[Federal Register Volume 87, Number 83 (Friday, April 29, 2022)]
[Rules and Regulations]
[Pages 25408-25410]
[FR Doc No: 2022-09220]

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DEPARTMENT OF HOMELAND SECURITY

Coast Guard

33 CFR Part 165

[Docket Number USCG-2022-0295]
RIN 1625-AA00

Safety Zone; Motus Myrtle Beach Triathlon, Myrtle Beach, SC

AGENCY: Coast Guard, DHS.

ACTION: Temporary final rule.

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SUMMARY: The Coast Guard is establishing a temporary safety zone on
certain waters of the Atlantic Intracoastal Waterway, near Myrtle
Beach, SC. This action is necessary to ensure the safety of life on
navigable waters of the United States during the Motus Myrtle Beach
Triathlon Swim event. During the enforcement period, no person or
vessel may enter, transit through, anchor in, or remain within the
designated area unless authorized by the Captain of the Port Charleston
(COTP) or a designated representative.

DATES: This rule is effective from 7:30 a.m. to 9:30 a.m., on May 1,
2022.

ADDRESSES: To view documents mentioned in this preamble as being
available in the docket, go to https://www.regulations.gov, type USCG-
2022-0295 in the search box and click ``Search.'' Next, in the Document
Type column, select ``Supporting & Related Material.''

FOR FURTHER INFORMATION CONTACT: If you have questions about this
temporary final rule, call or email LCDR Chad Ray, Sector Charleston
Office of Waterways Management, Coast Guard; telephone<PHONE_NUMBER>,
email [email protected].

SUPPLEMENTARY INFORMATION:

I. Table of Abbreviations

CFR Code of Federal Regulations
DHS Department of Homeland Security
FR Federal Register
NPRM Notice of proposed rulemaking
Sec.  Section
U.S.C. United States Code

II. Background Information and Regulatory History

    The Coast Guard is issuing this temporary rule without prior notice
and opportunity to comment pursuant to authority under section 4(a) of
the Administrative Procedure Act (APA) (5 U.S.C. 553(b)). This
provision authorizes an agency to issue a rule without prior notice and
opportunity to comment when the agency for good cause finds that those
procedures are ``impracticable, unnecessary, or contrary to the public
interest.'' The primary justification for this action is that the Coast
Guard was given short notice from the event sponsor, that the dates
would not align with the dates of the event in the special local
regulation. Therefore, it is impracticable to publish an NPRM because
we lack sufficient time to provide a reasonable comment period and then
consider those comments before issuing the rule. It would be
impracticable and contrary to the public interest to delay promulgating
this rule, as it is necessary to protect the safety of participants,
spectators, and vessels transiting near the race area during the Motus
Myrtle Beach Triathalon event on May 1, 2022.
    Under 5 U.S.C. 553(d)(3), the Coast Guard finds that good cause
exists for making this rule effective less than 30 days after
publication in the Federal Register. Delaying the effective date of
this rule would be impracticable because the safety zone must be
established by May, 1, 2022 to ensure the safety of life on navigable
waters of the United States during the event.

III. Legal Authority and Need for Rule

    The Coast Guard is issuing this rule under authority in 46 U.S.C.
70034. The Captain of the Port Charleston (COTP) has determined that
potential hazards associated with the large number of participants and
spectators during the swim will be a safety concern. The purpose of the
rule is to ensure the safety of participants, spectators, the general
public, vessels and the navigable waters in the safety zone before,
during and after the scheduled swim.

IV. Discussion of the Rule

    This rule establishes a safety zone from 7:30 a.m. until 9:30 a.m.,
on May 1, 2022. The safety zone will cover certain waters of the
Atlantic Intracoastal Waterway near near Myrtle Beach, South Carolina
during the Motus Myrtle Beach Triathalon event. The duration of the
safety zone is intended to ensure the safety of the participants,
spectators, and the general public during the scheduled 7:30 a.m. to
9:30 a.m. race. No vessel or person will be permitted to enter, transit
through, anchor in or remain within the safety zone without obtaining
permission from the COTP or a designated representative. If
authorization to enter, transit through, anchor in, or remain within
the saftey zone is granted by the COTP or a designated representative,
all persons and vessels receiving such authorization must comply with
the instructions of the COTP or a designated representative. The COTP
will inform the public of the safety zone by Local Notice to Mariners,
Broadcast Notice to Mariners, or by on-scene designated
representatives.

V. Regulatory Analyses

    We developed this rule after considering numerous statutes and
Executive orders related to rulemaking. Below we summarize our analyses
based on a number of these statutes and

Executive orders, and we discuss First Amendment rights of protestors.

A. Regulatory Planning and Review

    Executive Orders 12866 and 13563 direct agencies to assess the
costs and benefits of available regulatory alternatives and, if
regulation is necessary, to select regulatory approaches that maximize
net benefits. This rule has not been designated a ``significant
regulatory action,'' under Executive Order 12866. Accordingly, this
rule has not been reviewed by the Office of Management and Budget
(OMB).
    This regulatory action determination is based on the following
reasons: (1) The safety zone only being enforced for a total of two
hours; (2) although persons and vessels may not enter, transit through,
anchor in, or remain within the zone without authorization from the
COTP or a designated representative, they may operate in the
surrounding area during the enforcement period; and (3) persons and
vessels may still enter, transit through, anchor in, or remain within
the areas during the enforcement period if authorized by the COTP or a
designated representative.

B. Impact on Small Entities

    The Regulatory Flexibility Act of 1980, 5 U.S.C. 601-612, as
amended, requires Federal agencies to consider the potential impact of
regulations on small entities during rulemaking. The term ``small
entities'' comprises small businesses, not-for-profit organizations
that are independently owned and operated and are not dominant in their
fields, and governmental jurisdictions with populations of less than
50,000. The Coast Guard certifies under 5 U.S.C. 605(b) that this rule
will not have a significant economic impact on a substantial number of
small entities.
    While some owners or operators of vessels intending to transit the
safety zone may be small entities, for the reasons stated in section
V.A above, this rule will not have a significant economic impact on any
vessel owner or operator.
    Under section 213(a) of the Small Business Regulatory Enforcement
Fairness Act of 1996 (Pub. L. 104-121), we want to assist small
entities in understanding this rule. If the rule would affect your
small business, organization, or governmental jurisdiction and you have
questions concerning its provisions or options for compliance, please
call or email the person listed in the FOR FURTHER INFORMATION CONTACT
section.
    Small businesses may send comments on the actions of Federal
employees who enforce, or otherwise determine compliance with, Federal
regulations to the Small Business and Agriculture Regulatory
Enforcement Ombudsman and the Regional Small Business Regulatory
Fairness Boards. The Ombudsman evaluates these actions annually and
rates each agency's responsiveness to small business. If you wish to
comment on actions by employees of the Coast Guard, call 1-888-REG-FAIR
(1-888-734-3247). The Coast Guard will not retaliate against small
entities that question or complain about this rule or any policy or
action of the Coast Guard.

C. Collection of Information

    This rule will not call for a new collection of information under
the Paperwork Reduction Act of 1995 (44 U.S.C. 3501-3520).

D. Federalism and Indian Tribal Governments

    A rule has implications for federalism under Executive Order 13132,
Federalism, if it has a substantial direct effect 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. We have analyzed this rule under that Order and have
determined that it is consistent with the fundamental federalism
principles and preemption requirements described in Executive Order
13132.
    Also, this rule does not have tribal implications under Executive
Order 13175, Consultation and Coordination with Indian Tribal
Governments, because it does not have a substantial direct effect on
one or more Indian tribes, on the relationship between the Federal
Government and Indian tribes, or on the distribution of power and
responsibilities between the Federal Government and Indian tribes.

E. Unfunded Mandates Reform Act

    The Unfunded Mandates Reform Act of 1995 (2 U.S.C. 1531-1538)
requires Federal agencies to assess the effects of their discretionary
regulatory actions. In particular, the Act addresses actions that may
result in the expenditure by a State, local, or tribal government, in
the aggregate, or by the private sector of $100,000,000 (adjusted for
inflation) or more in any one year. Though this rule will not result in
such an expenditure, we do discuss the effects of this rule elsewhere
in this preamble.

F. Environment

    We have analyzed this rule under Department of Homeland Security
Directive 023-01, Rev. 1, associated implementing instructions, and
Environmental Planning COMDTINST 5090.1 (series), which guide the Coast
Guard in complying with the National Environmental Policy Act of 1969
(42 U.S.C. 4321-4370f), and have determined that this action is one of
a category of actions that do not individually or cumulatively have a
significant effect on the human environment. This rule involves a
safety zone that will prohibit persons and vessels from entering,
transiting through, anchoring in, or remaining within a limited area
along the Atlantic Intracoastal Waterway, near Myrtle Beach, SC during
a swim event lasting two hours. It is categorically excluded from
further review under paragraph L60(a) of Appendix A, Table 1 of DHS
Instruction Manual 023-01-001-01, Rev. 1. A Record of Environmental
Consideration supporting this determination is available in the docket.
For instructions on locating the docket, see the ADDRESSES section of
this preamble.

G. Protest Activities

    The Coast Guard respects the First Amendment rights of protesters.
Protesters are asked to call or email the person listed in the FOR
FURTHER INFORMATION CONTACT section to coordinate protest activities so
that your message can be received without jeopardizing the safety or
security of people, places or vessels.

List of Subjects in 33 CFR Part 165

    Harbors, Marine safety, Navigation (water), Reporting and
recordkeeping requirements, Security measures, Waterways.

    For the reasons discussed in the preamble, the Coast Guard amends
33 CFR part 165 as follows:

PART 165--REGULATED NAVIGATION AREAS AND LIMITED ACCESS AREAS

0
1. The authority citation for part 165 continues to read as follows:

    Authority: 33 U.S.C. 1231; 50 U.S.C. 191; 33 CFR 1.05-1, 6.04-1,
6.04-6, and 160.5; Department of Homeland Security Delegation No.
0170.1, Revision No. 01.2.

0
2. Add Sec.  165.T07-0295 to read as follows:.

Sec.  165.T07-0295  Safety Zone; Motus Myrtle Beach; Myrtle Beach, SC.

    (a) Location. The following is a safety zone: Certain waters of the
Atlantic Intracoastal Waterway within the

following two points of position and the North shore: 33[deg]45'03'' N,
78[deg]50'47'' W to 33[deg]45'18'' N, 78[deg]50'14'' W, located in
Myrtle Beach, South Carolina.
    (b) Definitions. As used in this section, ``designated
representative'' means a Coast Guard Patrol Commander, including a
Coast Guard coxswain, petty officer, or other officer operating a Coast
Guard vessel and a Federal, State, and local officer designated by or
assisting the Captain of the Port Charleston (COTP) in the enforcement
of the safety zone.
    (c) Regulations. (1) All persons and vessels are prohibited from
entering, transiting through, anchoring in, or remaining within the
safety zone unless authorized by the COTP Charleston or a designated
representative.
    (2) Persons and vessels desiring to enter, transit through, anchor
in, or remain within the regulated area may contact the COTP Charleston
by telephone at<PHONE_NUMBER>, or a designated representative via VHF
radio on channel 16, to request authorization. If authorization is
granted, all persons and vessels receiving such authorization must
comply with the instructions of the COTP Charleston or a designated
representative.
    (d) Enforcement period. This rule will be enforced from May 1, 2022
from 7:30 a.m. until 9:30 a.m.

    Dated: April 22, 2022.
J.D. Cole,
Captain, U.S. Coast Guard, Captain of the Port Charleston.
[FR Doc. 2022-09220 Filed 4-28-22; 8:45 am]
BILLING CODE 9110-04-P


Oil and Natural Gas Industry Estimated Reasonably Available Control
Technology Emission Reductions and Cost of Control

1.0	INTRODUCTION

The Clean Air Act (CAA) provides that state implementation plans (SIPs)
for ozone nonattainment (NA) areas must include reasonably available
control technology (RACT) for sources of emissions, and stipulates that
for moderate (and higher) ozone nonattainment (NA) areas, states must
revise their SIPs to include RACT for volatile organic compound (VOC)
emission sources covered by control techniques guidelines (CTG).
Furthermore, the CAA requires that SIPs for states in ozone transport
regions (OTRs) must comply with and implement RACT with respect to all
sources of VOC in the state covered by a CTG. The proposed Control
Techniques Guidelines for the Oil and Natural Gas Industry, henceforth
the CTG, proposes recommendations for RACT for select emission sources
in the oil and natural gas industry.

The proposed CTG provides state, local and tribal air agencies (air
agencies) with information to assist them in determining RACT for VOC
from select oil and natural gas industry emission sources. During the
development of the guidelines, the U.S. Environmental Protection Agency
(EPA) evaluated the sources of VOC emissions from the oil and natural
gas industry and the available control approaches to reduce these
emissions, including the costs of the evaluated approaches. The EPA is
recommending RACT for compressors, natural gas-driven pneumatic
controllers, natural gas-driven pneumatic pumps, storage vessels,
equipment leaks at natural gas processing plants and fugitive emissions
at well sites and compressor stations in the oil and natural gas
industry. Table 1-1 presents a summary of the recommended RACT level of
control for each of these sources.

