphs 

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

Administrator and performance test 

reports as specified in paragraph (b)(7) 

or (8) of this section. The initial annual 

report is due no later than 90 days after 

the end of the initial compliance period 

as determined according to § 60.5410. 

Subsequent annual reports are due no 

later than same date each year as the 

initial annual report. If you own or 

operate more than one affected facility, 

you may submit one report for multiple 

affected facilities provided the report 

contains all of the information required 

as specified in paragraphs (b)(1) through 

(6) of this section. Annual reports may 

coincide with title V reports as long as 

all the required elements of the annual 

report are included. You may arrange 

with the Administrator a common 

schedule on which reports required by 

this part may be submitted as long as 

the schedule does not extend the 

reporting period. 

* * * * * 

(3) * * * 

(iii) If required to comply with 

§ 60.5380(a)(1), the records specified in 

paragraphs (c)(6) through (11) of this 

section. 

(4) * * * 

(i) The cumulative number of hours of 

operation or the number of months 

since initial startup, since October 15, 

2012, or since the previous 

reciprocating compressor rod packing 

replacement, whichever is later. 

* * * * * 

(5) For each pneumatic controller 

affected facility, the information 

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

(iii) of this section. 

(i) An identification of each 

pneumatic controller constructed, 

modified or reconstructed during the 

reporting period, including the 


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identification information specified in 

§ 60.5390(b)(2) or (c)(2). 

* * * * * 

(6) For each storage vessel affected 

facility, the information in paragraphs 

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

(i) An identification, including the 

location, of each storage vessel affected 

facility for which construction, 

modification or reconstruction 

commenced during the reporting period. 

The location of the storage vessel shall 

be in latitude and longitude coordinates 

in decimal degrees to an accuracy and 

precision of five (5) decimals of a degree 

using the North American Datum of 

1983. 

(ii) Documentation of the VOC 

emission rate determination according 

to § 60.5365(e). 

* * * * * 

(iv) You must submit a notification 

identifying each Group 1 storage vessel 

affected facility in your initial annual 

report. You must include the location of 

the storage vessel, in latitude and 

longitude coordinates in decimal 

degrees to an accuracy and precision of 

five (5) decimals of a degree using the 

North American Datum of 1983. 

(v) A statement that you have met the 

requirements specified in 

§ 60.5410(h)(2) and (3). 

(vi) You must identify each storage 

vessel affected facility that is removed 

from service during the reporting period 

as specified in § 60.5395(f)(1). 

(vii) You must identify each storage 

vessel affected facility for which 

operation resumes during the reporting 

period as specified in § 60.5395(f)(2)(iii). 

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

completing each performance test (see 

§ 60.8 of this part) as required by this 

subpart, except testing conducted by the 

manufacturer as specified in 

§ 60.5413(d), you must submit the 

results of the performance tests required 

by this subpart to the EPA as follows. 

You must use the latest version of the 

EPA’s Electronic Reporting Tool (ERT) 

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

index.html) existing at the time of the 

performance test to generate a 

submission package file, which 

documents the performance test. You 

must then submit the file generated by 

the ERT through the EPA’s Compliance 

and Emissions Data Reporting Interface 

(CEDRI), which can be accessed by 

logging in to the EPA’s Central Data 

Exchange (CDX) (https://cdx.epa.gov/). 

Only data collected using test methods 

supported by the ERT as listed on the 

ERT Web site are subject to this 

requirement for submitting reports 

electronically. Owners or operators who 

claim that some of the information being 

submitted for performance tests is 

confidential business information (CBI) 

must submit a complete ERT file 

including information claimed to be CBI 

on a compact disk or other commonly 

used electronic storage media 

(including, but not limited to, flash 

drives) to EPA. The electronic media 

must be clearly marked as CBI and 

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

Office, Attention: WebFIRE 

Administrator, MD C404–02, 4930 Old 

Page Rd., Durham, NC 27703. The same 

ERT file with the CBI omitted must be 

submitted to EPA via CDX as described 

earlier in this paragraph. At the 

discretion of the delegated authority, 

you must also submit these reports, 

including the confidential business 

information, to the delegated authority 

in the format specified by the delegated 

authority. For any performance test 

conducted using test methods that are 

not listed on the ERT Web site, the 

owner or operator shall submit the 

results of the performance test to the 

Administrator at the appropriate 

address listed in § 60.4. 

(ii) All reports, except as specified in 

paragraph (b)(8) of this section, required 

by this subpart not subject to the 

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

this section must be sent to the 

Administrator at the appropriate 

address listed in § 60.4 of this part. The 

Administrator or the delegated authority 

may request a report in any form 

suitable for the specific case (e.g., by 

commonly used electronic media such 

as Excel spreadsheet, on CD or hard 

copy). 

