36096 Federal Register / Vol. 87, No. 115 / Wednesday, June 15, 2022 / Proposed Rules 

Benchmark Survey of Financial Services 

Transactions between U.S. Financial 

Services Providers and Foreign Persons, 

contained in this section, whether or not 

they are contacted by BEA. Also, a 

person, or its agent, that is contacted by 

BEA about reporting on this survey, 

either by sending a report form or by 

written inquiry, must respond in writing 

pursuant to this section. This may be 

accomplished by: 

(1) Completing and returning the BE– 

180 by the due date of the survey; or 

(2) If exempt, completing the 

determination of reporting status section 

of the BE–180 survey and returning it to 

BEA by the due date of the survey. 

(b) Who must report. A BE–180 report 

is required of each U.S. person that is 

a financial services provider or 

intermediary, or whose consolidated 

U.S. enterprise includes a separately 

organized subsidiary, or part, that is a 

financial services provider or 

intermediary, and that had financial 

services transactions with foreign 

persons in the categories covered by the 

survey during the fiscal year covered by 

the survey. 

(c) BE–180 definition of financial 

services provider. The definition of 

financial services provider used for this 

survey is identical to the definition of 

the term as used in the North American 

Industry Classification System, United 

States, Sector 52—Finance and 

Insurance, and holding companies that 

own or influence, and are principally 

engaged in making management 

decisions for, these firms (part of Sector 

55—Management of Companies and 

Enterprises). For example, companies 

and/or subsidiaries and other separable 

parts of companies in the following 

industries are defined as financial 

services providers: Depository credit 

intermediation and related activities 

(including commercial banking, savings 

institutions, credit unions, and other 

depository credit intermediation); nondepository credit intermediation 

(including credit card issuing, sales 

financing, and other non-depository 

credit intermediation); activities related 

to credit intermediation (including 

mortgage and nonmortgage loan brokers, 

financial transactions processing, 

reserve, and clearinghouse activities, 

and other activities related to credit 

intermediation); securities and 

commodity contracts intermediation 

and brokerage (including investment 

banking and securities dealing, 

securities brokerage, commodity 

contracts and dealing, and commodity 

contracts brokerage); securities and 

commodity exchanges; other financial 

investment activities (including 

miscellaneous intermediation, portfolio 

management, investment advice, and all 

other financial investment activities); 

insurance carriers; insurance agencies, 

brokerages, and other insurance related 

activities; insurance and employee 

benefit funds (including pension funds, 

health and welfare funds, and other 

insurance funds); other investment 

pools and funds (including open-end 

investment funds, trusts, estates, and 

agency accounts, real estate investment 

trusts, and other financial vehicles); and 

holding companies that own, or 

influence the management decisions of, 

firms principally engaged in the 

aforementioned activities. 

(d) What must be reported. (1) A U.S. 

person that had combined sales to, or 

purchases from foreign persons that 

exceeded $3 million in the financial 

services categories covered by the 

survey during its fiscal year, on an 

accrual basis, is required to provide data 

on total sales and/or purchases of each 

of the covered types of financial services 

and must disaggregate the totals by 

country and by relationship to the 

foreign transactor (foreign affiliate, 

foreign parent group, or unaffiliated). 

The $3 million threshold for sales and 

purchases should be applied to financial 

services transactions with foreign 

persons by all parts of the consolidated 

domestic U.S. Reporter. Because the $3 

million threshold applies separately to 

sales and purchases, the mandatory 

reporting requirement may apply to 

sales only, to purchases only, or to both. 

The determination of whether a U.S. 

financial services provider is subject to 

this reporting requirement can be based 

on the judgment of knowledgeable 

persons in a company who can identify 

reportable transactions on a recall basis, 

with a reasonable degree of certainty, 

without conducting a detailed manual 

records search. 

(2) A U.S. person that had combined 

sales to, or purchases from foreign 

persons that were $3 million or less in 

the financial services categories covered 

by the survey during its fiscal year, on 

an accrual basis, is required to provide 

the total sales and/or purchases for each 

type of transaction in which they 

engaged. The $3 million threshold for 

sales and purchases should be applied 

to financial services transactions with 

foreign persons by all parts of the 

consolidated domestic U.S. Reporter. 

Because the $3 million threshold 

applies separately to sales and 

purchases, the mandatory reporting 

requirement may apply to sales only, to 

purchases only, or to both. 

(e) Voluntary reporting of financial 

services transactions. If, during the 

fiscal year, combined sales and 

purchases were $3 million or less, on an 

accrual basis, the U.S. person may, in 

addition to providing the required total 

for each type of transaction, report sales 

at a country and affiliation level of 

detail on the applicable mandatory 

schedule(s). The estimates can be 

judgmental, that is, based on recall, 

without conducting a detailed records 

search. 

(f) Exemption claims. Any U.S. person 

that receives the BE–180 survey form 

from BEA, but is not subject to the 

reporting requirements, must file an 

exemption claim by completing the 

determination of reporting status section 

of the BE–180 survey and returning it to 

BEA by the due date of the survey. This 

requirement is necessary to ensure 

compliance with reporting requirements 

and efficient administration of the Act 

by eliminating unnecessary follow-up 

contact. 

(g) Covered types of financial services. 

