[Federal Register: April 9, 2009 (Volume 74, Number 67)]
[Notices]
[Page 16202-16203]
[DOCID:fr09ap09-50]

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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

Combined Notice of Filings

April 01, 2009.
    Take notice that the Commission has received the following Natural
Gas Pipeline Rate and Refund Report filings:

    Docket Numbers: RP96-272-089.
    Applicants: Northern Natural Gas Company.
    Description: Northern Natural Gas Company submit Fifth Revised
Sheet No 66B.01a et al. to FERC Gas Tariff, Fifth Revised Volume No 1,
to be effective 4/1/09.
    Filed Date: 03/31/2009.
    Accession Number: 20090331-0067.
    Comment Date: 5 p.m. Eastern Time on Monday, April 13, 2009.

    Docket Numbers: RP96-320-104.
    Applicants: Gulf South Pipeline Company, LP.
    Description: Gulf South Pipeline Company submits a capacity release
agreement containing Negotiated Rate provisions executed by Gulf South
and Texla Energy Management, Inc.
    Filed Date: 03/30/2009.
    Accession Number: 20090331-0057.
    Comment Date: 5 p.m. Eastern Time on Monday, April 13, 2009.

    Docket Numbers: RP99-176-194.
    Applicants: Natural Gas Pipeline Co of America LLC.
    Description: Natural Gas Pipeline Company of America LLC submits
First Revised Sheet No 35B et al. to FERC Gas Tariff, Seventh Revised
Volume No 1, to be effective 4/1/09.
    Filed Date: 03/31/2009.
    Accession Number: 20090331-0065.
    Comment Date: 5 p.m. Eastern Time on Monday, April 13, 2009.

    Docket Numbers: RP99-176-195.
    Applicants: Natural Gas Pipeline Co of America LLC.
    Description: Natural Gas Pipeline Company of America LLC submit
Second Revised Sheet No 35C et al. to FERC Gas Tariff, Seventh Revised
Volume No 1, to be effective 4/1/09.
    Filed Date: 03/31/2009.
    Accession Number: 20090331-0075.
    Comment Date: 5 p.m. Eastern Time on Monday, April 13, 2009.

    Docket Numbers: RP00-426-043.
    Applicants: Texas Gas Transmission, LLC.
    Description: Texas Gas Transmission, LLC submits Original Sheet 91
et al. to its FERC Gas Tariff, Third Revised Volume, and a Negotiated
Rate Agreements related to the Henderson Dogtown Lateral Project.
    Filed Date: 03/30/2009.
    Accession Number: 20090331-0055.
    Comment Date: 5 p.m. Eastern Time on Monday, April 13, 2009.

    Docket Numbers: RP07-139-006.
    Applicants: Algonquin Gas Transmission, LLC.
    Description: Algonquin Gas Transmission, LLC submits Third Revised
Sheet 513 to its FERC Gas Tariff, Fifth Revised Volume 1, to be
effective 3/1/09.
    Filed Date: 03/30/2009.
    Accession Number: 20090331-0054.
    Comment Date: 5 p.m. Eastern Time on Monday, April 13, 2009.

    Docket Numbers: RP08-479-002.
    Applicants: Saltville Gas Storage Company LLC.
    Description: Saltville Gas Storage Company, LLC submits Substitute
Fifth Revised Sheet 107 et al. to its FERC Gas Tariff, Original Volume
1, to be effective 3/1/09.
    Filed Date: 03/30/2009.
    Accession Number: 20090331-0052.
    Comment Date: 5 p.m. Eastern Time on Monday, April 13, 2009.

    Docket Numbers: RP08-487-002.
    Applicants: East Tennessee Natural Gas, LLC.
    Description: East Tennessee Natural Gas, LLC submits Substitute
Second Revised Sheet 313 et al. to its FERC Gas Tariff, Third Revised
Volume 1, to be effective 3/1/09.
    Filed Date: 03/30/2009.
    Accession Number: 20090331-0053.
    Comment Date: 5 p.m. Eastern Time on Monday, April 13, 2009.

    Docket Numbers: RP09-61-005.
    Applicants: Gulf Crossing Pipeline Company LLC.
    Description: Gulf Crossing Pipeline Company LLC submits replacement
amendment to negotiated rate letter agreement re the Gulf Crossing
Project.
    Filed Date: 03/30/2009.
    Accession Number: 20090331-0059.
    Comment Date: 5 p.m. Eastern Time on Monday, April 13, 2009.