Air agencies can use the recommendations in the CTG to inform their own
determination as to what constitutes RACT for VOC emissions for the oil
and natural gas industry sources included in the CTG. The information
contained in the CTG is provided only as guidance. The CTG does not
change, or substitute for, requirements specified in applicable sections
of the CAA or the EPA’s regulations; nor is it a regulation itself.
The CTG does not impose any requirements on facilities in the oil and
natural gas industry. It provides only recommendations for air agencies
to consider when they determine RACT. Air agencies are free to implement
other technically-sound approaches that are consistent with the CAA and
the EPA’s implementing regulations.

To understand the potential impact of the CTG, the EPA conducted a
scoping analysis based on a snapshot of the existing oil and natural gas
industry. While the CTG itself does not require facilities in the oil
and natural gas industry to adopt specific control technologies,
assessing the emission reductions and costs of the case where
recommended RACTs were adopted by oil and natural gas emission sources
in moderate and higher ozone NA areas and the OTR provides a reasonable
basis for the impact of the RACT requirements ultimately determined by
air agencies. Therefore, this document presents an assessment of the
emission reductions and net expenditures required by the industry in the
case where all affected oil and natural gas emission sources that
existed in 2012 adopt the recommended RACT. It is estimated that in this
case VOC emissions would be reduced by approximately 82 thousand tpy at
an annualized net cost to the industry of approximately $76 million
dollars based on the CTG recommended RACT. Additionally, the recommended
RACT is estimated to reduce methane emissions by approximately 220
thousand tpy and hazardous air pollutant (HAP) emissions by three
thousand tpy.

The assessment provides a reasonable estimate of the magnitude of
expected emission reductions and net costs to the source category
associated with the proposed CTG; however there are limitations,
including some that suggest the cost estimates may be conservative in
some dimensions. For example, while the analysis attempts to include
existing state regulations, the 2012 snapshot may not fully account for
state permit limits for individual sources that meet or exceed the
recommended RACT level of control. Thus, the percentage of existing
sources that are already achieving the recommended RACT level of control
may be underestimated which would lead to fewer emission reductions and
lower expected costs for owners and operators as a result of the CTG.
Also, air agencies have the flexibility of determining RACT that may
differ from what the EPA recommends. This flexibility allows them to
potentially take advantage of their local conditions and implement a
tailored RACT which may lower the costs for sources in their
jurisdiction. This analysis is based on industry averages and does not
account for heterogeneity in sources that affect the costs or emission
reductions. The resulting state and local regulations may also require a
lower level of control or may affect a lower number of sources than were
included in the analysis presented here. The focus on a 2012 snapshot of
existing sources may include some sources that are no longer in use.
However, any small changes to the existing universe of sources it is not
expected to notably change the magnitude of the estimates in this
analysis.

The document is organized as follows:

Section 2 presents a short discussion about the moderate or higher ozone
NA and OTR areas impacted by RACT.

Sections 3 presents a summary of the information used to determine the
number of sources, baseline emissions, emission reductions and costs.

Section 4 presents the methodology used to estimate baseline emissions,
emission reductions and costs.

Section 5 presents a summary of the VOC RACT emission reductions and
costs.

Table 1-  SEQ Table_3- \* ARABIC  1 . Summary of the Oil and Natural
Gas Industry Emission Sources and

Proposed Recommended RACT

Emission Source	Applicability	RACT Recommendations

1. Storage Vessels	Individual storage vessel 	95 percent reduction of
VOC emissions from storage vessels with a potential to emit (PTE)
greater than or equal to 6 tpy

2. Natural Gas-Driven Pneumatic Controllers	Individual continuous bleed,
natural gas-driven pneumatic controller located at a natural gas
processing plant	Natural gas bleed rate of zero scfh (unless there are
functional needs, including but not limited to response time, safety and
positive actuation, requiring a bleed rate greater than zero scfh).

	Individual continuous bleed natural gas-driven pneumatic controller
located from the wellhead to the natural gas processing plant or point
of custody transfer to an oil pipeline	Natural gas bleed rate less than
or equal to 6 scfh (unless there are functional needs, including but not
limited to response time, safety and positive actuation, requiring a
bleed rate greater than 6 scfh).

3. Natural Gas-Driven Pneumatic Pumps	Individual natural gas-driven
chemical/methanol and diaphragm pump located at a natural gas processing
plant	Zero natural gas emissions

	Individual natural gas-driven chemical/methanol and diaphragm pump at
locations other than natural gas processing plants from the well site to
the point of custody transfer to the natural gas transmission and
storage segment.	-If there is an existing control device at the location
of the pneumatic pump, reduce VOC emissions from each gas-driven
chemical/methanol and diaphragm pump at the location by 95 percent or
greater.

- If there is no existing control device at the location of the
pneumatic pump, submit a certification that there is no device.

4. Compressors (Centrifugal and Reciprocating)	Individual reciprocating
compressor located between the wellhead and point of custody transfer to
the natural gas transmission and storage segment. 	Reduce VOC emissions
by replacing reciprocating compressor rod packing after 26,000 hours of
operation or 36 months since the most recent rod packing replacement.
Alternatively, route rod packing emissions to a process through a closed
vent system under negative pressure.

	Individual reciprocating compressor located at a well site, or an
adjacent well site and servicing more than one well site 	RACT would not
apply.

	Individual centrifugal compressor using wet seals that is located
between the wellhead and point of custody transfer to the natural gas
transmission and storage segment. 	Reduce VOC emissions from each
centrifugal compressor wet seal fluid gassing system by 95 percent or
greater.

	Individual centrifugal compressor using wet seals located at a well
site, or an adjacent well site and servicing more than one well site
RACT would not apply.

	Individual centrifugal compressor using dry seals	RACT would not apply.

5. Equipment Leaks	Equipment components in VOC service located at a
natural gas processing plant	Implement the 40 CFR part 60, subpart VVa
LDAR program for natural gas processing plants constructed or modified
on or before August 23, 2011.

6. Fugitive Emissions	Individual well site with wells that produce, on
average, greater than 15 barrel equivalents per day per well	Implement a
semiannual optical gas imaging (OGI) monitoring and repair program.

	Individual compressor station located from the wellhead to the point of
custody transfer to the natural gas transmission and storage segment or
point of custody transfer or to an oil pipeline	Implement a semiannual
OGI monitoring and repair program.

2	MODERATE OR HIGHER OZONE NA AND OTR AREAS

	In order to estimate the potential moderate or higher ozone NA area and
OTR area (referred to collectively as “RACT-impacted areas”)
emission reduction impacts for the proposed RACT recommendations, we
obtained information on U.S. ozone NA areas from the EPA’s Greenbook
as of January 30, 2015 (  HYPERLINK
"http://www.epa.gov/oaqps001/greenbk/ancl.html"
http://www.epa.gov/oaqps001/greenbk/ancl.html ). The list of the
moderate or higher ozone NA areas included in this analysis is presented
in Attachment 1 to this memorandum. The OTR areas included in this
analysis are the States of Connecticut, Delaware, Maine, Maryland,
Massachusetts, New Hampshire, New Jersey, New York, Pennsylvania, Rhode
Island, Vermont and the CMSA that includes the District of Columbia).

3	INFORMATION USED TO DETERMINE THE NUMBER OF SOURCES IMPACTED BY RACT,
RACT-IMPACTED AREA BASELINE EMISSIONS AND EMISSION REDUCTIONS AND COSTS
BASED ON RACT

Activity data, baseline emissions and emission reductions per source
were estimated based on information obtained from the following sources:

2012 DI Desktop U.S. oil and natural gas wells information (2012 DI
Desktop). Includes location and production information for oil and gas
wells in the U.S. Discussed further below.

Oil and Gas Journal (OGJ). Worldwide Gas Processing (Capacities as of
January 1, 2013, and average production). June 3, 2013. (2012 Gas
Processing Survey). Includes information on the number, location and
capacities of gas processing plants worldwide. Discussed further below.

Emissions information and counts for various emission sources were
obtained from facility-level data submitted to the Greenhouse Gas
Reporting Program (GHGRP) and data used to calculate national emissions
in the Inventory of U.S. Greenhouse Gas Emissions and Sinks. The
published data from 2013 was used in this analysis. For the purposes of
this document these data sources are referred to as "GHGRP" and “GHG
Inventory”.,

The proposed Control Techniques Guidelines for the Oil and Natural Gas
Source Industry (CTG). Includes information on the baseline VOC
emissions per unit, VOC emission reductions per unit, and VOC cost of
control per unit used in this analysis.

The TSD for the 2015 proposed NSPS standards is referred to in this
document as the “2015 NSPS TSD”.

The gas composition memorandum that was developed during the NSPS
process which characterizes an analysis of data to determine the gas
composition and develop ratios for natural gas composition for the
various segments of the oil and natural gas industry. This document is
referred to in this document as the "2011 Gas Composition Memorandum".

All of the calculations supporting the analyses in this document are
included in the CTG docket (Docket ID. EPA-HQ-OAR-2015-0216) in the form
of spreadsheets.

2012 DI Desktop Data

The EPA obtained well production data from the DI Desktop database dated
February, 2014. The DI Desktop data collected by DrillingInfo, Inc.
consists of oil and natural gas well information that provides
parameters describing the location, operator, and production
characteristics. The DI Desktop data extract from the DrillingInfo, Inc.
database included the population of all wells with gas or hydrocarbon
liquid production during 2010 to 2012 and with a recorded completion
year of 2010 to the date of the extract (February, 2014).

The 2012 DI Desktop data was queried to identify oil and natural gas
wells in production in 2012 in RACT-impacted areas using Federal
Information Processing Standards (FIPS) codes for the respective areas.
Gas wells were defined as those wells with an average gas to liquids
ratio greater than or equal to 100,000 standard cubic feet per barrel
over the lifetime of the well, and oil wells were defined as those wells
with an average gas to liquids ratio less than 100,000 standard cubic
feet per barrel over the lifetime of the well. If a well had liquids
production but no gas production, it was classified as an oil well, and
if a well had gas production but no liquids production, it was
classified as a gas well.

As a result of this analysis, for all producing wells, 101,464 oil and
gas wells (63,936 oil wells and 37,528 gas wells) were identified in
moderate or higher ozone NA areas and 90,232 oil and gas wells (24,169
oil wells and 66,063 gas wells) were identified in OTR areas. An
estimated 22,426 oil and gas wells (1,249 oil wells and 21,177 gas
wells) were located in OTR areas that were also located in moderate or
higher ozone NA areas. For producing wells that produce, on average,
greater than 15 barrel equivalents per day, 25,212 oil and gas wells
(13,336 oil wells and 11,876 gas wells) were identified in moderate or
higher ozone NA areas and 4,642 oil and gas wells (277 oil wells and
4,365 gas wells) were identified in OTR areas. An estimated 932 oil and
gas wells (232 oil wells and 700 gas wells) were located in OTR areas
that were also located in moderate or higher ozone nonattainment areas.
States that had wells with RACT-impacted areas include California,
Maryland, New York, Pennsylvania, Texas and Virginia.

This information was used to:

estimate the number and location of all producing wells and individual
well sites with wells that produce, on average, greater than 15 barrel
equivalents per day in OTR and moderate or higher ozone NA areas (as
noted),

estimate the number and location of storage vessels in OTR and moderate
or higher ozone NA areas (assuming one storage vessel per well),

estimate the number of production segment pneumatic controllers and
pumps located in OTR and moderate or higher ozone NA areas (using the
percentage of the number of wells located in each of the respective
areas), and

estimate the number of gathering and boosting stations located in OTR
and moderate or higher ozone NA areas (using the average of the
percentage of wells and the percentage of total natural gas processing
plants located in each respective areas).

OGJ Worldwide Gas Processing Survey (Capacities as of January 1, 2013,
and Average Production)

The OGJ Gas Processing Survey reflecting capacities as of January 1,
2013 (which would reflect capacities for 2012) was used to obtain
location information of natural gas processing plants in OTR and
moderate or higher ozone NA areas. Of the estimated 606 natural gas
processing plants in the U.S., an estimated 10 natural gas processing
plants were located in OTR areas and 40 were located in moderate or
higher ozone NA areas. None of the 40 natural gas processing plants in
moderate or higher ozone NA areas were located in OTR areas. States that
had processing plants with RACT-impacted areas include California,
Pennsylvania and Texas.