Financial services covered by the BE– 

180 survey consist of transactions 

between U.S. financial services 

companies and foreign persons for 

brokerage, underwriting, financial 

management, credit-related, creditcards, financial advisory, financial 

custody, securities lending, electronic 

funds transfers, and other financial 

services. 

(h) Due date. A fully completed and 

certified BE–180 report, or qualifying 

exemption claim with the determination 

of reporting status section completed, is 

due to be filed with BEA by July 31 of 

the year after the year covered by the 

survey. 

[FR Doc. 2022–12796 Filed 6–14–22; 8:45 am] 

BILLING CODE 3510–06–P 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Part 52 

[EPA–R02–OAR –2022–0450, FRL–9927–01– 

R02] 

Approval and Promulgation of 

Implementation Plans; New York; Oil 

and Natural Gas Control Measures 

AGENCY: Environmental Protection 

Agency (EPA). 

ACTION: Proposed rule. 

SUMMARY: The Environmental Protection 

Agency (EPA) is proposing to approve a 

State Implementation Plan (SIP) 

revision submitted by the state of New 

York. The revision provides the State’s 

control measures for facilities within its 

borders subject to EPA’s 2016 Control 

Techniques Guideline (CTG) for the oil 

and natural gas industry. The intended 

effect of this action is to approve this 


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1The finding of failure to submit for the oil and 

natural gas CTG was issued for the 2008 NAAQS 

on November 16, 2020 (85 FR 72963, November 16, 

2020), with an effective date of December 16, 2020, 

and for the 2015 NAAQS on December 16, 2021 (86 

FR 71385, December 16, 2021), with an effective 

date of January 18, 2022. 

2The submittal was deemed complete on April 8, 

2022, this completeness determination stops the 2– 

1 NSR offset ratio and federal highway funding 

sanction clocks. 

item into the New York SIP and satisfy 

the requirement for the CTG. This action 

is being taken in accordance with the 

requirements of the Clean Air Act 

(CAA). 

DATES: Written comments must be 

received on or before July 15, 2022. 

ADDRESSES: Submit your comments, 

identified by Docket ID Number EPA– 

R02–OAR–2022–0450 at http://

www.regulations.gov. Follow the online 

instructions for submitting comments. 

Once submitted, comments cannot be 

edited or removed from Regulations.gov. 

The EPA may publish any comment 

received to its public docket. Do not 

submit electronically any information 

you consider to be Confidential 

Business Information (CBI) or other 

information whose disclosure is 

restricted by statute. Multimedia 

submissions (audio, video, etc.) must be 

accompanied by a written comment. 

The written comment is considered the 

official comment and should include 

discussion of all points you wish to 

make. The EPA will generally not 

consider comments or comment 

contents located outside of the primary 

submission (i.e., on the web, cloud, or 

other file sharing system). For 

additional submission methods, the full 

EPA public comment policy, 

information about CBI or multimedia 

submissions, and general guidance on 

making effective comments, please visit 

http://www2.epa.gov/dockets/ 

commenting-epa-dockets. 

FOR FURTHER INFORMATION CONTACT: 

Omar Hammad, Environmental 

Protection Agency, 290 Broadway, New 

York, New York 10007–1866, at (212) 

637–3347, or by email at 

Hammad.Omar@epa.gov. 

SUPPLEMENTARY INFORMATION: 

Throughout this document, whenever 

‘‘we,’’ ‘‘us,’’ or ‘‘our’’ is used, we mean 

EPA. 

Table of Contents 

I. Background and Purpose 

A. Final Control Techniques Guidelines for 

the Oil and Natural Gas Industry 

B. Finding of Failure To Submit 

II. Summary of New York’s Submission and 

EPA’s Analysis 

III. Proposed Action 

IV. Incorporation by Reference 

V. Statutory and Executive Order Reviews 

I. Background and Purpose 

A. Final Control Techniques Guidelines 

for the Oil and Natural Gas Industry 

On October 27, 2016, EPA published 

in the Federal Register the ‘‘Final 

Control Techniques Guidelines for the 

Oil and Natural Gas Industry’’ (CTG) (81 

FR 74798, October 27, 2016). The CTG 

provided information to state, local, and 

tribal air agencies to assist them in 

determining reasonably available 

control technology (RACT) for volatile 

organic compounds (VOC) emissions 

from select oil and natural gas industry 

emission sources. CAA section 

182(b)(2)(A) requires that for ozone 

nonattainment areas classified as 

Moderate or above, states must revise 

their SIPs to include provisions to 

implement RACT for each category of 

VOC sources covered by a CTG 

document. CAA section 184(b)(1)(B) 

extends the RACT obligation to all areas 

of states within the Ozone Transport 

Region (OTR). In addition to New York 

being classified as nonattainment for the 

2008 and 2015 ozone standards for the 

New York portion of the New YorkNorthern New Jersey-Long Island, NYNJ-CT area, New York is a member state 

of the OTR. States subject to RACT 

requirements are required to adopt 

controls that are at least as stringent as 

those found within the CTG either via 

the adoption of regulations, or by 

issuance of single source orders or 

permits that outline what the source is 

required to do to meet RACT. 

B. Finding of Failure To Submit 

On October 29, 2020,1 the U.S. 