(8) For enclosed combustors tested by 

the manufacturer in accordance with 

§ 60.5413(d), an electronic copy of the 

performance test results required by 

§ 60.5413(d) shall be submitted via 

email to Oil_and_Gas_PT@EPA.GOV 

unless the test results for that model of 

combustion control device are posted at 

the following Web site: epa.gov/

airquality/oilandgas/. 

(c) Recordkeeping requirements. You 

must maintain the records identified as 

specified in § 60.7(f) and in paragraphs 

(c)(1) through (13) of this section. All 

records required by this subpart must be 

maintained either onsite or at the 

nearest local field office for at least 5 

years. 

(1) * * * 

(v) For each gas well affected facility 

required to comply with both 

§ 60.5375(a)(1) and (3), if you are using 

a digital photograph in lieu of the 

records required in paragraphs (c)(1)(i) 

through (iv) of this section, you must 

retain the records of the digital 

photograph as specified in 

§ 60.5410(a)(4). 

* * * * * 

(4) * * * 

(ii) Records of the demonstration that 

the use of pneumatic controller affected 

facilities with a natural gas bleed rate 

greater than the applicable standard are 

required and the reasons why. 

* * * * * 

(5) Except as specified in paragraph 

(c)(5)(v) of this section, for each storage 

vessel affected facility, you must 

maintain the records identified in 

paragraphs (c)(5)(i) through (iv) of this 

section. 

(i) If required to reduce emissions by 

complying with § 60.5395(d)(1), the 

records specified in §§ 60.5420(c)(6) 

through (8), § 60.5416(c)(6)(ii), and 

§ 60.6516(c)(7)(ii) of this subpart. 

(ii) Records of each VOC emissions 

determination for each storage vessel 

affected facility made under § 60.5365(e) 

including identification of the model or 

calculation methodology used to 

calculate the VOC emission rate. 

(iii) Records of deviations in cases 

where the storage vessel was not 

operated in compliance with the 

requirements specified in §§ 60.5395, 

60.5411, 60.5412, and 60.5413, as 

applicable. 

(iv) For storage vessels that are skidmounted or permanently attached to 

something that is mobile (such as 

trucks, railcars, barges or ships), records 

indicating the number of consecutive 

days that the vessel is located at a site 

in the oil and natural gas production 

segment, natural gas processing segment 

or natural gas transmission and storage 

segment. If a storage vessel is removed 

from a site and, within 30 days, is either 

returned to or replaced by another 

storage vessel at the site to serve the 

same or similar function, then the entire 

period since the original storage vessel 

was first located at the site, including 

the days when the storage vessel was 

removed, will be added to the count 

towards the number of consecutive 

days. 

(v) You must maintain records of the 

identification and location of each 

storage vessel affected facility. 

(6) Records of each closed vent system 

inspection required under 

§ 60.5416(a)(1) for centrifugal 

compressors or § 60.5416(c)(1) for 

storage vessels. 

(7) A record of each cover inspection 

required under § 60.5416(a)(3) for 

centrifugal compressors or 

§ 60.5416(c)(2) for storage vessels. 

(8) If you are subject to the bypass 

requirements of § 60.5416(a)(4) for 

centrifugal compressors or 


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Federal Register / Vol. 78, No. 184 / Monday, September 23, 2013 / Rules and Regulations 58447 

§ 60.5416(c)(3) for storage vessels, a 

record of each inspection or a record 

each time the key is checked out or a 

record of each time the alarm is 

sounded. 

(9) If you are subject to the closed 

vent system no detectable emissions 

requirements of § 60.5416(b) for 

centrifugal compressors, a record of the 

monitoring conducted in accordance 

with § 60.5416(b). 

(10) For each centrifugal compressor 

affected facility, records of the schedule 

for carbon replacement (as determined 

by the design analysis requirements of 

§ 60.5413(c)(2) or (3)) and records of 

each carbon replacement as specified in 

§ 60.5412(c)(1). 

(11) For each centrifugal compressor 

subject to the control device 

requirements of § 60.5412(a), (b), and 

(c), records of minimum and maximum 

operating parameter values, continuous 

parameter monitoring system data, 

calculated averages of continuous 

parameter monitoring system data, 

results of all compliance calculations, 

and results of all inspections. 

(12) For each carbon adsorber 

installed on storage vessel affected 

facilities, records of the schedule for 

carbon replacement (as determined by 

the design analysis requirements of 

§ 60.5412(d)(2)) and records of each 

carbon replacement as specified in 

§ 60.5412(c)(1). 