This information was used to:

estimate the number and location of natural gas processing plants in OTR
and moderate or higher ozone NA areas,

estimate the number of processing segment compressors and pneumatic
controllers located in OTR and moderate or higher ozone NA areas (using
the percentage of the number of gas processing plants located in OTR and
moderate or higher ozone NA areas), and

estimate the number of gathering and boosting stations located in OTR
and moderate or higher ozone NA areas (using the average of the
percentage of wells and the percentage of gas processing plants located
in OTR and moderate or higher ozone NA areas).

4	METHODOLOGY USED TO ESTIMATE RACT-IMPACTED AREA BASELINE EMISSIONS,
EMISSION REDUCTIONS AND COSTS

	The following paragraphs present the methodologies used to estimate
RACT-impacted area baseline emissions, emission reductions and costs for
storage vessels, pneumatic controllers, pneumatic pumps, compressors,
equipment leaks at natural gas processing plants and fugitive emissions
at well sites and compressor stations.

4.1	Storage Vessels

4.1.1 	Approach

RACT-impacted baseline emissions and emission reductions from storage
vessels were calculated by multiplying the number of estimated
uncontrolled storage vessels by emission factors based on oil and
condensate production and production information from the 2012 DI
Desktop database. Emission reductions were estimated by multiplying the
emissions calculated for each storage vessel by 95 percent. The
RACT-impacted area costs were estimated by multiplying the number of
RACT-impacted storage vessels by costs per storage vessel.

4.1.2 	RACT-Impacted Population of Storage Vessels

In order to estimate the number of storage vessels that would
potentially be impacted by RACT, we conducted an analysis using the
following procedures:

Estimated the number of wells in existence and located in RACT-impacted
areas in 2012 (assuming one controlled storage vessel per well) based on
2012 DI Desktop location information.

Subtracted the wells completed in 2012 from this number (assuming that
these storage vessels would be subject to the NSPS).

Subtracted the number of storage vessels subject to and presumed to be
controlled at baseline under state air regulations from the number of
storage vessels that would potentially be impacted by RACT,

Used the emission factor from a typical storage vessel within each
throughput bracket established under the NSPS to estimate emissions
based on 2012 DI Desktop production information.

Determined the number of storage vessels that would likely have VOC
emissions greater than or equal to the RACT recommended applicability
threshold of 6 tons per year (tpy).

Estimated the number of storage vessels that would likely have VOC
emissions greater than or equal to 6 tpy that would also be subject to
and controlled under state air regulations.

Using information on state environmental regulations developed for the
CTG, we subtracted the number of storage vessels subject to and
controlled under state air regulations from the number of storage
vessels with VOC emissions greater than or equal to 6 tpy to determine
the number of storage vessels that would potentially be impacted by
RACT.

Attachments 2 and 3 to this memorandum include the RACT-impacted storage
vessel population and baseline emissions analysis. Table 4-1 presents
the estimated number of RACT-impacted storage vessels.

Table 4-1.  RACT-Impacted Population of Storage Vessels

Emission Source	Number of RACT-Impacted Storage Vessels

Moderate or Higher Ozone NA Areas Outside of OTR Areas	OTR Areas
Moderate or Higher Ozone NA Areas/OTR Areas

Storage Vessels	2,451	11	2,462

4.1.3	RACT-Impacted Storage Vessel Baseline Emissions, Emission
Reductions and Costs

Using average storage vessel VOC emission factors based on well
production rate brackets developed under the NSPS and 2012 DI Desktop
production information, we calculated the RACT-impacted number of
storage vessels and baseline VOC, methane and HAP emissions.
RACT-impacted storage vessel emission reductions were estimated by
multiplying the calculated baseline emissions per storage vessel by the
95 percent reduction efficiency attributable to combustion or capture
and recovery. Using VOC to methane and VOC to HAP ratios developed for
the oil and natural gas industry as presented in the 2011 Gas
Composition memorandum, we estimated methane and HAP baseline emissions
and emission reductions for storage vessels. Table 4-2 presents the
estimated RACT-impacted storage vessel baseline emissions. RACT-impacted
storage vessel emission reductions are provided in Table 4-3.

Table 4-2. RACT-Impacted Storage Vessel Baseline Emissions

Emission Source	RACT-Impacted Storage Vessel Baseline Emissions (tpy)

	Moderate or Higher Ozone NA Areas Outside of OTR Areas	OTR Areas
Moderate or Higher Ozone NA Areas /OTR Areas

	VOC	CH4	HAP	VOC	CH4	HAP	VOC	CH4	HAP

Storage Vessels	24,515	5,704	769	101	21	3	24,617	5,095	773

Table 4-3. RACT-Impacted Storage Vessel Emission Reductionsa

Emission Source	Type of Control

 	RACT-Impacted Storage Vessel Emission Reductions (tpy)

Moderate or Higher Ozone NA Areas Outside of OTR Areas	OTR Areas
Moderate or Higher Ozone NA Areas/OTR Areas

VOC	CH4	HAP	VOC	CH4	HAP	VOC	CH4	HAP

Storage Vessel	95% Control	23,290	4,820	731	96	20	3	23,386	4,840	734

a Assumes 94 percent of sources will use a combustion control device and
6 percent will use a VRU to comply with the recommended RACT.

Using the retrofit costs for a combustor or VRU developed for the CTG,
we multiplied these costs by the number of RACT-impacted storage
vessels, assuming 94 percent of the storage vessels would use combustion
and 6 percent would use a vapor recovery unit (VRU). The capital costs
and annual costs used for a combustion device was $100,986 and $22,228,
respectively. The capital costs and annual costs used for a VRU used was
$171,538 and $28,230, respectively. Gas savings is individual to
production and emission rate class. Gas savings was estimated for
storage vessels using a VRU only, assuming gas recovered would be valued
at $4 per Mcf of recovered natural gas. No gas savings was attributed to
storage vessels using combustion control. Attachment 2 presents the VRU
and combustion cost analysis. Table 4-4 presents the estimated
RACT-impacted storage vessel costs.

Table 4-4. RACT-Impacted Storage Vessel Costsa

Emission Point	Moderate or Higher Ozone NA Areas Outside of OTR Areas
OTR Areas	Moderate or Higher Ozone NA Areas/OTR Areas

	Capital ($)	Annual w/o savings ($/yr)	Annual w/ savings ($/yr)	Capital
($)	Annual w/o savings ($/yr)	Annual w/ savings ($/yr)	Capital ($)
Annual w/o savings ($/yr)	Annual w/ savings ($/yr)

Storage Vessel	$257,902,585 	$55,365,741 	$55,176,698 	$1,157,410
$248,469 	$247,688 	$259,059,995 	$55,614,210 	$55,424,387

a Assumes 94 percent of sources will use a combustion control device and
6 percent will use a VRU to comply with the recommended RACT.

4.2	Natural Gas-Driven Pneumatic Controllers

4.2.1 	Approach

RACT-impacted natural gas-driven pneumatic controller baseline emissions
and emission reductions were calculated by multiplying the number of
uncontrolled natural gas-driven pneumatic controllers reported in the
2012 GHG Inventory (assuming that they were natural gas-driven) by
emissions and emission reductions per controller. The RACT-impacted area
costs were estimated by multiplying the calculated RACT VOC emission
reductions by costs per controller.

4.2.2 	RACT-Impacted Population of Natural Gas-Driven Pneumatic
Controllers

Based on information in the 2012 GHG Inventory, there were an estimated
135 natural gas-driven pneumatic controllers in the processing segment
nationally. The percentage of natural gas processing plants located in
RACT-impacted areas based on the 2012 Gas Processing Survey was used to
estimate the number of RACT-impacted natural gas-driven pneumatic
controllers.

Similarly, based on information in the 2012 GHG Inventory, there were an
estimated 165,372 high bleed natural gas-driven pneumatic controllers
installed in the production segment nationally. The percentage of wells
located in RACT-impacted areas based on 2012 DI Desktop location
information was used to estimate the number of high bleed natural
gas-driven pneumatic controllers located in RACT-impacted areas.

Table 4-5 presents the estimated population of RACT-impacted natural
gas-driven pneumatic controllers.

Table 4-5.  RACT-Impacted Population of Natural Gas-Driven Pneumatic
Controllers

Segment	Number of RACT-Impacted Sources

Moderate or Higher Ozone NA Areas Outside of OTR Areas	OTR Areas
Moderate or Higher Ozone NA Areas/OTR Areas

Oil and Natural Gas Production 	10,219	11,666	21,885

Processing Plants	9	2	11

4.2.3	RACT-Impacted Natural Gas-Driven Pneumatic Controller Baseline
Emissions, Emission Reductions and Costs

RACT-impacted natural gas-driven pneumatic controller baseline emissions
were estimated by multiplying the population of natural gas-driven
pneumatic controllers and the VOC, methane and HAP baseline emissions
per natural gas-driven pneumatic controller. Using the cost and emission
reductions developed for the CTG, we estimated emission reductions and
costs by multiplying the number of natural gas-driven pneumatic
controllers by the emission reductions and costs per natural gas-driven
controller. For processing segment natural gas-driven pneumatic
controllers, we used the emission reductions and costs associated with
the use of an existing instrument air system. For production segment
natural gas-driven pneumatic controllers, we used the emission
reductions and costs associated with the replacement of an existing high
bleed controller with a low bleed controller. Using methane to HAP
ratios developed for the oil and natural gas industry as presented in
the 2011 Gas Composition memorandum, we estimated RACT-impacted natural
gas-driven pneumatic controller HAP baseline emissions and emission
reductions.

Tables 4-6 and 4-7 present the RACT-impacted natural gas-driven
pneumatic controller baseline emissions and emission reductions. Tables
4-8 and 4-9 present the RACT-impacted natural gas-driven pneumatic
controller costs.

Table 4-6. RACT-Impacted Natural Gas-Driven Pneumatic Controller
Baseline Emissions

Segment	Baseline Emissions Per Natural Gas-Driven Pneumatic Controller
(tpy)	RACT-Impacted Pneumatic Controller Baseline Emissions (tpy)

Moderate or Higher Ozone NA Areas Outside of OTR Areas	OTR Areas
Moderate or Higher Ozone NA Areas /OTR Areas

	VOC	CH4	HAP	VOC	CH4	HAP	VOC	CH4	HAP	VOC	CH4	HAP

Oil and Natural Gas Production 	1.5	5.3	0.055	15,057	54,162	567	17,189
61,831	647	32,246	115,993	1,214

Processing Plants	0.28	1.0	0.01	2.5	8.9	0.9	0.62	2.2	0.02	3.1	11	0.12

Table 4-7. RACT-Impacted Natural Gas-Driven Pneumatic Controller
Emission Reductions

Segment	Type of Control

 	Emission Reductions Per Pneumatic Controller (tpy)	RACT-Impacted
Pneumatic Controller Emission Reductions (tpy)

	Moderate or Higher Ozone NA Areas Outside of OTR Areas	OTR Areas
Moderate or Higher Ozone NA Areas/OTR Areas

VOC	Methane	HAP	VOC	CH4	HAP	VOC	CH4	HAP	VOC	CH4	HAP

Oil and Natural Gas Production 	Replace w/ Low Bleed	1.4	5.10	0.05
14,444	52,118	546	16,489	59,498	623	30,933	111,616	1,169

Processing Plants	Existing Instrument Air System	0.28	1.0	0.01	2.5	8.9
0.09	0.62	2.2	0.02	3.1	11	0.12

Table 4-8. Total Annual Costs and VOC Cost of Control Per Natural
Gas-Driven Pneumatic Controller

Segment	Natural Gas Savings Per Source (Mcf)	Total Value of Natural Gas
Savings Per Source ($/yr)	Total Capital Costs Per Source ($)	Total
Annual Costs Per Source ($/yr)	VOC Cost of Control ($/ton of VOC
reduced)

	w/o savings	w/ savings	w/o savings	w/ savings

Oil and Gas Production 	296	$1,184 	$2,698 	$296	($886)	$210 	($627)

Processing Plants	58	$232 	$2,000 	$285 	$53 	$1,018 	$190

Table 4-9. RACT-Impacted Natural Gas-Driven Pneumatic Controller Costs

Segment	Moderate or Higher Ozone NA Areas Outside of OTR Areas	OTR Areas
Moderate or Higher Ozone NA Areas/OTR Areas

	Capital ($)	Annual w/o savings ($yr)	Annual w/ savings ($/yr)	Capital
($)	Annual w/o savings ($/yr)	Annual w/ savings ($/yr)	Capital ($)
Annual w/o savings ($/yr)	Annual w/ savings ($/yr)

Oil and Gas Production 	$27,571,450 	$3,027,197 	($9,054,192)
$31,475,544 	$3,455,846 	($10,336,259)	$59,046,994 	$6,483,043
($19,390,451)

Processing Plants	$17,822 	$2,540 	$474 	$4,455 	$635 	$118 	$22,277
$3,175 	$592

4.3	Natural Gas-Driven Pneumatic Pumps

4.3.1 	Approach

RACT-impacted natural gas-driven pneumatic pump baseline emissions and
emission reductions were calculated by multiplying the number of
uncontrolled natural gas-driven pneumatic pumps reported in the 2012 GHG
Inventory (assuming they were all natural gas-driven pumps) by emissions
and emission reductions per pump. The RACT-impacted natural gas-driven
pneumatic pump costs were estimated by multiplying the calculated RACT
VOC emission reductions by costs per pump.