Environmental Protection Agency (EPA) 

found that California, Connecticut, New 

York, Pennsylvania, and Texas failed to 

submit State Implementation Plan (SIP) 

revisions in a timely manner to satisfy 

the Clean Air Act’s reasonably available 

control technology requirements (RACT) 

associated with EPA’s 2016 Oil and 

Natural Gas Industry Control 

Techniques Guidelines (CTG). 

These findings of failure to submit 

established a 24-month deadline for 

EPA to either approve SIPs or finalize 

Federal Implementation Plans (FIPs) 

that address the CTG in each area or 

OTR state. This action also established 

timelines for the implementation of two 

mandatory sanctions that will begin if 

the named states do not submit 

complete SIPs to address the CTG: (1) 

Eighteen months after the effective date 

of these findings, a 2-to-1 offset ratio for 

the nonattainment New Source Review 

(NSR) permitting program will go into 

effect, such that for every unit of VOC 

or nitrogen oxide (NOX) emissions a 

new or modified source will contribute 

to the nonattainment area or OTR state, 

two units must be reduced; and (2) six 

months after the date of offset sanctions, 

federal highway funding may be 

withheld in nonattainment areas. For 

the OTR states, such highway sanctions 

would apply only in nonattainment 

areas in those states. If the OTR state 

does not contain any nonattainment 

areas, then the highway sanctions 

would not apply in that state. 

II. Summary of New York’s Submission 

and EPA’s Analysis 

On March 21, 2022, New York 

submitted for approval a SIP revision to 

incorporate the adoption of Title 6 of 

the New York Codes, Rules, and 

Regulations (NYCRR) Part 200, ‘‘General 

Provisions,’’ and Part 203, ‘‘Oil and 

Natural Gas Sector,’’ as adopted on 

January 18, 2022.2 Part 200, section 

200.9, amends Table 1 to add regulation 

203–7.1(a) with a Code of Federal 

Regulations (CFR) citation of ‘‘40 CFR 

part 60, appendix A–7 (July 1, 2017).’’ 

Part 203 sets monitoring, operational, 

and reporting requirements for the oil 

and natural gas sector statewide. The 

adoption of part 203 is meant to satisfy 

the requirements to implement EPA’s 

2016 Oil and Natural Gas CTG within 

the 2008 and 2015 ozone nonattainment 

areas and statewide OTR requirements. 

203–1 Applicability 

Part 203 applies to owners and 

operators of equipment and components 

that are associated with sources in the 

following oil and natural gas sectors: (1) 

Oil and natural gas production, (2) oil, 

condensate, and produced water 

separation and storage; (3) natural gas 

storage; (4) natural gas gathering and 

boosting; (5) natural gas transmission 

and compressor stations; and (6) natural 

gas metering and regulating stations. 

Part 203 does not apply to distributing 

gas utilities or to equipment and 

components located downstream of a 

Citygate. 

EPA’s 2016 CTG applies to: (1) 

Storage vessels, such as a tanks or other 

vessels in the oil and natural gas 

industry that contain an accumulation 

of crude oil, condensate, intermediate 

hydrocarbon liquids, or produced water, 

and that are constructed primarily of 

non-earthen materials (such as wood, 

concrete, steel, fiberglass, or plastic) that 

provide structural support; (2) 

compressors, applicable to centrifugal 

and reciprocating compressors in the oil 

and natural gas industry located 

between the wellhead and point of 

custody transfer to the natural gas 

transmission and storage segment; (3) 


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pneumatic controllers, applicable to 

natural gas-driven pneumatic 

controllers in the oil and natural gas 

industry located between the wellhead 

and a natural gas processing plant 

(including the natural gas processing 

plant) or between the wellhead and the 

point of custody transfer to an oil 

pipeline; (4) pneumatic pumps, 

applicable to natural gas-driven 

chemical/methanol and diaphragm 

pumps located at natural gas processing 

plants and well sites; (5) equipment 

leaks from natural gas processing plants, 

applicable to the group of all equipment 

(except compressors and sampling 

connection systems) within a process 

unit located at a natural gas processing 

plant in VOC service or in wet gas 

service, and any device or system that 

is used to control VOC emissions (e.g., 

a closed vent system); and (6) fugitive 

emissions from well sites and gathering 

boosting stations, applicable to the 

collection of fugitive emissions 

components at well sites with an 

average production of greater than 15 

barrel equivalents per well per day (15 

barrel equivalents) and the collection of 

fugitive emissions components at 

gathering and boosting stations in the 

production segment. 

EPA finds that Subpart 203–1 of New 

York’s part 203, ‘‘Oil and Natural Gas 

Sector’’ satisfies the applicability 

requirements of the 2016 CTG and 

applies to a wider range than what is 

required in the 2016 CTG. Part 203 

applies to all wells in New York. The 

New York State Department of 

Environmental Conservation (NYSDEC) 

did not adopt an exemption for lowerproducing wells. 

Subparts 203–2, ‘‘Oil and Natural Gas 

Well Activities,’’ 203–3, ‘‘Natural Gas 

Gathering Lines,’’ 203–4.1, ‘‘Storage 

Vessels,’’ and 203–4.2, ‘‘Natural Gas 

Actuated Pneumatic Devices and 

Pumps’’ 

Subparts 203–2, 203–3, and 203–4.1 

require all storage vessels located at oil 

and natural gas well sites with a 

potential to emit greater than or equal to 

six tons per year (tpy) of VOC to either 

have a vapor control efficiency of 95 

percent if installed prior to 2023, or to 

not vent to the atmosphere if installed 

after January 1, 2023. 