    Docket Numbers: RP09-304-001.
    Applicants: Texas Gas Transmission, LLC.
    Description: Texas Gas Transmission, LLC submits Substitute First
Revised Sheet No 2805 et al. to FERC Gas Tariff, Third Revised Volume
No 1, to be effective 3/1/09.
    Filed Date: 03/30/2009.
    Accession Number: 20090331-0058.
    Comment Date: 5 p.m. Eastern Time on Monday, April 20, 2009.

    Docket Numbers: RP09-474-000.
    Applicants: Natural Gas Pipeline Company of America.
    Description: Natural Gas Pipeline Company of America LLC. submits
Transportation Rate Schedule FTS Agreement dated 3/9/04 with Tenaska
Marketing Ventures, to be effective 4/1/09.
    Filed Date: 03/31/2009.
    Accession Number: 20090331-0066.
    Comment Date: 5 p.m. Eastern Time on Monday, April 13, 2009.

    Docket Numbers: RP09-475-000.
    Applicants: Vector Pipeline, LP.
    Description: Vector Pipeline LP submits their Annual Fuel Use
Report.
    Filed Date: 03/31/2009.
    Accession Number: 20090331-0068.
    Comment Date: 5 p.m. Eastern Time on Monday, April 13, 2009.

    Docket Numbers: RP09-477-000.
    Applicants: Panhandle Eastern Pipe Line Company, LP.
    Description: Panhandle Eastern Pipe Line Company, LP submits work
papers in support of its Annual Flow Through of Cash Out Revenues in
Excess of Costs and Scheduling Charges Assessed Against Affiliates.
    Filed Date: 03/31/2009.
    Accession Number: 20090331-0069.
    Comment Date: 5 p.m. Eastern Time on Monday, April 13, 2009.

    Docket Numbers: RP09-478-000.
    Applicants: Panhandle Eastern Pipe Line Company, LP.
    Description: Panhandle Eastern Pipe Line Company, LP submits Annual
Report of Flow Through of Penalty Revenues.

    Filed Date: 03/31/2009.
    Accession Number: 20090331-0070.
    Comment Date: 5 p.m. Eastern Time on Monday, April 13, 2009.

    Docket Numbers: RP09-479-000.
    Applicants: Columbia Gulf Transmission Company.
    Description: Columbia Gulf Transmission Company submits First
Revised Sheet No. 333D et al. to FERC Gas Tariff, Second Revised Volume
No. 1, to be effective 5/1/09.
    Filed Date: 03/31/2009.
    Accession Number: 20090331-0071.
    Comment Date: 5 p.m. Eastern Time on Monday, April 13, 2009.

    Docket Numbers: RP09-480-000.
    Applicants: Horizon Pipeline Company, LLC.
    Description: Horizon Pipeline Company, LLC submits Second Revised
Sheet No. 7C et al. to FERC Gas Tariff, Original Volume No. 1, to be
effective 4/1/09.
    Filed Date: 03/31/2009.
    Accession Number: 20090331-0072.
    Comment Date: 5 p.m. Eastern Time on Monday, April 13, 2009.

    Docket Numbers: RP09-481-000.
    Applicants: CenterPoint Energy Gas Transmission Company.
    Description: CenterPoint Energy Gas Transmission Company submits
annual revenue crediting filing pursuant to its FERC Gas Tariff, Sixth
Revised Volume No. 1 etc.
    Filed Date: 03/31/2009.
    Accession Number: 20090331-0073.
    Comment Date: 5 p.m. Eastern Time on Monday, April 13, 2009.

    Docket Numbers: RP09-482-000.
    Applicants: Horizon Pipeline Company, LLC.
    Description: Horizon Pipeline Company, LLC submits its Penalty
Revenue Crediting Report for the period 1/1/08 to 12/31/08.
    Filed Date: 03/31/2009.
    Accession Number: 20090331-0074.
    Comment Date: 5 p.m. Eastern Time on Monday, April 13, 2009.

    Docket Numbers: RP09-483-000.
    Applicants: Quest Pipelines (KPC).
    Description: Quest Pipelines submits Third Revised Sheet No. 21 et
al. to FERC Gas Tariff, Second Revised Volume No. 1, to be effective 4/
1/09.
    Filed Date: 03/31/2009.
    Accession Number: 20090331-0076.
    Comment Date: 5 p.m. Eastern Time on Monday, April 13, 2009.

    Docket Numbers: RP09-484-000.
    Applicants: Kern River Gas Transmission Company.
    Description: Report of Kern River Gas Transmission Company on
Annual Fuel and Lost and Unaccounted-For Gas Factor Report for calendar
year 2008.
    Filed Date: 03/30/2009.
    Accession Number: 20090330-5178.
    Comment Date: 5 p.m. Eastern Time on Monday, April 13, 2009.