4.3.2 	RACT-Impacted Population of Natural Gas-Driven Pneumatic Pumps

Based on information in the 2012 GHG Inventory for oil production, there
were an estimated 14,408 diaphragm pumps and 14,293 piston pumps. The
number of pneumatic pumps reported in the 2012 GHG Inventory for gas
production was an estimated 37,477 pneumatic pumps (for both diaphragm
and piston pumps). Similar to the assumption used in the 2015 NSPS TSD,
we assumed that 50 percent of the gas production inventory pumps to be
diaphragm pumps and 50 percent of the pumps to be piston pumps. Based on
these assumptions, and assuming that all of the reported pumps were
natural gas-driven, we estimated that there were 33,147 diaphragm and
33,032 piston natural gas-driven pneumatic pumps in the production
segment nationally. The percentage of RACT-impacted wells based on 2012
DI Desktop location information was used to estimate the number of
RACT-impacted high bleed natural gas-driven pneumatic pumps.

The 2012 GHG Inventory did not estimate emissions from pneumatic pumps
for the natural gas processing segment.

Table 4-10 presents the estimated RACT-impacted population of natural
gas-driven pneumatic pumps.

Table 4-10.  RACT-Impacted Population of Natural Gas-Driven Pneumatic
Pumps

Pneumatic Pump Type 	Number of RACT-Impacted Sources

Moderate or Higher Ozone NA Areas Outside of OTR Areas	OTR Areas
Moderate or Higher Ozone NA Areas/OTR Areas

Diaphragm  	2,048	2,338	4,387

Piston 	2,041	2,330	4,371

4.3.3	RACT-Impacted Natural Gas-Driven Pneumatic Pump Baseline
Emissions, Emission Reductions and Costs

RACT-impacted natural gas-driven pneumatic pump baseline emissions were
estimated by multiplying the population of natural gas-driven pneumatic
pumps and the VOC, methane and HAP baseline emissions per diaphragm and
piston natural gas-driven pneumatic pump. Using the emission reductions
and costs developed for the CTG, we estimated the emission reductions
and costs by multiplying the number of natural gas-driven pneumatic
pumps by the emission reductions and costs associated with routing
emissions to an existing combustion device. Using methane to HAP ratios
developed for the oil and natural gas industry as presented in the 2011
Gas Composition memorandum, we estimated RACT-impacted natural
gas-driven pneumatic pump HAP baseline emissions and emission
reductions.

Tables 4-11 and 4-12 present the RACT-impacted natural gas-driven
pneumatic pump baseline emissions and emission reductions. Tables 4-13
and 4-14 present the RACT-impacted natural gas-driven pneumatic pump
costs. Table 4-11. RACT-Impacted Natural Gas-Driven Pneumatic Pump
Baseline Emissions

Emission Source	Baseline Emissions Per Natural Gas-Driven Pneumatic Pump
(tpy)	RACT-Impacted Natural Gas-Driven Pneumatic Pump Baseline Emissions
(tpy)

Moderate or Higher NA Areas Outside of OTR Areas	OTR Areas	Moderate or
Higher Ozone NA Areas/OTR Areas

	VOC	CH4	HAP	VOC	CH4	HAP	VOC	CH4	HAP	VOC	CH4	HAP

Diaphragm	0.96	3.5	0.04	1,966	7,087	74	2,245	8,091	85	4,211	15,178	159

Piston	0.11	0.38	0.004	225	776	8.1	256	885	9.3	481	1,661	17

Table 4-12. RACT-Impacted Natural Gas-Driven Pneumatic Pump Emission
Reductions

Emission Source	Type of Control

 	Emission Reductions Per Natural Gas-Drven Pneumatic Pump (tpy)
RACT-Impacted Natural Gas-Driven Pneumatic Pump Emission Reductions
(tpy)

	Moderate or Higher NA Areas Outside of OTR Areas	OTR Areas	Moderate or
Higher Ozone NA Areas/OTR Areas

VOC	Methane	HAP	VOC	CH4	HAP	VOC	CH4	HAP	VOC	CH4	HAP

Diaphragm	Existing Combustion Device	0.91	3.3	0.034	1,872	6,733	70	2,137
7,686	80	4,008	14,419	151

Piston	Existing Combustion Device	0.10	0.36	0.0038	205	737	7.7	234	841
8.8	439	1,578	17

Table 4-13. Total Annual Costs and VOC Cost of Control Per Natural
Gas-Driven Pneumatic Pump

Emission Source	Natural Gas Savings Per Source (Mcf)	Total Value of
Natural Gas Savings Per Source ($/yr)	Total Capital Costs Per Source ($)
Total Annual Costs Per Source ($/yr)	VOC Cost of Control ($/ton of VOC
reduced)

	w/o savings	w/ savings	w/o savings	w/ savings

Diaphragm	0	$0	$2,000	$285	$285	$312 	$312

Piston	0	$0	$2,000 	$285 	$285 	$2,840 	$2,840

Table 4-14. RACT-Impacted Natural Gas-Driven Pneumatic Pump Costs

Emission Point	Moderate or Higher NA Areas Outside of OTR Areas	OTR
Areas	Moderate or Higher Ozone NA Areas/OTR Areas

	Capital ($)	Annual w/o savings ($/yr)	Annual w/ savings ($/yr)	Capital
($)	Annual w/o savings ($/yr)	Annual w/ savings ($/yr)	Capital ($)
Annual w/o savings ($/yr)	Annual w/ savings ($/yr)

Diaphragm	$4,096,598 	$583,765 	$583,765 	$4,676,673 	$666,426 	$666,426
	$8,773,271 	$1,250,191 	$1,250,191

Piston	$4,082,385 	$581,740 	$581,740 	$4,660,447 	$664,114 	$664,114
$8,742,833 	$1,245,854 	$1,245,854

4.4	Compressors

4.4.1 	Approach

RACT-impacted reciprocating compressor and wet seal centrifugal
compressor baseline emissions and emission reductions were calculated by
multiplying the number of uncontrolled compressors based on information
reported in the 2012 GHG Inventory by emissions and emission reductions
by compressor. The RACT-impacted reciprocating compressor and wet seal
centrifugal compressor costs were estimated by multiplying the
calculated RACT VOC emission reductions by costs per compressor.

4.4.2 	RACT-Impacted Population of Reciprocating Compressors and Wet
Seal Centrifugal Compressors

Based on information in the 2012 GHG Inventory, there were an estimated
36,066 reciprocating compressors located at gathering and boosting
stations. The average of the percentage of the total number of
RACT-impacted natural gas processing plants based on the 2012 Gas
Processing Survey and the percentage of the total number of
RACT-impacted oil and natural gas wells based on 2012 DI Desktop
location information was used to estimate the number of RACT-impacted
reciprocating compressors located at gathering and boosting stations.

Based on information in the 2012 GHG Inventory, there were an estimated
5,624 reciprocating compressors in the processing segment. The
percentage of the total number of RACT-impacted natural gas processing
plants based on the 2012 Gas Processing Survey was used to estimate the
number of RACT-impacted reciprocating compressors in the processing
segment.

Based on information in the 2012 GHG Inventory, there were an estimated
658 wet seal compressors in the processing segment. The percentage of
the total number of RACT-impacted natural gas processing plants based on
the 2012 Gas Processing Survey was used to estimate the number of
RACT-impacted reciprocating compressors in the processing segment.

Table 4-15 presents the estimated population of RACT-impacted
reciprocating compressors and wet seal compressors.

Table 4-15.  RACT-Impacted Population of Reciprocating Compressors and
Wet Seal Compressors

Emission Source	Number of RACT-Impacted Sources

Moderate or Higher Ozone NA Areas Outside of OTR Areas	OTR Areas
Moderate or Higher Ozone NA Areas/OTR Areas

Reciprocating Compressors - Gathering/Boosting Stations	2,305	1,570
3,874

Reciprocating Compressors - Processing Plants	371	93	464

Centrifugal Compressors - Wet Seals Processing Plants	43	11	54

4.4.3	RACT-Impacted Reciprocating Compressor and Wet Seal Centrifugal
Compressor Baseline Emissions, Emission Reductions and Costs

	RACT-impacted compressor baseline emissions were estimated by
multiplying the population of compressors and the VOC, methane and HAP
emissions per compressor. Using the emission reductions and costs
developed for the CTG, we estimated emission reductions and costs by
multiplying the number of compressors by the emission reductions and
costs per compressor. For reciprocating compressors, we used the
emission reductions and costs associated with replacing reciprocating
compressor rod packing after 26,000 hours of operation or 36 months
since the most recent rod packing replacement. For wet seal compressors,
we used the emission reductions and costs associated with routing
emissions to an existing combustion device. Using methane to HAP ratios
developed for the oil and natural gas industry as presented in the 2011
Gas Composition memorandum, we estimated natural gas-driven pneumatic
pump HAP baseline emissions and emission reductions.

Tables 4-16 and 4-17 present the RACT-impacted reciprocating compressor
and wet seal compressor baseline emissions and emission reductions.
Tables 4-18 and 4-19 present the RACT-impacted reciprocating compressor
and wet seal compressor costs. Table 4-16. RACT-Impacted Reciprocating
Compressor and Wet Seal Compressor Baseline Emissions

Emission Source	Baseline Emissions Per Compressor (tpy)	RACT-Impacted
Compressor Baseline Emissions (tpy)

Moderate or Higher NA Areas Outside of OTR Areas	OTR Areas	Moderate or
Higher Ozone NA Areas/OTR Areas

	VOC	CH4	HAP	VOC	CH4	HAP	VOC	CH4	HAP	VOC	CH4	HAP

Reciprocating Compressor – Gathering and Boosting Station	3.4	12	0.13
7,892	28,390	297	5,375	19,377	203	13,267	47,726	500

Reciprocating Compressor – Processing	6.1	22	0.23	2,270	8,176	86	568
2,042	21	2,838	10,209	107

Wet Seal Compressor – Processing	19	211	2.2	830	9,144	96	207	2,286	24
1,037	11,430	120

Table 4-17. RACT-Impacted Reciprocating Compressor and Wet Seal
Compressor Emission Reductions

Emission Source	Type of Control

 	Emission Reductions Per Compressor (tpy)	RACT-Impacted Compressor
Emission Reductions (tpy)

	Moderate or Higher NA Areas Outside of OTR Areas	OTR Areas	Moderate or
Higher Ozone NA Areas/OTR Areas

VOC	Methane	HAP	VOC	CH4	HAP	VOC	CH4	HAP	VOC	CH4	HAP

Reciprocating Compressor – Gathering and Boosting Station	Replace
Packing After Three Years	1.9	6.8	0.07	4,385	15,774	165	2,986	10,744	113
7,371	26,518	278

Reciprocating Compressor – Processing	Replace Packing After Three
Years	4.9	18	0.18	1,814	6,525	68	453	1,631	17	2,267	8,156	85

Wet Seal Compressor – Processing	95 Percent Control; Existing
Combustion Device	18	200	2.1	788	8,706	91	197	2,177	23	985	10,883	114

Table 4-18. Total Annual Costs and VOC Cost of Control Per Compressor

Emission Source	Natural Gas Savings Per Source (Mcf)	Total Value of
Natural Gas Savings Per Source ($/yr)	Total Capital Costs Per Source ($)
Total Annual Costs Per Source ($/yr)	VOC Cost of Control ($/ton of VOC
reduced)

	w/o savings	w/ savings	w/o savings	w/ savings

Reciprocating Compressor – Gathering and Boosting Station	397	$1,587
$5,650 	$2,153	$566 	$1,132 	$298

Reciprocating Compressor – Processing	1,019	$4,074 	$4,280 	$1,631
($2,443)	$334 	($500)

Wet Seal Compressor – Processing	0	$0 	$23,252 	$3,311 	$3,311 	$182
$182

Table 4-19. RACT-Impacted Reciprocating Compressor and Centrifugal
Compressor Costs

Emission Source	Moderate or Higher NA Areas Outside of OTR Areas	OTR
Areas	Moderate or Higher Ozone NA Areas/OTR Areas

	Capital ($)	Annual w/o savings ($/yr)	Annual w/ savings ($/yr)	Capital
($)	Annual w/o savings ($/yr)	Annual w/ savings ($/yr)	Capital ($)
Annual w/o savings ($/yr)	Annual w/ savings ($/yr)

Reciprocating Compressor – Gathering and Boosting Station	$13,020,363
$4,961,431 	$1,305,079 	$8,868,297 	$3,379,279 	$888,902 	$21,888,661
$8,340,711 	$2,193,981

Reciprocating Compressor – Processing	$1,588,826 	$605,462 	($906,997)
$397,207 	$151,365 	($226,749)	$1,986,033 	$756,827 	($1,133,746)

Wet Seal Compressor – Processing	$1,009,889 	$143,804 	$143,804
$252,472 	$35,951 	$35,951 	$1,262,361 	$179,756 	$179,756

4.5.	Equipment Leaks at Natural Gas Processing Plants

4.5.1 	Approach

RACT-impacted equipment leaks at natural gas processing plants baseline
emissions and emission reductions were calculated by multiplying the
number of natural gas processing plants and the baseline emissions and
emission reductions per plant. The RACT-impacted equipment leaks at
natural gas processing plants costs were estimated by multiplying the
emission reductions by costs per natural gas processing plant.