Subparts 203–2, 203–3, and 203–4.2 

require natural gas actuated pneumatic 

devices and pumps located at oil and 

natural gas well sites, gathering and 

boosting locations and compressor 

stations to prevent venting of natural gas 

to the atmosphere beginning on January 

1, 2023, except for devices installed 

prior to 2023, that may be used 

provided they do not vent natural gas at 

a rate greater than six standard cubic 

feet per hour (scfh). When the device is 

idle and not actuating, the devices must 

be clearly marked with a permanent tag 

that identifies the vented emissions rate 

as less than or equal to six scfh. Devices 

must be tested by January 1, 2024, and 

then tested annually thereafter, no later 

than 13 months, and no earlier than 11 

months from the previous test using a 

direct measurement method (high 

volume sampling, bagging, calibrated 

flow measuring instrument). Any device 

with a measured emissions flow rate 

greater than six scfh shall be 

successfully repaired within 14 days 

from the date of the initial emission 

flow rate measurement. Beginning 

January 1, 2023, intermittent bleed 

natural gas actuated pneumatic devices 

shall comply with the leak detection 

and repair (LDAR) requirements 

specified in Subpart 203–7 when the 

device is idle and not controlling. 

Beginning January 1, 2023, natural gas 

actuated pneumatic pumps shall not 

vent natural gas to the atmosphere and 

shall comply with the LDAR 

requirements specified in Subpart 203– 

7. 

EPA’s 2016 CTG lists various control 

options, such as routing emissions to a 

process via a vapor recovery unit (VRU) 

with a 95 percent efficiency, routing 

emissions to a combustion device with 

an at least 95 percent efficiency or 

routing the emissions to a VRU with a 

combustion device as a backup with an 

assumed 95 percent emission reduction. 

The recommended RACT level of 

control in the CTG is a continuous 95 

percent reduction of VOC. 

EPA’s 2016 CTG requires each 

diaphragm pump located at a well site 

capture and route VOC emissions to an 

existing control device or process that is 

located onsite, unless it is technically 

infeasible to route emissions to the 

existing control device or process. 95 

percent control of VOC emissions must 

be controlled, unless the existing 

control device or process cannot achieve 

95 percent control. If the existing 

control device cannot achieve a 95 

percent control efficiency, the emissions 

must nevertheless be routed to the 

existing onsite control device to control 

emissions to the extent achievable. 

Documentation of the percent control 

that the onsite control device is 

designed to achieve must be 

maintained. If there is no existing 

control device at the location of the 

pump, a certification that there is no 

device must be submitted. If a control 

device is subsequently added to the site 

where the pump is located, then the 

VOC emissions from the pump must be 

captured and routed to the newly 

installed control device. 

EPA finds that Subparts 203–2, 203– 

3, 203–4.1, and 203–4.2 of New York’s 

Part 203, ‘‘Oil and Natural Gas Sector’’ 

satisfy, and go beyond the storage vessel 

and pneumatic pump RACT 

requirements of the 2016 CTG by 

requiring at least a 95 percent emission 

control efficiency for storage vessels 

installed prior to 2023 and eliminating 

venting for storage vessels installed after 

January 1, 2023. Similarly, prohibiting 

venting for pneumatic pumps at oil and 

natural gas wells, gathering and 

boosting locations, and compressor 

stations installed after January 1, 2023, 

and limiting the measured emissions 

flow rate to six scfh for devices installed 

prior to 2023 satisfy the RACT 

requirements of the 2016 CTG. 

Subpart 203–4, ‘‘Natural Gas 

Transmission Pipelines and Compressor 

Stations’’ 

Subpart 203–4.3 applies to centrifugal 

natural gas compressors located at 

natural gas transmission compressor 

stations, and natural gas underground 

storage facilities. This subpart does not 

apply to centrifugal natural gas 

compressors that operate less than 200 

hours over a rolling 12-month period. 

Beginning on January 1, 2023, 

centrifugal compressors with wet seals 

shall control the wet seal vent gas with 

the use of a vapor collection system as 

described in Subpart 203–8 or shall 

replace the wet seal with a dry seal. 

Beginning on January 1, 2023, 

components on driver engines and 

compressors that use a wet seal, or a dry 

seal shall comply with the LDAR 

requirements specified in Subpart 203– 

7. The compressor wet seal shall be 

measured annually by direct 

measurement (high volume sampling, 

bagging, calibrated flow measuring 

instrument) while the compressor is 

running at normal operating 

temperature in order to determine the 

wet seal emission flow rate. A 

compressor with a wet seal emission 

flow rate greater than three scfm, or a 

combined flow rate greater than the 

number of wet seals multiplied by three 

scfm, shall be successfully repaired 

within 30 days of the initial flow rate 

measurement. 