    Docket Numbers: RP09-485-000.
    Applicants: Rockies Express Pipeline LLC.
    Description: Annual Incidental Purchases and Sales Report of
Rockies Express Pipeline LLC.
    Filed Date: 04/01/2009.
    Accession Number: 20090401-5030.
    Comment Date: 5 p.m. Eastern Time on Monday, April 13, 2009.

    Any person desiring to intervene or to protest in any of the above
proceedings must file in accordance with Rules 211 and 214 of the
Commission's Rules of Practice and Procedure (18 CFR 385.211 and
385.214) on or before 5 p.m. Eastern time on the specified comment
date. It is not necessary to separately intervene again in a subdocket
related to a compliance filing if you have previously intervened in the
same docket. Protests will be considered by the Commission in
determining the appropriate action to be taken, but will not serve to
make protestants parties to the proceeding. Anyone filing a motion to
intervene or protest must serve a copy of that document on the
Applicant. In reference to filings initiating a new proceeding,
interventions or protests submitted on or before the comment deadline
need not be served on persons other than the Applicant.
    The Commission encourages electronic submission of protests and
interventions in lieu of paper, using the FERC Online links at http://
www.ferc.gov. To facilitate electronic service, persons with Internet
access who will eFile a document and/or be listed as a contact for an
intervenor must create and validate an eRegistration account using the
eRegistration link. Select the eFiling link to log on and submit the
intervention or protests.
    Persons unable to file electronically should submit an original and
14 copies of the intervention or protest to the Federal Energy
Regulatory Commission, 888 First St., NE., Washington, DC 20426.
    The filings in the above proceedings are accessible in the
Commission's eLibrary system by clicking on the appropriate link in the
above list. They are also available for review in the Commission's
Public Reference Room in Washington, DC. There is an eSubscription link
on the Web site that enables subscribers to receive e-mail notification
when a document is added to a subscribed docket(s). For assistance with
any FERC Online service, please e-mail<EMAIL_ADDRESS>or
call<PHONE_NUMBER> (toll free). For TTY, call<PHONE_NUMBER>.

Nathaniel J. Davis, Sr.,
Deputy Secretary.
[FR Doc. E9-8035 Filed 4-8-09; 8:45 am]

BILLING CODE 6717-01-P


[Federal Register Volume 87, Number 33 (Thursday, February 17, 2022)]
[Notices]
[Page 9066]
[FR Doc No: 2022-03476]

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DEPARTMENT OF HEALTH AND HUMAN SERVICES

Food and Drug Administration

[Docket No. FDA-2021-N-0008]

Device Good Manufacturing Practice Advisory Committee; Notice of
Meeting

AGENCY: Food and Drug Administration, HHS.

ACTION: Notice.

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SUMMARY: The Food and Drug Administration (FDA or Agency) announces a
forthcoming public advisory committee meeting of the Device Good
Manufacturing Practice Advisory Committee. The committee reviews
regulations proposed for promulgation regarding good manufacturing
practices governing the methods used in, and the facilities and
controls used for, the manufacture, packing, storage, and installation
of devices, and makes recommendations to the Commissioner of Food and
Drugs regarding the feasibility and reasonableness of those proposed
regulations. The meeting will be open to the public.

DATES: The meeting will take place virtually on March 2, 2022, from 9
a.m. to 6 p.m. Eastern Time.

ADDRESSES: Please note that due to the impact of this COVID-19
pandemic, all meeting participants will be joining this advisory
committee meeting via an online teleconferencing platform. Answers to
commonly asked questions including information regarding special
accommodations due to a disability may be accessed at: https://www.fda.gov/advisory-committees/about-advisory-committees/common-questions-and-answers-about-fda-advisory-committee-meetings.

FOR FURTHER INFORMATION CONTACT: Jarrod Collier, Center for Devices and
Radiological Health, Food and Drug Administration, 10903 New Hampshire
Ave., Bldg. 66, Rm. 5214, Silver Spring, MD 20993-0002,
[email protected],<PHONE_NUMBER>, or FDA Advisory Committee
Information Line, 1-800-741-8138<PHONE_NUMBER> in the Washington, DC
area). A notice in the Federal Register about last-minute modifications
that impact a previously announced advisory committee meeting cannot
always be published quickly enough to provide timely notice. Therefore,
you should always check the Agency's website at https://www.fda.gov/AdvisoryCommittees/default.htm and scroll down to the appropriate
advisory committee meeting link, or call the advisory committee
information line to learn about possible modifications before the
meeting. The meeting will be webcast and will be available at the
following links: YouTube (primary): https://youtu.be/SPrNfVb2Yv8 and
TEAMS (captions): https://teams.microsoft.com/. Please log on 20
minutes before the webcast to test your signal. You may have to refresh
your browser before logging on.