4.5.2 	RACT-Impacted Population of Natural Gas Processing Plants

The number of RACT-impacted natural gas processing plants was obtained
from information in the 2012 Gas Processing Survey. There were 40
natural gas processing plants located in moderate or higher ozone NA
areas and 10 natural gas processing plants in OTR areas in 2012. Table
4-20 presents the estimated RACT-impacted population of natural gas
processing plants.

Table 4-20.  RACT-Impacted Population of Natural Gas Processing Plants

Emission Source	Number of RACT-Impacted Sources

Moderate or Higher NA Areas Outside of OTR Areas	OTR Areas	Moderate or
Higher Ozone NA Areas/OTR Areas

Natural Gas Processing Plants	40	10	50

4.5.3	RACT-Impacted Equipment Leaks at Natural Gas Processing Plants
Baseline Emissions, Emission Reductions and Costs

	RACT-impacted equipment leaks at natural gas processing plants baseline
VOC, methane and HAP emissions were estimated by multiplying the
population of natural gas processing plants and the methane and VOC
emissions per plant. The baseline assumes that existing natural gas
processing plants currently implement an LDAR program equivalent to 40
CFR part 60 subpart VV. Using the emission reductions and costs
developed for the CTG, we estimated emission reductions and costs by
multiplying the number of natural gas processing plants by the emission
reductions and costs associated with the implementation of an LDAR
program equivalent to 40 CFR part 60 subpart VVa (subpart VVa). Using
methane to HAP ratios developed for the oil and natural gas industry as
presented in the 2011 Gas Composition memorandum, we estimated HAP
baseline emissions per natural gas processing plant.

Tables 4-21 and 4-22 present the RACT-impacted equipment leaks at
natural gas processing plants baseline emissions and emission
reductions. Tables 4-23 and 4-24 present the RACT-impacted equipment
leaks at natural gas processing plants costs.

Table 4-21. RACT-Impacted Natural Gas Processing Plant Equipment Leaks
Baseline Emissions

Emission Source	Baseline Emissions Per Natural Gas Processing Plant
(tpy)	RACT-Impacted Natural Gas Processing Plant Baseline Emissions
(tpy)

Moderate or Higher NA Areas Outside of OTR Areas	OTR Areas	Moderate or
Higher Ozone NA Areas/OTR Areas

	VOC	CH4	HAP	VOC	CH4	HAP	VOC	CH4	HAP	VOC	CH4	HAP

Natural Gas Processing Plants - Equipment Leaks	35	126	1.3	1,397	5,027
53	349	1,257	13	1,747	6,284	66

Table 4-22. RACT-Impacted Natural Gas Processing Plant Equipment Leaks
Emission Reductions

Emission Source	Type of Control

 	Emission Reductions Per Natural Gas Processing Plant (tpy)
RACT-Impacted Natural Gas Processing Plant Emission Reductions (tpy)

	Moderate or Higher NA Areas Outside of OTR Areas	OTR Areas	Moderate or
Higher Ozone NA Areas/OTR Areas

VOC	Methane	HAP	VOC	CH4	HAP	VOC	CH4	HAP	VOC	CH4	HAP

Natural Gas Processing Plants - Equipment Leaks	 Subpart VVa	4.6	16	0.17
182	656	7	46	164	2	228	820	9

Table 4-23. Total Annual Costs and VOC Cost of Control Per Natural Gas
Processing Plant

Emission Source	Natural Gas Savings Per Source (Mcf)	Total Value of
Natural Gas Savings Per Source ($/yr)	Total Capital Costs Per Source ($)
Total Annual Costs Per Source ($/yr)	VOC Cost of Control ($/ton of VOC
reduced)

	w/o savings	w/ savings	w/o savings	w/ savings

Natural Gas Processing Plants - Equipment Leaks	950	$3,800 	$8,499
$12,959 	$9,159 	$2,844 	$2,010

Table 4-24. RACT-Impacted Natural Gas Processing Plant Equipment Leaks
Costs

Emission Point	Moderate or Higher NA Areas Outside of OTR Areas	OTR
Areas	Moderate or Higher Ozone NA Areas/OTR Areas

	Capital ($)	Annual w/o savings ($/yr)	Annual w/ savings ($/yr)	Capital
($)	Annual w/o savings ($/yr)	Annual w/ savings ($/yr)	Capital ($)
Annual w/o savings ($/yr)	Annual w/ savings ($/yr)

Natural Gas Processing Plants - Equipment Leaks	$339,960 	$518,366
$366,379 	$84,990 	$129,591 	$91,595 	$424,950 	$647,957 	$457,974

4.6	Fugitive Emissions at Well Sites and Compressor Stations

4.6.1	Approach

RACT-impacted fugitive emissions at well sites that produce, on average,
greater than 15 barrel equivalents per day per well, and gathering and
boosting stations baseline emissions and emission reductions were
calculated by multiplying the number of well sites and gathering and
boosting stations by the baseline emissions and emission reductions per
site/station. The RACT-impacted well site and gathering and boosting
station costs were estimated by multiplying the calculated RACT VOC
emission reductions by costs per well site/gathering and boosting
station.

4.6.2 	RACT-Impacted Population of Wells Sites and Gathering and
Boosting Stations

The DI Desktop database was used to obtain information on the number of
oil and natural gas wells in 2012 in the U.S that produce, on average,
greater than 15 barrel equivalents per day. The number of natural gas
wells in RACT impacted areas was estimated to be 15,541. The number of
oil wells in RACT-impacted areas was estimated to be 13,381. Using
information developed for the 2015 NSPS TSD and CTG, we estimated the
number of well sites that would be subject to RACT by dividing the
number of wells by two (assuming a national average of two wells per
well site).

Based on information in the 2015 NSPS TSD, we estimated that there would
be 8,015 gathering and boosting stations nationally. The average of the
percentage of the total RACT-impacted number of natural gas processing
plants based on the 2012 Gas Processing Survey and the percentage of the
total RACT-impacted number of oil and natural gas wells based on 2012 DI
Desktop location information was used to estimate the number of
RACT-impacted gathering and boosting stations.

Table 4-25 presents the estimated population of RACT-impacted well sites
and gathering and boosting stations.

Table 4-25.  RACT-Impacted Population of Oil and Natural Gas Well Sites
and Gathering and Boosting Stations

Emission Source	Number of RACT-Impacted Sources

Moderate or Higher NA Areas Outside of OTR Areas	OTR Areas	Moderate or
Higher Ozone NA Areas/OTR Areas

Natural Gas Well Sites	5,588	2,183	7,771

Oil Well Sites	6,552	139	6,691

Gathering and Boosting Stations	512	349	861

4.6.3	RACT-Impacted Oil and Natural Gas Well Site and Gathering and
Boosting Station

Fugitive Emissions, Fugitive Emission Reductions and Costs

	RACT-impacted oil and natural gas well site and gathering and boosting
station baseline fugitive emissions were estimated by multiplying the
population of oil and gas well sites and gathering and boosting stations
and VOC baseline emissions per site/station. Using the emission
reductions and costs developed for the 2015 NSPS TSD and CTG, we
estimated emission reductions and costs by multiplying the number of oil
and gas well sites and gathering and boosting stations by the emission
reductions and costs per well site/station. Using VOC to methane and VOC
to HAP ratios developed for the oil and natural gas industry as
presented in the 2011 Gas Composition Memorandum, we estimated methane
and HAP baseline emissions and emission reductions.

Tables 4-26 and 4-27 present the RACT-impacted oil and natural gas well
site and gathering and boosting station baseline fugitive emissions and
fugitive emission reductions. Tables 4-28 and 4-29 present the
RACT-impacted oil and gas well site and gathering and boosting station
costs.

Table 4-26. RACT-Impacted Oil and Natural Gas Well Site and Gathering
and Boosting Station Baseline Fugitive Emissions

Emission Source	Baseline Emissions Per Natural Gas Processing Plant
(tpy)	RACT-Impacted Oil and Gas Well Site and Gathering and Boosting
Station Baseline Fugitive Emissions (tpy)

Moderate or Higher NA Areas Outside of OTR Areas	OTR Areas	Moderate or
Higher Ozone NA Areas/OTR Areas

	VOC	CH4	HAP	VOC	CH4	HAP	VOC	CH4	HAP	VOC	CH4	HAP

Natural Gas Well Sites	1.3	4.5	0.05	7,051	25,365	266	2,754	9,907	104
9,805	35,272	369

Oil Well Sites	0.30	1.1	0.01	1,981	7,125	75	42	151	2	2,203	7,276	76

Gathering and Boosting Stations	9.8	35	0.37	5,003	17,999	188	3,408
12,259	128	8,411	30,258	317

Table 4-27. RACT-Impacted Oil and Natural Gas Well Site and Gathering
and Boosting Station Fugitive Emission Reductions

Emission Source	Type of Control

 	Emission Reductions Per Natural Gas Processing Plant (tpy)
RACT-Impacted Oil and Gas Well Site and Gathering and Boosting Station
Fugitive Emission Reductions (tpy)

	Moderate or Higher NA Areas Outside of OTR Areas	OTR Areas	Moderate or
Higher Ozone NA Areas/OTR Areas

VOC	CH4	HAP	VOC	CH4	HAP	VOC	CH4	HAP	VOC	CH4	HAP

Natural Gas Well Sites	Semiannual OGI	0.76	2.7	0.03	4,231	15,219	159
1,652	5,944	62	5,883	21,163	222

Oil Well Sites	Semiannual OGI	0.18	0.65	0.01	1,188	4,275	45	25	90	1
1,214	4,366	46

Gathering and Boosting Stations	Semiannual OGI	5.9	21	0.22	3,002	10,799
113	2,045	7,356	77	5,047	18,155	190

Table 4-28. Total Annual Costs and VOC Cost of Control Per Well
Site/Station

Emission Source	Natural Gas Savings Per Source (Mcf)	Total Value of
Natural Gas Savings Per Source ($/yr)	Total Capital Costs Per Source ($)
Total Annual Costs Per Source ($/yr)	VOC Cost of Control ($/ton of VOC
reduced)

	w/o savings	w/ savings	w/o savings	w/ savings

Natural Gas Well Sites	158	$631 	$801 	$2,230 	$1,599 	$2,945 	$2,111

Oil Well Sites	38	$151 	$801 	$2,230 	$2,079 	$12,294 	$11,460

Gathering and Boosting Stations	1,222	$4,888 	$10,993 	$15,881 	$10,993
$2,710 	$1,876

Table 4-29. RACT-Impacted Oil and Natural Gas Well Site and Gathering
and Boosting Station Fugitive Emission Costs

Emission Point	Moderate or Higher NA Areas Outside of OTR Areas	OTR
Areas	Moderate or Higher Ozone NA Areas/OTR Areas

	Capital ($)	Annual w/o savings ($/yr)	Annual w/ savings ($/yr)	Capital
($)	Annual w/o savings ($/yr)	Annual w/ savings ($/yr)	Capital ($)
Annual w/o savings ($/yr)	Annual w/ savings ($/yr)

Natural Gas Well Sites	$4,475,582 	$12,460,517 	$8,932,579 	$1,748,024
$4,866,693 	$3,488,789 	$6,223,605 	$17,327,210 	$12,421,368

Oil Well Sites	$5,247,675 	$14,610,112 	$13,619,076 	$110,928 	$308,837
$287,888 	$5,358,604 	$14,918,949 	$13,906,964

Gathering and Boosting Stations	$5,630,384 	$8,133,758 	$5,630,384
$3,834,910 	$5,539,982 	$3,834,910 	$9,465,294 	$13,673,740 	$9,465,294

5	SUMMARY OF THE VOC RACT EMISSION REDUCTIONS AND COSTS

	Table 5-1 presents a summary of the VOC RACT emission reductions and
costs for storage vessels, natural gas-driven pneumatic controllers,
natural gas-driven pneumatic pumps, reciprocating compressors, wet seal
centrifugal compressors, natural gas processing plant equipment leaks,
and fugitive emissions at well sites and gathering and boosting
stations.