Subpart 203–4.4 applies to 

reciprocating natural gas compressors 

located at natural gas transmission 

compressor stations, and natural gas 

underground storage facilities. This 

subpart does not apply to reciprocating 

natural gas compressors that operate 

fewer than 200 hours over a rolling 12- 

month period. Beginning on January 1, 

2023, components on driver engines and 


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compressors shall comply with the 

LDAR requirements specified in Subpart 

203–7, with the exception of the rodpacking components, the compressor 

rod packing, or seal emission flow rate 

through the rod packing, or seal vent 

stack, which shall be measured annually 

by direct measurement (high volume 

sampling, bagging, calibrated flow 

measuring instrument) while the 

compressor is running at normal 

operating temperature. Beginning on 

January 1, 2023, compressor vent stacks 

used to vent rod packing or seal 

emissions shall be controlled with the 

use of a vapor collection system as 

specified in Subpart 203–8. A 

compressor with a rod packing or seal 

with a measured emission flow rate 

greater than two scfm, or a combined 

rod packing or seal emission flow rate 

greater than the number of compression 

cylinders multiplied by two scfm, shall 

be successfully repaired within 30 days 

from the date of the initial emission 

flow rate measurement. 

Subpart 203–4.5 applies to blowdown 

activity at compressor stations and 

transmission pipelines greater than 

10,000 standard feet cubed (scf) and 

requires notification to the NYSDEC and 

appropriate local authorities of at least 

48 hours in advance of a planned 

blowdown event. If any of the 

information reported prior to the 

blowdown changed during or after the 

blowdown, another notification to the 

NYSDEC and appropriate local 

authorities shall be made with the 

updates no later than 48 hours after the 

end of the planned blowdown. For 

unplanned blowdowns, notification to 

the NYSDEC and appropriate local 

authorities must be provided within 30 

minutes of blowdown, or as soon as it 

is safe to do so. 

Subpart 203–4.6 applies to any 

Pigging activity along natural gas 

pipelines and requires recording and 

reporting Pigging activities and 

estimated natural gas loss to the 

NYSDEC by March 31st of each year for 

the previous calendar year. 

EPA’s 2016 CTG requires VOC 

emissions to be reduced by at least 95 

percent (the recommended RACT level 

of control) from a centrifugal 

compressor equipped with a wet seal 

when using a control device or other 

control measure (such as routing to a 

process). The centrifugal compressor 

should be equipped with a cover that is 

connected through a closed vent system 

that routes emissions to the control 

device (or process) that meets the RACT 

level of control. The CTG does not 

recommend that RACT apply to 

individual centrifugal compressors 

using wet seals located at a well site, or 

an adjacent well site that services more 

than one well site. The 2016 CTG 

recommends that each reciprocating 

compressor reduce VOC emissions by 

replacing the rod packing on or before 

26,000 hours of operation or 36 months 

from the date of the last rod packing 

replacement. It also recommends that an 

alternative be provided to allow routing 

of rod packing emissions to a process 

via a closed vent system under negative 

pressure in lieu of the specified rod 

packing replacement periods. The CTG 

does not recommend that RACT apply 

to individual reciprocating compressors 

located at a well site, or an adjacent well 

site that services more than one well 

site. 

EPA finds that Subpart 203–4 of New 

York’s part 203, ‘‘Oil and Natural Gas 

Sector’’ satisfies or goes beyond the 

requirements of the CTG. Subpart 203– 

4 goes beyond the CTG by requiring the 

use of vapor collection systems and 

vapor control devices for centrifugal 

compressors equipped with a wet seal, 

as well as requiring notification for any 

blowdown or Pigging activities. Subpart 

203–4 satisfies the CTG by requiring 

reciprocating natural gas compressors to 

detect leaks and repair them and 

requiring direct annual measurement for 

the rod packing components, the 

compressor rod packing or seal emission 

flow rate through the rod packing, or 

seal vent stack. 

Subparts 203–5, ‘‘Natural Gas 

Underground Storage Facilities’’ and 

203–6, ‘‘City Gate’’ 

Subparts 203–5 and 203–6 apply to 

natural gas underground storage 

facilities and metering and regulating 

components and require LDAR as 

specified in Subpart 203–7. 

EPA’s 2016 CTG applies RACT to 

equipment leaks from natural gas 

processing plants and recommends that 

RACT for natural gas processing plants 

be the implementation of an LDAR 

program equivalent to what is required 

under 40 CFR part 60 subpart VVa for 

equipment (with the exception of 

compressors and sampling connection 

systems) in VOC service. 

EPA finds that Subparts 203–5 and 

203–6 of New York’s part 203, ‘‘Oil and 

Natural Gas Sector’’ satisfy and go 

beyond, the requirements of the 2016 

CTG. The NYSDEC requires LDAR, as 

specified in Subpart 203–7, in order to 

monitor for methane (CH4) and VOC. 

Subpart 203–7, ‘‘Leak Detection and 

Repair’’ 

Subpart 203–7 does not apply to 

components that are: (1) Buried below 

ground, (2) used to supply compressed 

air to equipment or instrumentation, (3) 

operating under a negative gauge 

pressure, or below atmospheric 

pressure, or (4) used for general 

maintenance for fewer than 15 days over 

a 12-month period if the owner or 

operator maintains for at least five years, 

and can make available at the request of 

the NYSDEC, a record of the date when 

the components were installed and 

removed. Subpart 203–7 also does not 

apply to pneumatic devices or pumps 

that use compressed air or electricity to 

operate and a compressor rod packing, 

which is subject to annual emission 

flow rate testing as specified in Subpart 

203–4.4. 