SUPPLEMENTARY INFORMATION:
    Agenda: The meeting presentations will be heard, viewed, captioned,
and recorded through an online teleconferencing platform. As required
by section 520(f)(1)(B) of the Federal Food, Drug, and Cosmetic Act
(FD&C Act) (21 U.S.C. 360j(f)(1)(B)), on March 2, 2022, the committee
will discuss and make recommendations on the current good manufacturing
practice requirements for medical devices under 21 CFR part 820, the
Quality System Regulation, to align more closely with an international
consensus standard for medical devices used by other regulatory
authorities.
    FDA intends to make background material available to the public no
later than 2 business days before the meeting. If FDA is unable to post
the background material on its website prior to the meeting, the
background material will be made publicly available on FDA's website at
the time of the advisory committee meeting, and the background material
will be posted on FDA's website after the meeting. Background material
and the link to the online teleconference meeting room will be
available at https://www.fda.gov/advisory-committees/medical-devices/device-good-manufacturing-practice-advisory-committee. Select the link
for the 2022 Meeting Materials. The meeting will include slide
presentations with audio components to allow the presentation of
materials in a manner that most closely resembles an in-person advisory
committee meeting.
    Procedure: Interested persons may present data, information, or
views, orally or in writing, on issues pending before the committee.
Written submissions may be made to the contact person on or before
February 24, 2022. Oral presentations from the public will be scheduled
on March 2, 2022, between approximately 1:30 p.m. to 2:30 p.m. Eastern
Time. Those individuals interested in making formal oral presentations
should notify the contact person (see FOR FURTHER INFORMATION CONTACT).
The notification should include a brief statement of the general nature
of the evidence or arguments they wish to present, the names and
addresses of proposed participants, and an indication of the
approximate time requested to make their presentation on or before
February 21, 2022. Time allotted for each presentation may be limited.
If the number of registrants requesting to speak is greater than can be
reasonably accommodated during the scheduled open public hearing
session, FDA may conduct a lottery to determine the speakers for the
scheduled open public hearing session. The contact person will notify
interested persons regarding their request to speak by February 22,
2022.
    For press inquiries, please contact the Office of Media Affairs at
[email protected] or<PHONE_NUMBER>.
    FDA welcomes the attendance of the public at its advisory committee
meetings and will make every effort to accommodate persons with
disabilities. If you require accommodations due to a disability, please
contact AnnMarie Williams at [email protected] or 301-796-
5966 at least 7 days in advance of the meeting.
    FDA is committed to the orderly conduct of its advisory committee
meetings. Please visit our website at https://www.fda.gov/advisory-committees/about-advisory-committees/public-conduct-during-fda-advisory-committee-meetings for procedures on public conduct during
advisory committee meetings.
    Notice of this meeting is given under the Federal Advisory
Committee Act (5 U.S.C. app. 2).

    Dated: February 10, 2022.
Lauren K. Roth,
Associate Commissioner for Policy.
[FR Doc. 2022-03476 Filed 2-16-22; 8:45 am]
BILLING CODE 4164-01-P


                 United States Environmental Protection Agency
                              Statement of Basis
                             Air Pollution Control
                     Part 71 Title V Permit to Operate for
                           Tap 5 Compressor Station
                        Permit No. V-UO-000018-2022.00

The purpose of this document is to set forth the legal and factual basis for permit conditions, including references to applicable provisions of the Clean Air Act (CAA or Act) and implementing regulations of the CAA title V operating permit program at 40 C.F.R. part 71 (Part 71). This document also gives the derivation of conditions as required by 40 C.F.R. § 71.11(b).

EPA Authority to Issue Part 71 Permits

All major stationary sources of air pollution and certain other sources are required to apply for title V operating permits that include emission limitations and other conditions as necessary to assure compliance with applicable requirements of the CAA, including the requirements of the applicable State Implementation Plan (SIP). CAA §§ 502(a) and 504(a). The title V operating permit program does not generally impose new substantive air quality control requirements (referred to as "applicable requirements"), but does require permits to contain monitoring, recordkeeping, reporting and other requirements to assure source' compliance with applicable requirements. 57 FR 32250, 32251 (July 21, 1992). One purpose of the title V operating permit program is to "enable the source, States, EPA, and the public to understand better the requirements to which the source is subject, and whether the source is meeting those requirements." 57 FR 32251. Thus, the title V operating permit program is a vehicle for ensuring that air quality control requirements are appropriately applied to the source emission units and for assuring compliance with such requirements.