Table 5-1. Summary of the Oil and Natural Gas Industry VOC RACT
Emission Reductions and Costs

ATTACHMENT 1

Moderate or Higher Ozone NA Areas

Moderate or Higher Ozone NA Areas

State	County Name	NA Area Name

CA	Amador County	Amador and Calaveras Cos. (Central Mountain Cos.)

CA	Calaveras County	Amador and Calaveras Cos. (Central Mountain Cos.)

CA	El Dorado County	Sacramento Metro

CA	Fresno County	San Joaquin Valley

CA	Imperial County	Imperial County Area

CA	Kern County	Kern County (Eastern Kern)

CA	Kings County	San Joaquin Valley

CA	Los Angeles County	Los Angeles and San Bernardino Counties (Western
Mojave Desert)

CA	Madera County	San Joaquin Valley

CA	Mariposa County	Mariposa and Tuolumne Cos. (Southern Mountain
Counties)

CA	Merced County	San Joaquin Valley

CA	Nevada County	Nevada County (Western part)

CA	Orange County	Los Angeles-South Coast Air Basin

CA	Placer County	Sacramento Metro

CA	Riverside County	Los Angeles-South Coast Air Basin

CA	Sacramento County	Sacramento Metro

CA	San Bernardino County	Los Angeles and San Bernardino Counties
(Western Mojave Desert)

CA	San Joaquin County	San Joaquin Valley

CA	Solano County	Sacramento Metro

CA	Stanislaus County	San Joaquin Valley

CA	Sutter County	Sacramento Metro

CA	Tulare County	San Joaquin Valley

CA	Tuolumne County	Mariposa and Tuolumne Cos. (Southern Mountain
Counties)

CA	Ventura County	Ventura County

CA	Yolo County	Sacramento Metro

CT	Fairfield County	New York-N. New Jersey-Long Island Area

CT	Hartford County	Greater Connecticut Area

CT	Litchfield County	Greater Connecticut Area

CT	Middlesex County	New York-N. New Jersey-Long Island Area

CT	New Haven County	New York-N. New Jersey-Long Island Area

CT	New London County	Greater Connecticut Area

CT	Tolland County	Greater Connecticut Area

CT	Windham County	Greater Connecticut Area

DE	Kent County	Philadelphia-Wilmington-Atlantic City Area

DE	New Castle County	Philadelphia-Wilmington-Atlantic City Area

DE	Sussex County	Philadelphia-Wilmington-Atlantic City Area

DC	District of Columbia	Washington Area

MD	Anne Arundel County	Baltimore

MD	Baltimore County	Baltimore

MD	Calvert County	Washington Area

MD	Carroll County	Baltimore

MD	Cecil County	Philadelphia-Wilmington-Atlantic City Area

MD	Charles County	Washington Area

MD	Frederick County	Washington Area

MD	Harford County	Baltimore

MD	Howard County	Baltimore

MD	Montgomery County	Washington Area

MD	Prince George's County	Washington Area

MD	Baltimore city	Baltimore

MA	Barnstable County	Boston-Lawrence-Worcester (E. Mass) Area

MA	Berkshire County	Springfield (W. Mass) Area

MA	Bristol County	Boston-Lawrence-Worcester (E. Mass) Area

MA	Dukes County	Boston-Lawrence-Worcester (E. Mass) Area

MA	Essex County	Boston-Lawrence-Worcester (E. Mass) Area

MA	Franklin County	Springfield (W. Mass) Area

MA	Hampden County	Springfield (W. Mass) Area

MA	Hampshire County	Springfield (W. Mass) Area

MA	Middlesex County	Boston-Lawrence-Worcester (E. Mass) Area

MA	Nantucket County	Boston-Lawrence-Worcester (E. Mass) Area

MA	Norfolk County	Boston-Lawrence-Worcester (E. Mass) Area

MA	Plymouth County	Boston-Lawrence-Worcester (E. Mass) Area

MA	Suffolk County	Boston-Lawrence-Worcester (E. Mass) Area

MA	Worcester County	Boston-Lawrence-Worcester (E. Mass) Area

NJ	Atlantic County	Philadelphia-Wilmington-Atlantic City Area

NJ	Bergen County	New York-N. New Jersey-Long Island Area

NJ	Burlington County	Philadelphia-Wilmington-Atlantic City Area

NJ	Camden County	Philadelphia-Wilmington-Atlantic City Area

NJ	Cape May County	Philadelphia-Wilmington-Atlantic City Area

NJ	Cumberland County	Philadelphia-Wilmington-Atlantic City Area

NJ	Essex County	New York-N. New Jersey-Long Island Area

NJ	Gloucester County	Philadelphia-Wilmington-Atlantic City Area

NJ	Hudson County	New York-N. New Jersey-Long Island Area

NJ	Hunterdon County	New York-N. New Jersey-Long Island Area

NJ	Mercer County	Philadelphia-Wilmington-Atlantic City Area

NJ	Middlesex County	New York-N. New Jersey-Long Island Area

NJ	Monmouth County	New York-N. New Jersey-Long Island Area

NJ	Morris County	New York-N. New Jersey-Long Island Area

NJ	Ocean County	Philadelphia-Wilmington-Atlantic City Area

NJ	Passaic County	New York-N. New Jersey-Long Island Area

NJ	Salem County	Philadelphia-Wilmington-Atlantic City Area

NJ	Somerset County	New York-N. New Jersey-Long Island Area

NJ	Sussex County	New York-N. New Jersey-Long Island Area

NJ	Union County	New York-N. New Jersey-Long Island Area

NJ	Warren County	New York-N. New Jersey-Long Island Area

NY	Bronx County	New York-N. New Jersey-Long Island Area

NY	Chautauqua County	Jamestown

NY	Dutchess County	Poughkeepsie Area

NY	Erie County	Buffalo-Niagara Falls

NY	Jefferson County	Jefferson County Area

NY	Kings County	New York-N. New Jersey-Long Island Area

NY	Nassau County	New York-N. New Jersey-Long Island Area

NY	New York County	New York-N. New Jersey-Long Island Area

NY	Niagara County	Buffalo-Niagara Falls

NY	Orange County	Poughkeepsie Area

NY	Putnam County	Poughkeepsie Area

NY	Queens County	New York-N. New Jersey-Long Island Area

NY	Richmond County	New York-N. New Jersey-Long Island Area

NY	Rockland County	New York-N. New Jersey-Long Island Area

NY	Suffolk County	New York-N. New Jersey-Long Island Area

NY	Westchester County	New York-N. New Jersey-Long Island Area

PA	Allegheny County	Pittsburgh-Beaver Valley

PA	Armstrong County	Pittsburgh-Beaver Valley

PA	Beaver County	Pittsburgh-Beaver Valley

PA	Bucks County	Philadelphia-Wilmington-Atlantic City Area

PA	Butler County	Pittsburgh-Beaver Valley

PA	Chester County	Philadelphia-Wilmington-Atlantic City Area

PA	Delaware County	Philadelphia-Wilmington-Atlantic City Area

PA	Fayette County	Pittsburgh-Beaver Valley

PA	Montgomery County	Philadelphia-Wilmington-Atlantic City Area

PA	Philadelphia County	Philadelphia-Wilmington-Atlantic City Area

PA	Washington County	Pittsburgh-Beaver Valley

PA	Westmoreland County	Pittsburgh-Beaver Valley

RI	Bristol County	Providence (all of RI) Area

RI	Kent County	Providence (all of RI) Area

RI	Newport County	Providence (all of RI) Area

RI	Providence County	Providence (all of RI) Area

RI	Washington County	Providence (all of RI) Area

TX	Brazoria County	Houston-Galveston-Brazoria Area

TX	Chambers County	Houston-Galveston-Brazoria Area

TX	Collin County	Dallas-Fort Worth

TX	Dallas County	Dallas-Fort Worth

TX	Denton County	Dallas-Fort Worth

TX	Ellis County	Dallas-Fort Worth

TX	Fort Bend County	Houston-Galveston-Brazoria Area

TX	Harris County	Houston-Galveston-Brazoria Area

TX	Johnson County	Dallas-Fort Worth

TX	Kaufman County	Dallas-Fort Worth

TX	Liberty County	Houston-Galveston-Brazoria Area

TX	Montgomery County	Houston-Galveston-Brazoria Area

TX	Parker County	Dallas-Fort Worth

TX	Rockwall County	Dallas-Fort Worth

TX	Tarrant County	Dallas-Fort Worth

TX	Waller County	Houston-Galveston-Brazoria Area

TX	Wise County	Dallas-Fort Worth

VA	Arlington County	Washington Area

VA	Fairfax County	Washington Area

VA	Loudoun County	Washington Area

VA	Prince William County	Washington Area

VA	Alexandria city	Washington Area

VA	Fairfax city	Washington Area

VA	Falls Church city	Washington Area

VA	Manassas city	Washington Area

VA	Manassas Park city	Washington Area

WI	Sheboygan County	Sheboygan Area

ATTACHMENT 2

ONG CTG – RACT-Impacted Population of Storage Vessels and
RACT-Impacted Storage Vessel Baseline Emissions, Emission Reductions and
Costs

Well Productivity Bracket (bbls/day range)	Representative (bbls/day)
Number of RACT-Impacted Storage Vessels – 2012	Number of Storage
Vessels Not Impacted by RACT

	>0-1	0.385	0	34,577

1-2	1.34	0	8,727

2-4	2.66	0	10,589

4-6	4.45	0	6,174

6-8	6.22	0	4,228

8-10	8.08	0	3,361

10-12	9.83	0	2,592

12-15	12.1	0	2,880

15-20	15.4	0	3,177

20-25	19.9	0	2,017

25-30	24.3	0	1,306

30-40	30.5	1,086	423

40-50	39.2	505	197

50-100	61.6	755	279

100-200	120	104	64

200-400	238	13	21

400-800	456	0	2

800-1600	914	0	0

1600-3200	1,692	0	1

3200-6400	3,353	0	0

6400-12800	6,825	0	0

TOTAL	 	2,462	80,616

Table A2-1.  Number of RACT-Impacted Oil Storage Vessels

Total A2-2.  Number of RACT-Impacted Condensate Storage Vessels

Well Productivity Bracket (bbls/day range)	Representative (bbls/day)	CTG
Covered Vessels 2012	Total Number of Vessels Not Covered by RACT

	>0-1	635	0	80,133

1-2	349	0	257

2-4	648	0	127

4-6	766	0	48

6-8	640	0	10

8-10	525	0	12

10-12	408	0	9

12-15	564	0	7

15-20	758	0	5

20-25	674	0	2

25-30	531	0	0

30-40	927	0	1

40-50	747	0	0

50-100	2,691	0	0

100-200	3,800	0	0

200-400	2,705	0	0

400-800	1,165	0	0

800-1600	348	0	0

1600-3200	69	0	0

3200-6400	37	0	0

6400-12800	5	0 	0

>12800	0	0	0

TOTAL	 	0	80,611

Table A2-3.  RACT-Impacted Oil Storage Vessel Baseline Emissions

	Well Productivity Bracket (bbls/day range)	Representative (bbls/day)
Average Baseline Emissions per Unit (tpy/unit)	Nationwide Baseline
Emissions 2012

VOC	Methane	HAP	VOC	Methane	HAP

>0-1	0.385	0.083	0.017	0.003	0	0	0.000

1-2	1.34	0.287	0.059	0.009	0	0	0.000

2-4	2.66	0.570	0.118	0.018	0	0	0.000

4-6	4.45	0.953	0.197	0.030	0	0	0.000

6-8	6.22	1.33	0.28	0.04	0	0	0.000

8-10	8.08	1.73	0.36	0.05	0	0	0.000

10-12	9.83	2.11	0.44	0.07	0	0	0.000

12-15	12.1	2.59	0.54	0.08	0	0	0.000

15-20	15.4	3.31	0.68	0.10	0	0	0.000

20-25	19.9	4.27	0.88	0.13	0	0	0.000

25-30	24.3	5.22	1.08	0.16	0	0	0.000

30-40	30.5	6.54	1.35	0.21	6,749	1,397	212

40-50	39.2	8.41	1.74	0.26	4,033	835	127

50-100	61.6	13.2	2.7	0.4	9,470	1,960	297

100-200	120	25.6	5.3	0.8	2,524	522	79

200-400	238	51.0	10.6	1.6	611	126	19

400-800	456	97.7	20.2	3.1	0	0	0.000

800-1600	914	196.0	40.6	6.2	0	0	0.000

1600-3200	1,692	362.9	75.1	11.4	0	0	0.000

3200-6400	3,353	719.1	148.8	22.6	0	0	0.000

6400-12800	6,825	1463.7	302.9	45.9	0	0	0.000

TOTAL	 	 	 	 	23,386	4,840	734

Table A2-4.  RACT-Impacted Condensate Storage Vessel Baseline Emissions

	Well Productivity Bracket

(bbls/day range)	Representative

(bbls/day)	Average Baseline Emissions per Unit (tpy/unit)	Nationwide
Baseline Emissions 2012