Subpart 203–7.1 requires all owners 

and operators to comply by either: (1) 

Opting to comply using EPA Method 21, 

where fugitive emission is defined as an 

instrument reading of 500 ppm CH4 and 

VOC, 500 ppm or greater of CH4 and 

VOC using a Flame Ionization Detector 

(FID)-based instrument, and if an 

analyzer other than a FID-based 

instrument is used, a site-specific 

fugitive emission definition must be 

developed by the owner or operator that 

would be equivalent to 500 ppm of CH4 

and VOC using a FID-based instrument. 

Such site-specific fugitive emission 

definition is subject to approval by the 

NYSDEC; (2) using optical gas imaging 

(OGI) equipment that is capable of 

imaging gases in the spectral range for 

CH4 and VOC in the potential fugitive 

emissions, and whose calibration and 

maintenance procedures comply with 

those recommended by the 

manufacturer; and (3) using alternative 

techniques that are approved by the 

NYSDEC in lieu of, or in combination 

with, OGI, Method 21, or other 

previously approved alternative 

methods. A proposed alternative 

method must be able to demonstrate 

that it is capable of identifying leaks and 

that it is at least as effective as the leak 

detection methods achieved using 

Method 21 or OGI. 

Subpart 203–7.2, ‘‘LDAR Frequency,’’ 

requires that for oil and natural gas 

wells, wellheads, and components 

subject to Subpart 203–2, each well site 

shall be inspected by OGI, Method 21 or 

similar approved alternative method 

semiannually, or one time over 24 

months if using an approved alternative 

method which offers continuous 

monitoring. For natural gas gathering 

and boosting components subject to 

Subpart 203–3, each gathering and 

boosting station shall be inspected by 

OGI, Method 21 or similar approved 

alternative method quarterly, or one 

time over 24 months if using an 

approved alternative method which 

offers continuous monitoring. Natural 

gas transmission compressor station 


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components subject to Subpart 203–4 

shall be inspected by OGI, Method 21, 

or similar approved alternative method 

bimonthly, at least 45 days apart, or one 

time over 12 months if using an 

approved alternative method which 

offers continuous monitoring. Storage 

facility components subject to Subpart 

203–5 shall be inspected by OGI, 

Method 21, or similar approved 

alternative method bimonthly, at least 

45 days apart, or one time over 12 

months if using an approved alternative 

method which offers continuous 

monitoring. City gate components 

subject to Subpart 203–6 shall be 

inspected by OGI, Method 21, or similar 

approved alternative method quarterly, 

or one time over 12 months if using an 

approved alternative method which 

offers continuous monitoring. 

Subpart 203–7.3 applies to leaks and 

requires, upon detection of a leak from 

any equipment or component subject to 

part 203, that the owner or operator affix 

to that component a weatherproof, 

readily visible tag that identifies the 

date and time of leak detection. The 

owner or operator shall maintain for at 

least five years, and make available 

upon request by the NYSDEC, a record 

of leaks identified, and shall report to 

the NYSDEC within 60 days after the reinspection of repaired leaks is complete. 

Leaks shall be repaired within 30 days 

of identification. Repaired leaks shall be 

re-inspected using the methods 

specified in subpart 203–7 within 15 

days of repair. Critical components or 

critical process units shall be 

successfully repaired by the end of the 

next process shutdown or within 12 

months from the date of initial leak 

detection, whichever is sooner. A delay 

of repair may be granted by the NYSDEC 

under the following conditions: (1) The 

owner or operator can demonstrate that 

the parts or equipment required to make 

necessary repairs have been ordered. A 

delay of repair to obtain parts or 

equipment shall not exceed 30 days, 

unless the owner or operator notifies the 

NYSDEC to report the delay and 

provides an estimated time by which 

the repairs will be completed, or (2) a 

gas service utility can provide 

documentation, in a form suitable to the 

NYSDEC, that a system has been 

temporarily classified as critical to 

reliable public gas system operation as 

ordered by the utility’s gas control 

office. 

EPA’s 2016 CTG applies RACT to 

equipment leaks from natural gas 

processing plants and recommends that 

RACT for natural gas processing plants 

be the implementation of an LDAR 

program equivalent to what is required 

under 40 CFR part 60 subpart VVa for 

equipment (with the exception of 

compressors and sampling connection 

systems) in VOC service. The subpart 

VVa leak detection and repair program 

requires the annual monitoring of 

connectors using an organic vapor 

analyzer (OVA) or toxic vapor analyzer 

(TVA) (with leaks defined as readings of 

at least 500 ppm), monthly monitoring 

of valves (where again, leaks are defined 

as readings of at least 500 ppm), and 

requires open-ended lines and pressure 

relief devices to operate with no 

detectable emissions (defined as 

emissions of less than 500 ppm above 

background). 

EPA finds that Subpart 203–7 of New 

York’s part 203, ‘‘Oil and Natural Gas 

Sector’’ satisfies and goes beyond the 

requirements of the 2016 CTG. The 

NYSDEC requires LDAR, as specified in 

Subpart 203–7 in order to monitor for 

CH4 and VOC. 

Subpart 203–8, ‘‘Vapor Collection 

Systems and Vapor Control Devices’’ 

Beginning on January 1, 2023, Subpart 

203–8 applies to equipment that must 

be controlled using a vapor collection 

system and control device pursuant to 

the requirements specified in Part 203. 