(13) For each storage vessel affected 

facility subject to the control device 

requirements of § 60.5412(c) and (d), 

you must maintain records of the 

inspections, including any corrective 

actions taken, the manufacturers’ 

operating instructions, procedures and 

maintenance schedule as specified in 

§ 60.5417(h). You must maintain records 

of EPA Method 22, 40 CFR part 60, 

appendix A, section 11 results, which 

include: company, location, company 

representative (name of the person 

performing the observation), sky 

conditions, process unit (type of control 

device), clock start time, observation 

period duration (in minutes and 

seconds), accumulated emission time 

(in minutes and seconds), and clock end 

time. You may create your own form 

including the above information or use 

Figure 22–1 in EPA Method 22, 40 CFR 

part 60, appendix A. Manufacturer’s 

operating instructions, procedures and 

maintenance schedule must be available 

for inspection. 

■ 14. Section 60.5430 is amended by: 

■ a. Adding, in alphabetical order, 

definitions for the terms ‘‘Condensate,’’ 

‘‘Group 1 storage vessel,’’ ‘‘Group 2 

storage vessel,’’ ‘‘Intermediate 

hydrocarbon liquid’’ and ‘‘Produced 

water;’’ and 

■ b. Revising the definitions for ‘‘Flow 

line’’ and ‘‘Storage vessel’’ to read as 

follows: 

§ 60.5430 What definitions apply to this 

subpart? 

* * * * * 

Condensate means hydrocarbon 

liquid separated from natural gas that 

condenses due to changes in the 

temperature, pressure, or both, and 

remains liquid at standard conditions. 

* * * * * 

Flow line means a pipeline used to 

transport oil and/or gas to a processing 

facility, a mainline pipeline, reinjection, or routed to a process or other 

useful purpose. 

* * * * * 

Group 1 storage vessel means a 

storage vessel, as defined in this section, 

for which construction, modification or 

reconstruction has commenced after 

August 23, 2011, and on or before April 

12, 2013. 

Group 2 storage vessel means a 

storage vessel, as defined in this section, 

for which construction, modification or 

reconstruction has commenced after 

April 12, 2013. 

* * * * * 

Intermediate hydrocarbon liquid 

means any naturally occurring, 

unrefined petroleum liquid. 

* * * * * 

Produced water means water that is 

extracted from the earth from an oil or 

natural gas production well, or that is 

separated from crude oil, condensate, or 

natural gas after extraction. 

* * * * * 

Storage vessel means a tank or other 

vessel that contains 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. For 

the purposes of this subpart, the 

following are not considered storage 

vessels: 

(1) Vessels that are skid-mounted or 

permanently attached to something that 

is mobile (such as trucks, railcars, 

barges or ships), and are intended to be 

located at a site for less than 180 

consecutive days. If you do not keep or 

are not able to produce records, as 

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

that the vessel has been located at a site 

for less than 180 consecutive days, the 

vessel described herein is considered to 

be a storage vessel since the original 

vessel was first located at the site. 

(2) Process vessels such as surge 

control vessels, bottoms receivers or 

knockout vessels. 

(3) Pressure vessels designed to 

operate in excess of 204.9 kilopascals 

and without emissions to the 

atmosphere. 

* * * * * 

■ 15. Tables 1 and 2 to Subpart OOOO 

of part 60 are revised to read as follows: 

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

H2S content of acid gas (Y), % 

Sulfur feed rate (X), LT/D 

2.0≤X≤5.0 5.0<X≤15.0 15.0<X≤300.0 X>300.0 

Y≥50 ............................................... 79.0 88.51X0.0101Y0.0125 or 99.9, whichever is smaller. 

20≤Y<50 ......................................... 79.0 88.51X0.0101Y0.0125 or 97.9, whichever is smaller 97.9 

10≤Y<20 ......................................... 79.0 88.51X0.0101Y0.0125 or 93.5, whichever is smaller ............ 93.5 93.5 

Y<10 ............................................... 79.0 79.0 ................................................................................. 79.0 79.0 


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58448 Federal Register / Vol. 78, No. 184 / Monday, September 23, 2013 / Rules and Regulations 

TABLE 2 TO SUBPART OOOO OF PART 60—REQUIRED MINIMUM SO2 EMISSION REDUCTION EFFICIENCY (Zc) 

H2S content of acid gas (Y), % 

Sulfur feed rate (X), LT/D 

2.0≤X≤5.0 5.0<X≤15.0 15.0<X≤300.0 X>300.0 

Y≥50 ............................................... 74.0 85.35X0.0144Y0.0128 or 99.9, whichever is smaller. 

20≤Y<50 ......................................... 74.0 85.35X0.0144Y0.0128 or 97.5, whichever is smaller 97.5 

10≤Y<20 ......................................... 74.0 85.35X0.0144Y0.0128 or 90.8, whichever is smaller ............ 90.8 90.8 

Y<10 ............................................... 74.0 74.0 ................................................................................. 74.0 74.0 

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

place. 

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

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

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

[FR Doc. 2013–22010 Filed 9–20–13; 8:45 am] 

BILLING CODE 6560–50–P 


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