VOC	Methane	HAP	VOC	Methane	HAP

>0-1	635	0.038	0.008	0.001	0	0	0

1-2	349	0.168	0.037	0.005	0	0	0

2-4	648	0.318	0.070	0.009	0	0	0

4-6	766	0.573	0.126	0.017	0	0	0

6-8	640	0.82	0.18	0.02	0	0	0

8-10	525	1.04	0.23	0.03	0	0	0

10-12	408	1.37	0.30	0.04	0	0	0

12-15	564	1.53	0.34	0.04	0	0	0

15-20	758	2.10	0.46	0.06	0	0	0

20-25	674	3.32	0.73	0.10	0	0	0

25-30	531	3.85	0.85	0.11	0	0	0

30-40	927	5.33	1.17	0.16	0	0	0

40-50	747	7.59	1.67	0.22	0	0	0

50-100	2,691	11.7	2.6	0.3	0	0	0

100-200	3,800	25.4	5.6	0.7	0	0	0

200-400	2,705	49.8	11.0	1.5	0	0	0

400-800	1,165	92.3	20.3	2.7	0	0	0

800-1600	348	142.2	31.3	4.2	0	0	0

1600-3200	69	310.7	68.5	9.1	0	0	0

3200-6400	37	489.9	107.9	14.4	0	0	0

6400-12800	5	1864.4	410.8	54.7	0	0	0

>12800	0	0	0	0	0	0	0

Table A2-5.  RACT-Impacted Oil Storage Vessel Emission Reductions

Well Productivity Bracket

(bbls/day range)	Representative (bbls/day)	Average Emission Reductions
Per Unit (tpy) Assuming 95% Reduction	Nationwide Emissions Reductions
2012	Natural Gas Saved Mcf/yr/unit	Total Natural Gas Saved Mcf/yr

VOC	Methane	HAP	VOC	Methane	HAP

>0-1	0.385	0.078	0.016	0.002	0	0	0.000	2.7	0

1-2	1.34	0.272	0.056	0.009	0	0	0.000	9.2	0

2-4	2.66	0.542	0.112	0.017	0	0	0.000	18.3	0

4-6	4.45	0.906	0.187	0.028	0	0	0.000	30.6	0

6-8	6.22	1.27	0.26	0.04	0	0	0.000	42.9	0

8-10	8.08	1.65	0.34	0.05	0	0	0.000	55.7	0

10-12	9.83	2.00	0.41	0.06	0	0	0.000	67.8	0

12-15	12.1	2.46	0.51	0.08	0	0	0.000	83.2	0

15-20	15.4	3.14	0.65	0.10	0	0	0.000	106.3	0

20-25	19.9	4.05	0.84	0.13	0	0	0.000	137.1	0

25-30	24.3	4.96	1.03	0.16	0	0	0.000	167.7	0

30-40	30.5	6.21	1.29	0.20	6755	1398	212	210.1	22847

40-50	39.2	7.99	1.65	0.25	4033	835	127	270.3	13638

50-100	61.6	12.5	2.6	0.4	9470	1960	297	424.2	32028

100-200	120	24.4	5.0	0.8	2524	522	79	823.9	8536

200-400	238	48.5	10.0	1.5	611	126	19	1638.9	2065

400-800	456	92.8	19.2	2.9	0	0	0.000	3139.0	0

800-1600	914	186.2	38.5	5.8	0	0	0.000	6297.8	0

1600-3200	1,692	344.8	71.4	10.8	0	0	0.000	11660.3	0

3200-6400	3,353	683.2	141.4	21.4	0	0	0.000	23105.8	0

6400-12800	6,825	1390.5	287.8	43.6	0	0	0.000	47028.1	0

TOTAL	 	 	 	 	23,392	4,842	734	 	79,114

Table A2-6.  RACT-Impacted Condensate Storage Vessel Emission Reductions

Well Productivity Bracket (bbls/day range)	Representative (bbls/day)
Average Emission Reductions Per Unit (tpy) assuming 95% reduction
Nationwide Emissions Reductions 2012

	Natural Gas Saved Mcf/yr/unit	Total Natural Gas Saved Mcf/yr

	VOC	Methane	HAP	VOC	Methane	HAP

>0-1	635	0.036	0.008	0.001	0	0	0	1.151	0

1-2	349	0.159	0.035	0.005	0	0	0	5.051	0

2-4	648	0.302	0.067	0.009	0	0	0	9.558	0

4-6	766	0.545	0.120	0.016	0	0	0	17.252	0

6-8	640	0.78	0.17	0.02	0	0	0	24.818	0

8-10	525	0.99	0.22	0.03	0	0	0	31.423	0

10-12	408	1.30	0.29	0.04	0	0	0	41.27	0

12-15	564	1.46	0.32	0.04	0	0	0	46.16	0

15-20	758	1.99	0.44	0.06	0	0	0	63.11	0

20-25	674	3.15	0.70	0.09	0	0	0	99.91	0

25-30	531	3.65	0.81	0.11	0	0	0	115.68	0

30-40	927	5.07	1.12	0.15	0	0	0	160.4	0

40-50	747	7.21	1.59	0.21	0	0	0	228.4	0

50-100	2,691	11.1	2.5	0.3	0	0	0	352.6	0

100-200	3,800	24.1	5.3	0.7	0	0	0	763	0

200-400	2,705	47.3	10.4	1.4	0	0	0	1498	0

400-800	1,165	87.7	19.3	2.6	0	0	0	2777	0

800-1600	348	135.1	29.8	4.0	0	0	0	4277	0

1600-3200	69	295.1	65.0	8.7	0	0	0	9346	0

3200-6400	37	465.4	102.5	13.6	0	0	0	14737	0

6400-12800	5	1771.2	390.3	51.9	0	0	0	56086	0

>12800	0	0.0	0.0	0.0	0	0	0	0.000	0

Table A2-7.  RACT-Impacted Oil Storage Vessel VRU and Combustor Costs

Well Productivity Bracket

(bbls/day range)	Route Emissions to a VRU	Route Emissions to a Combustor

	Total Capital Cost Per Unit ($)	Total Annual Cost Per Unit ($/yr)	VOC
Cost of Control              ($/ton)	Total Capital Cost Per Unit ($)
Total Annual Cost Per Unit ($/yr)	VOC Cost of Control
($/ton)

w/o savings	w/ savings	w/o savings	w/ savings

w/o savings	w/ savings	w/o savings	w/ savings

>0-1	$171,538	$28,230	$28,219	$359,638	$359,503	$100,986	$22,228	$22,228
$283,175	$283,175

1-2	$171,538	$28,230	$28,193	$103,714	$103,579	$100,986	$22,228	$22,228
$81,663	$81,663

2-4	$171,538	$28,230	$28,157	$52,104	$51,969	$100,986	$22,228	$22,228
$41,026	$41,026

4-6	$171,538	$28,230	$28,107	$31,170	$31,035	$100,986	$22,228	$22,228
$24,543	$24,543

6-8	$171,538	$28,230	$28,058	$22,261	$22,126	$100,986	$22,228	$22,228
$17,528	$17,528

8-10	$171,538	$28,230	$28,007	$17,144	$17,009	$100,986	$22,228	$22,228
$13,499	$13,499

10-12	$171,538	$28,230	$27,959	$14,092	$13,957	$100,986	$22,228	$22,228
$11,096	$11,096

12-15	$171,538	$28,230	$27,897	$11,478	$11,342	$100,986	$22,228	$22,228
$9,037	$9,037

15-20	$171,538	$28,230	$27,805	$8,986	$8,851	$100,986	$22,228	$22,228
$7,075	$7,075

20-25	$171,538	$28,230	$27,682	$6,963	$6,828	$100,986	$22,228	$22,228
$5,483	$5,483

25-30	$171,538	$28,230	$27,559	$5,692	$5,557	$100,986	$22,228	$22,228
$4,482	$4,482

30-40	$171,538	$28,230	$27,390	$4,544	$4,409	$100,986	$22,228	$22,228
$3,578	$3,578

40-50	$171,538	$28,230	$27,149	$3,532	$3,397	$100,986	$22,228	$22,228
$2,781	$2,781

50-100	$171,538	$28,230	$26,533	$2,251	$2,115	$100,986	$22,228	$22,228
$1,772	$1,772

100-200	$171,538	$28,230	$24,934	$1,159	$1,024	$100,986	$22,228	$22,228
$912	$912

200-400	$171,538	$28,230	$21,675	$583	$447	$100,986	$22,228	$22,228	$459
$459

400-800	$171,538	$28,230	$15,674	$304	$169	$100,986	$22,228	$22,228	$239
$239

800-1600	$171,538	$28,230	$3,039	$152	$16	$100,986	$22,228	$22,228	$119
$119

1600-3200	$171,538	$28,230	-$18,411	$82	-$53	$100,986	$22,228	$22,228
$64	$64

3200-6400	$171,538	$28,230	-$64,193	$41	-$94	$100,986	$22,228	$22,228
$33	$33

6400-12800	$171,538	$28,230	-$159,882	$20	-$115	$100,986	$22,228	$22,228
$16	$16

Table A2-8.  RACT-Impacted Condensate Storage Vessel VRU and Combustor
Costs

Well Productivity Bracket

(bbls/day range)	Routing Emissions to a VRU	Routing to a Combustor

	Total Capital Cost Per Unit ($)	Total Annual Cost Per Unit ($/yr)	VOC
Cost Effectiveness               ($/ton)	Total Capital Cost Per Unit ($)
Total Annual Cost Per Unit ($/yr)	VOC Cost Effectiveness
($/ton)

w/o savings	w/ savings	w/o savings	w/ savings

w/o savings	w/ savings	w/o savings	w/ savings

>0-1	$171,538	$28,230	$28,225	$776,897	$776,770	$100,986	$22,228	$22,228
$611,720	$611,720

1-2	$171,538	$28,230	$28,210	$176,996	$176,870	$100,986	$22,228	$22,228
$139,365	$139,365

2-4	$171,538	$28,230	$28,192	$93,529	$93,402	$100,986	$22,228	$22,228
$73,643	$73,643

4-6	$171,538	$28,230	$28,161	$51,817	$51,690	$100,986	$22,228	$22,228
$40,800	$40,800

6-8	$171,538	$28,230	$28,131	$36,020	$35,893	$100,986	$22,228	$22,228
$28,362	$28,362

8-10	$171,538	$28,230	$28,104	$28,449	$28,322	$100,986	$22,228	$22,228
$22,400	$22,400

10-12	$171,538	$28,230	$28,065	$21,663	$21,537	$100,986	$22,228	$22,228
$17,057	$17,057

12-15	$171,538	$28,230	$28,045	$19,367	$19,240	$100,986	$22,228	$22,228
$15,249	$15,249

15-20	$171,538	$28,230	$27,978	$14,166	$14,039	$100,986	$22,228	$22,228
$11,154	$11,154

20-25	$171,538	$28,230	$27,830	$8,948	$8,821	$100,986	$22,228	$22,228
$7,045	$7,045

25-30	$171,538	$28,230	$27,767	$7,727	$7,601	$100,986	$22,228	$22,228
$6,085	$6,085

30-40	$171,538	$28,230	$27,588	$5,573	$5,446	$100,986	$22,228	$22,228
$4,388	$4,388

40-50	$171,538	$28,230	$27,316	$3,914	$3,787	$100,986	$22,228	$22,228
$3,082	$3,082

50-100	$171,538	$28,230	$26,820	$2,535	$2,409	$100,986	$22,228	$22,228
$1,996	$1,996

100-200	$171,538	$28,230	$25,177	$1,171	$1,045	$100,986	$22,228	$22,228
$922	$922

200-400	$171,538	$28,230	$22,239	$597	$470	$100,986	$22,228	$22,228	$470
$470

400-800	$171,538	$28,230	$17,120	$322	$195	$100,986	$22,228	$22,228	$253
$253

800-1600	$171,538	$28,230	$11,122	$209	$82	$100,986	$22,228	$22,228	$165
$165

1600-3200	$171,538	$28,230	-$9,152	$96	-$31	$100,986	$22,228	$22,228	$75
$75

3200-6400	$171,538	$28,230	-$30,717	$61	-$66	$100,986	$22,228	$22,228
$48	$48

6400-12800	$171,538	$28,230	-$196,116	$16	-$111	$100,986	$22,228	$22,228
$13	$13

>12800	$171,538	$28,230	$28,230	$0	$0	$100,986	$22,228	$22,228	$0	$0

Table A2-9.  RACT-Impacted Oil Storage Vessel Nationwide Costs

Well Productivity Bracket

 (bbls/day range)	Representative

(bbls/day)	Total Nationwide Costs

Capital ($)	Annual w/o savings

($/yr)	Annual w/ savings ($/yr)