The vapor collection system shall direct 

the collected vapors to a sales gas 

system, or a fuel gas system. If no sales 

gas system or fuel gas system is 

available at the facility, the owner or 

operator must control the collected 

vapors by January 1, 2024. Any vapor 

control device required must achieve at 

least 95 percent vapor collection control 

efficiency of total emissions and must 

meet all applicable federal and state 

requirements. Vapor collection systems 

and control devices may be taken out of 

service for up to 30 days per rolling 12- 

month period to perform maintenance 

while the facility continues to operate. 

A time extension to perform 

maintenance not to exceed 14 days per 

12-month period may be granted by the 

NYSDEC. If an alternate vapor control 

device compliant with section 203–8.1 

is installed prior to conducting 

maintenance, and the vapor collection 

and control system continues to collect 

and control vapors during the 

maintenance operation consistent with 

the applicable standards specified in 

Subpart 203–8, the event does not count 

towards the 30-day limit. Vapor 

collection system and control device 

shutdowns that result from emergencies 

are not subject to enforcement action, 

provided the equipment resumes 

normal operation immediately after the 

emergency. 

EPA’s 2016 CTG states that routing 

emissions to a process via a vapor 

recovery unit (VRU) should have at least 

a 95 percent efficiency rating. 

EPA finds that Subpart 203–8 of New 

York’s part 203, ‘‘Oil and Natural Gas 

Sector’’ satisfies and goes beyond the 

requirements of the CTG by requiring 

vapor recovery and control for a wider 

range of applications in the oil and 

natural gas industry. 

Subpart 203–9, ‘‘Feasibility and Safety’’ 

Subpart 203–9 states that a repair or 

replacement may not be delayed unless 

it results in a vented blowdown, a 

gathering and boosting station 

shutdown, a well shutdown, a well 

shut-in, or rationale for continued 

operation is submitted to the NYSDEC 

to be later deemed technically infeasible 

or unsafe by the New York State 

Department of Public Service or other 

federal or state regulatory agency. 

The repair or replacement delay may 

be extended until the next compressor 

station shutdown, the next gathering 

and boosting station shutdown, well 

shutdown, well shut-in, the next 

unscheduled, planned or emergency 

vent blowdown, or within one year. 

EPA’s 2016 CTG recommends certain 

RACT control requirements with 

functional and safety exceptions. 

EPA finds that Subpart 203–9 of New 

York’s part 203, ‘‘Oil and Natural Gas 

Sector’’ satisfies the requirements of the 

2016 CTG. 

Subpart 203–10, ‘‘Reporting and 

Recordkeeping’’ 

Subpart 203–10.1 requires baseline 

reporting and applies to all sources as 

described in Section 203–1. Owners or 

operators of components or processes 

subject to Subpart 203–10 must submit 

a report to the NYSDEC by March 31, 

2023, or by March 31st of the year 

following initiation of operation. The 

report shall be in a format approved by 

the NYSDEC and shall list the number 

and type of components, including but 

not limited to the following: (1) 

Separators, (2) storage vessels, (3) 

compressors, (4) gas drying systems, (5) 

pneumatic devices, and (6) metering 

and regulating systems. 

Subpart 203–10.2 requires 

recordkeeping. The recordkeeping 

requirements for reciprocating natural 

gas compressors are to maintain for at 

least five years the following: (1) A 

record from the date of each rod packing 

leak concentration measurement found 

above the minimum leak threshold as 

defined in Section 203–4.4; (2) a record 

of each rod packing emission flow rate 

measurement from the date of each 

emissions flow rate measurement; (3) a 

record that documents the date(s) and 

hours of operation a compressor is 


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Federal Register / Vol. 87, No. 115 / Wednesday, June 15, 2022 / Proposed Rules 36101 

operated in order to demonstrate 

compliance with the rod packing leak 

concentration or emission flow rate 

measurement in the event that the 

compressor is not operating during a 

scheduled inspection; and (4) records 

that provide proof that parts or 

equipment required to make necessary 

repairs have been ordered and installed. 

Owners or operators of centrifugal 

natural gas compressors must maintain, 

for at least five years, the following: (1) 

A record of each wet seal emission flow 

rate measurement from the date of each 

emissions flow rate measurement; (2) a 

record that documents the date(s) and 

hours of operation a compressor is 

operated in order to demonstrate 

compliance with the wet seal emission 

flow rate measurement in the event that 

the compressor is not operating during 

a scheduled inspection; and (3) records 

that provide proof that parts or 

equipment required to make necessary 

repairs have been ordered and installed. 

Owners or operators of natural gas 

actuated pneumatic devices and vapor 

collection system and vapor control 

devices must maintain, for at least five 

years, the following: (1) A record of the 

emission flow rate measurement; (2) a 

record of each LDAR inspection; (3) 

component leak and repair 

documentation from the date of each 

inspection; (4) records that provide 

proof that parts or equipment required 

to make necessary repairs have been 

ordered and installed; and (5) gas 

service utility records that demonstrate 

that a system has been temporarily 

classified as critical to reliable public 

gas operation throughout the duration of 

the classification period. 