>0-1	0.385	$0	$0	$0

1-2	1.34	$0	$0	$0

2-4	2.66	$0	$0	$0

4-6	4.45	$0	$0	$0

6-8	6.22	$0	$0	$0

8-10	8.08	$0	$0	$0

10-12	9.83	$0	$0	$0

12-15	12.1	$0	$0	$0

15-20	15.4	$0	$0	$0

20-25	19.9	$0	$0	$0

25-30	24.3	$0	$0	$0

30-40	30.5	$117,473,197	$24,821,102	$24,729,715

40-50	39.2	$54,517,590	$11,519,110	$11,464,556

50-100	61.6	$81,571,106	$17,235,291	$17,107,178

100-200	120	$11,193,068	$2,365,002	$2,330,858

200-400	238	$1,361,319	$287,635	$279,375

400-800	456	$0	$0	$0

800-1600	914	$0	$0	$0

1600-3200	1,692	$0	$0	$0

3200-6400	3,353	$0	$0	$0

6400-12800	6,825	$0	$0	$0

TOTAL	 	$266,116,280	$56,228,139	$55,911,683

Table A2-10.  RACT-Impacted Condensate Storage Vessel Nationwide Costs

Well Productivity Bracket

(bbls/day range)	Representative

(bbls/day)	Total Nationwide Costs

Capital ($)	Annual w/o savings ($/yr)	Annual w/ savings ($/yr)

>0-1	635	$0	$0	$0

1-2	349	$0	$0	$0

2-4	648	$0	$0	$0

4-6	766	$0	$0	$0

6-8	640	$0	$0	$0

8-10	525	$0	$0	$0

10-12	408	$0	$0	$0

12-15	564	$0	$0	$0

15-20	758	$0	$0	$0

20-25	674	$0	$0	$0

25-30	531	$0	$0	$0

30-40	927	$0	$0	$0

40-50	747	$0	$0	$0

50-100	2,691	$0	$0	$0

100-200	3,800	$0	$0	$0

200-400	2,705	$0	$0	$0

400-800	1,165	$0	$0	$0

800-1600	348	$0	$0	$0

1600-3200	69	$0	$0	$0

3200-6400	37	$0	$0	$0

6400-12800	5	$0	$0	$0

>12800	0	$0	$0	$0

TOTAL	 	$0	$0	 $0

ATTACHMENT 3

Oil and Natural Gas CTG – Storage Vessels Covered By State Regulation

		This attachment presents an analysis of state regulations that
estimates the number of existing storage vessels that are subject to a
RACT-equivalent or greater level of control. The number of storage
vessels determined to be subject to a RACT-equivalent or greater level
of control was subtracted from the number of storage vessels that were
located in RACT-impacted areas that we assumed emit greater than or
equal to six tpy. There may be more storage vessels regulated or
permitted at a greater or equivalent level of control to the recommended
RACT that have not been accounted for in this analysis (e.g., based on
case-by-case permit limits).

 CAA Section 172(c)(1) and Section 182(b)(2)(A).

 CAA Section 184(b)(1)(B).

 U.S. Environmental Protection Agency. Proposed Control Techniques
Guidelines for the Oil and Natural Gas Industry. August 2015

 DI Desktop. 2012. Drilling Info. Inc.

 U.S. Environmental Protection Agency (2014). Inventory of U.S.
Greenhouse Gas Emissions and Sinks: 1990-2012. U.S. Environmental
Protection Agency, Washington D.C. EPA 430-R-15-004 Available online at:
  HYPERLINK
"http://www.epa.gov/climatechange/ghgemissions/usinventoryreport.html"
http://www.epa.gov/climatechange/ghgemissions/usinventoryreport.html .

 Note that the EPA’s GHGRP plans to release additional activity data
in the fall of 2015 from its Petroleum and Natural Gas Systems source
category. These data covers oil and gas operations reporting to the
GHGRP in 2011, 2012, 2013 and 2014. These new activity data will be
reviewed prior to finalization of the CTG and incorporated into this
analysis if appropriate.

 See reference 3.

 U.S. Environmental Protection Agency. Oil and Natural Gas Sector:
Standards of Performance for Crude Oil and Natural Gas Production,
Transmission, and Distribution - Background Technical Support Document
for the Proposed Amendments to the New Source Performance Standards.
June 2015.

 Memorandum to Bruce Moore, U.S. EPA from Heather Brown, EC/R.
Composition of Natural Gas for use in the Oil and Natural Gas Sector
Rulemaking. July 2011. Docket ID EPA-HQ-OAR-2010-0505-0084.

 DrillingInfo is a private organization specializing in oil and gas data
and statistical analysis. The DrillingInfo database is focused on
historical oil and gas production data and drilling permit data.

 Memorandum to Mark de Figueiredo, U.S EPA from Casey MacQueen and
Jessica Gray, P.E., ERG. 2013 GHGRP Subpart W and NSPS/NESHAP
DrillingInfo Processing Methodology. August 27, 2014.

 The EPA is aware that there is often more than one storage vessel per
well site. However, for emissions calculation purposes, we assumed that
all storage vessels are likely manifolded together or could reasonable
be manifolded together such that there is a single emission point for
all storage vessels on the well site. Thus, we count one storage vessel
per well site for emission calculation purposes because only one
emission point would need to be controlled.

 Heather Brown, EC/R Incorporated to Moore, B., EPA/OAQPS/SPPD/FIG.
Revised Analysis to Determine the Number of Storage Vessels Projected to
be Subject to New Source Performance Standards for the Oil and Natural
Gas Sector. April 8, 2013.

 Ibid.

 U.S. Environmental Protection Agency. Greenhouse Gas Reporting Program
– Petroleum and Natural Gas Systems (Subpart W) Analysis: Onshore
Production Storage Tanks (Reporting Year: 2013 Data).

***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During
Review***

  PAGE   \* MERGEFORMAT  3

***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During
Review***

***EO12866_Oil and Gas CTG 2060-ZA22 Emission Reduction and Cost of
Control_20150810***

***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During
Review***

***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During
Review***

***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During
Review***

***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During
Review***

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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During
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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During
Review***

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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During
Review***

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[Federal Register Volume 87, Number 89 (Monday, May 9, 2022)]
[Rules and Regulations]
[Pages 27507-27508]
[FR Doc No: 2022-09676]

-----------------------------------------------------------------------

DEPARTMENT OF TRANSPORTATION

Federal Aviation Administration

14 CFR Part 71

[Docket No. FAA-2022-0163; Airspace Docket No. 22-ACE-7]
RIN 2120-AA66

Amendment of Class E Airspace; Hugoton, KS

AGENCY: Federal Aviation Administration (FAA), DOT.

ACTION: Final rule.

-----------------------------------------------------------------------

SUMMARY: This action amends the Class E airspace at Hugoton, KS. This
action as the result of an airspace review conducted as part of the
decommissioning of the Hugoton non-directional beacon (NDB). The
geographic coordinates of the airport are also being updated to
coincide with the FAA's aeronautical database.

DATES: Effective 0901 UTC, July 14, 2022. The Director of the Federal
Register approves this incorporation by reference action under 1 CFR
51, subject to the annual revision of FAA Order JO 7400.11 and
publication of conforming amendments.

ADDRESSES: FAA Order JO 7400.11F, Airspace Designations and Reporting
Points, and subsequent amendments can be viewed online at https://www.faa.gov/air_traffic/publications/. For further information, you can
contact the Airspace Policy Group, Federal Aviation Administration, 800
Independence Avenue SW, Washington, DC 20591; telephone: (202) 267-
8783.

FOR FURTHER INFORMATION CONTACT: Jeffrey Claypool, Federal Aviation
Administration, Operations Support Group, Central Service Center, 10101
Hillwood Parkway, Fort Worth, TX 76177; telephone<PHONE_NUMBER>.

SUPPLEMENTARY INFORMATION:

Authority for This Rulemaking

    The FAA's authority to issue rules regarding aviation safety is
found in Title 49 of the United States Code. Subtitle I, Section 106
describes the authority of the FAA Administrator. Subtitle VII,
Aviation Programs, describes in more detail the scope of the agency's
authority. This rulemaking is promulgated under the authority described
in Subtitle VII, Part A, Subpart I, Section 40103. Under that section,
the FAA is charged with prescribing regulations to assign the use of
airspace necessary to ensure the safety of aircraft and the efficient
use of airspace. This regulation is within the scope of that authority
as it amends the Class E airspace extending upward from 700 feet above
the surface at Hugoton Municipal Airport, Hugoton, KS, to support
instrument flight rule operations at this airport.

History

    The FAA published a notice of proposed rulemaking in the Federal
Register (87 FR 12001; March 3, 2022) for Docket No. FAA-2022-0163 to
amend the Class E airspace at Hugoton, KS. Interested parties were
invited to participate in this rulemaking effort by submitting written
comments on the proposal to the FAA. No comments were received.
    Class E airspace designations are published in paragraph 6005 of
FAA Order JO 7400.11F, dated August 10, 2021, and effective September
15, 2021,

which is incorporated by reference in 14 CFR 71.1. The Class E airspace
designations listed in this document will be published subsequently in
FAA Order JO 7400.11.

Availability and Summary of Documents for Incorporation by Reference

    This document amends FAA Order JO 7400.11F, Airspace Designations
and Reporting Points, dated August 10, 2021, and effective September
15, 2021. FAA Order JO 7400.11F is publicly available as listed in the
ADDRESSES section of this document. FAA Order JO 7400.11F lists Class
A, B, C, D, and E airspace areas, air traffic service routes, and
reporting points.

The Rule

    This amendment to 14 CFR part 71 amends the Class E airspace
extending upward from 700 feet above the surface within a 6.5-mile
(reduced from a 7.2-mile) radius of Hugoton Municipal Airport, Hugoton,
KS; removes the Hugoton NDB and associated extension from the airspace
legal description; and updates the geographic coordinates of the
airport to coincide with the FAA's aeronautical database.
    This action is necessary due to an airspace review conducted as
part of the decommissioning of the Hugoton NDB which provided
navigation information for the instrument procedures this airport.
    FAA Order JO 7400.11, Airspace Designations and Reporting Points,
is published yearly and effective on September 15.

Regulatory Notices and Analyses

    The FAA has determined that this regulation only involves an
established body of technical regulations for which frequent and
routine amendments are necessary to keep them operationally current, is
non-controversial and unlikely to result in adverse or negative
comments. It, therefore: (1) Is not a ``significant regulatory action''
under Executive Order 12866; (2) is not a ``significant rule'' under
DOT Regulatory Policies and Procedures (44 FR 11034; February 26,
1979); and (3) does not warrant preparation of a regulatory evaluation
as the anticipated impact is so minimal. Since this is a routine matter
that only affects air traffic procedures and air navigation, it is
certified that this rule, when promulgated, does not have a significant
economic impact on a substantial number of small entities under the
criteria of the Regulatory Flexibility Act.

Environmental Review

    The FAA has determined that this action qualifies for categorical
exclusion under the National Environmental Policy Act in accordance
with FAA Order 1050.1F, ``Environmental Impacts: Policies and
Procedures,'' paragraph 5-6.5.a. This airspace action is not expected
to cause any potentially significant environmental impacts, and no
extraordinary circumstances exist that warrant preparation of an
environmental assessment.

Lists of Subjects in 14 CFR Part 71

    Airspace, Incorporation by reference, Navigation (air).

Adoption of the Amendment

    In consideration of the foregoing, the Federal Aviation
Administration amends 14 CFR part 71 as follows:

PART 71--DESIGNATION OF CLASS A, B, C, D, AND E AIRSPACE AREAS; AIR
TRAFFIC SERVICE ROUTES; AND REPORTING POINTS

0
1. The authority citation for part 71 continues to read as follows:

    Authority:  49 U.S.C. 106(f), 106(g); 40103, 40113, 40120; E.O.
10854, 24 FR 9565, 3 CFR, 1959-1963 Comp., p. 389.

Sec.  71.1  [Amended]

0
2. The incorporation by reference in 14 CFR 71.1 of FAA Order JO
7400.11F, Airspace Designations and Reporting Points, dated August 10,
2021, and effective September 15, 2021, is amended as follows:

Paragraph 6005 Class E Airspace Areas Extending Upward From 700
Feet or More Above the Surface of the Earth.

* * * * *

ACE KS E5 Hugoton, KS [Amended]

Hugoton Municipal Airport, KS
    (Lat. 37[deg]09'48'' N, long. 101[deg]22'14'' W)

    That airspace extending upward from 700 feet above the surface
within a 6.5-mile radius of Hugoton Municipal Airport.

    Issued in Fort Worth, Texas, on May 2, 2022.
Martin A. Skinner,
Acting Manager, Operations Support Group, ATO Central Service Center.
[FR Doc. 2022-09676 Filed 5-6-22; 8:45 am]
BILLING CODE 4910-13-P