EPA’s 2016 CTG recommends that air 

agencies specify operating, 

recordkeeping, and reporting 

requirements to document compliance 

with the CTG. When implementing an 

LDAR program, the CTG recommends 

that air agencies consider including 

recordkeeping requirements that require 

owners/operators of subject facilities to 

maintain a list of identification numbers 

for all equipment subject to an 

equipment leak regulation. The CTG 

appendix includes annual 

recordkeeping and reporting 

requirements for pneumatic controllers, 

compressors, pneumatic pumps, and 

fugitive emissions. 

EPA finds that Subpart 203–10 of 

New York’s part 203, ‘‘Oil and Natural 

Gas Sector,’’ satisfies the requirements 

of the 2016 CTG. 

III. Proposed Action 

EPA is proposing to approve New 

York’s part 200 ‘‘General Provisions’’ 

section 200.9 amendment to Table 1 to 

add regulation 203–7.1(a) with a CFR 

citation of ‘‘40 CFR part 60, appendix 

A–7 (July 1, 2017).’’ EPA is also 

proposing to approve part 203, ‘‘Oil and 

Natural Gas Sector’’ control measure 

because it satisfies the 2016 Oil and 

Natural Gas Industry CTG. EPA is 

soliciting public comments on the 

issues discussed in this notice or on 

other relevant matters. These comments 

will be considered before taking final 

action. Interested parties may 

participate in the federal rulemaking 

procedure by submitting written 

comments to this proposed rule by 

following the instructions listed in the 

ADDRESSES section of this Federal 

Register. 

IV. Incorporation by Reference 

In this rule, the EPA is proposing to 

include in a final EPA rule regulatory 

text that includes incorporation by 

reference. In accordance with 

requirements of 1 CFR 51.5, EPA is 

proposing to incorporate by reference 

the adoption of Title 6 of the NYCRR 

part 203, ‘‘Oil and Natural Gas Sector’’ 

of the New York Administrative Code 

that implements New York’s RACT 

regulations for the oil and gas CTG, 

including attendant revisions to 6 

NYCRR part 200, ‘‘General Provisions,’’ 

section 200.9, Table 1, ‘‘Referenced 

material,’’ as described in section II of 

this preamble. 

The EPA has made, and will continue 

to make, these materials generally 

available through www.regulations.gov 

and/or at the EPA Region 2 Office 

(please contact the person identified in 

the FOR FURTHER INFORMATION CONTACT

section of this preamble for more 

information). 

V. Statutory and Executive Order 

Reviews 

Under the CAA, the Administrator is 

required to approve a SIP submission 

that complies with the provisions of the 

CAA and applicable Federal regulations. 

42 U.S.C. 7410(k); 40 CFR 52.02(a). 

Thus, in reviewing SIP submissions, 

EPA’s role is to approve state choices, 

provided that they meet the criteria of 

the CAA. Accordingly, this action 

merely proposes to approve state law as 

meeting federal requirements and does 

not impose additional requirements 

beyond those imposed by state law. For 

that reason, this proposed action: 

• Is not a ‘‘significant regulatory 

action’’ subject to review by the Office 

of Management and Budget under 

Executive Order 12866 (58 FR 51735, 

October 4, 1993) and 13563 (76 FR 382, 

January 21, 2011); 

• Does not impose an information 

collection burden under the provisions 

of the Paperwork Reduction Act (44 

U.S.C. 3501 et seq.); 

• Is certified as not having a 

significant economic impact on a 

substantial number of small entities 

under the Regulatory Flexibility Act (5 

U.S.C. 601 et seq.); 

• Does not contain any unfunded 

mandate or significantly or uniquely 

affect small governments, as described 

in the Unfunded Mandates Reform Act 

of 1995 (Pub. L. 104–4); 

• Does not have federalism 

implications as specified in Executive 

Order 13132 (64 FR 43255, August 10, 

1999); 

• Is not an economically significant 

regulatory action based on health or 

safety risks subject to Executive Order 

13045 (62 FR 19885, April 23, 1997); 

• Is not a significant regulatory action 

subject to Executive Order 13211 (66 FR 

28355, May 22, 2001); 

• Is not subject to requirements of 

Section 12(d) of the National 

Technology Transfer and Advancement 

Act of 1995 (15 U.S.C. 272 note) because 

application of those requirements would 

be inconsistent with the CAA; and 

• Does not provide EPA with the 

discretionary authority to address, as 

appropriate, disproportionate human 

health or environmental effects, using 

practicable and legally permissible 

methods, under Executive Order 12898 

(59 FR 7629, February 16, 1994). 

In addition, this proposed rulemaking 

action, pertaining to New York’s oil and 

gas sector control measures submission, 

is not approved to apply on any Indian 

reservation land or in any other area 

where the EPA or an Indian tribe has 

demonstrated that a tribe has 

jurisdiction. In those areas of Indian 

country, the proposed rule does not 

have tribal implications and will not 

impose substantial direct costs on tribal 

governments or preempt tribal law as 

specified by Executive Order 13175 (65 

FR 67249, November 9, 2000). 

List of Subjects in 40 CFR Part 52 

Environmental protection, Air 

pollution control, Incorporation by 

reference, Nitrogen dioxide, 

Intergovernmental relations, Ozone, 

Reporting and recordkeeping 

requirements, Volatile organic 

compounds. 

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

Lisa Garcia, 

Regional Administrator, Region 2. 

[FR Doc. 2022–12831 Filed 6–14–22; 8:45 am] 

BILLING CODE 6560–50–P 


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