Part 71 programs for Indian country - The Administrator will implement and enforce an operating permits program in Indian country, as defined in § 71.2, when an operating permits program which meets the requirements of Part 70 of this chapter has not been explicitly granted full or interim approval by the Administrator for Indian country.

Facility Information and Description

Applicant and Stationary Source Information

Table 1: Applicant Information
Owner/Operator
Facility (SIC Code: 1311)
Utah Gas Corporation
133 E 1000N
Roosevelt, Utah  84066
Tap 5 Compressor Station: Latitude 39.9750760N, Longitude<PHONE_NUMBER>W

Table 2: Stationary Source Information
Responsible Official(s)
Facility Contact
(1) Russ Knight, President
(2) April Mestas, Regulatory Manager

Utah Gas Corporation
760 Horizon Drive, Suite 400
Grand Junction, Colorado  81506
(970) 260-1864
Ken Secrest
Regulatory Coordinator
Utah Gas Corporation
133 E 1000N
Roosevelt, Utah  84066
(970) 675-4440 Ext. 7947

Facility Description

Natural gas produced from area wells and from the Little Canyon Unit Compressor Station is sent to Tap 5 through natural gas gathering flowlines. A low-pressure natural gas stream from area wells enters a low-pressure inlet separator in order to reduce water and condensable liquids content in the gas stream prior to entry into two compressor engines and a triethylene glycol (TEG) natural gas dehydration system. A high-pressure gas stream from the Little Canyon Unit Compressor Station enters a high-pressure separator in order to reduce water and condensable liquids content in the gas stream prior to entry into a compressor engine. The liquids produced from on-site separators are sent to 300-barrel (bbl) and 400-bbl slop tanks for storage prior to being hauled off site. The TEG natural gas dehydration system utilized for the low-pressure natural gas stream consists of one 40 million standard cubic feet per day (MMscfd) capacity natural gas TEG dehydration process still vent, with a 0.50 million British thermal units per hour (MMBTU/hr) natural gas-fired process heater and a TEG regenerator. The TEG natural gas dehydration system emissions are controlled by a thermal oxidizer.

Following dehydration, the dry natural gas stream leaves the station via a metered sales pipeline. The station has on-site electrical power supplied by a Capstone natural gas-fired microturbine-driven generator. In addition, the pneumatic control devices are operated by plant air supplied by the on-site electric-driven air compressor.
In addition, a wellsite (RBU 11-2F) is located on the same surface pad as Tap 5. The RBU 11-2F wellsite does not produce significant natural gas and is considered an oil production well only. The emission units at the RBU 11-2F wellsite include a 19 hp pumping unit engine, two 300-bbl storage tanks, condensate truck loading operations, one 0.25 MMBtu/hr natural gas-fired tank heater, one 0.5 MMBtu/hr natural gas-fired tank heater and fugitive emissions.
Title V Major Source Status
The Part 71 Permit Program applies to major sources, as defined in 40 C.F.R. § 71.2. The title V major source thresholds, as determined by pollutant-specific PTE, for criteria pollutants are 100 tons per year (tpy) and for HAP are 10 tons/year for a single HAP or 25 tons/year for any combination of HAP.
According to the information provided by UGC in their Part 71 renewal application, uncontrolled emissions from dehydration unit, T5D-1, exceed the major source thresholds for HAP. Therefore, the source is a title V source, per 40 C.F.R. § 71.3(a)(3). This facility is subject to federally enforceable requirements under MACT HH that limit the PTE of T5D-1.
Source Determination
At 40 C.F.R. § 71.2, a major source is generally defined as any stationary source (or any group of stationary sources that are located on one or more contiguous or adjacent properties and are under common control of the same person (or persons under common control)), belonging to a single major industrial grouping and that are a major source as described in the definition. On June 3, 2016, the EPA published a final rule clarifying when oil and natural gas sector equipment and activities must be deemed a single source when determining whether major source permitting programs (prevention of significant deterioration (PSD) and New Source Review preconstruction permit programs, and the Part 71 permit program) apply (81 FR 35622). By clarifying the term "adjacent," the rule specifies that equipment and activities in the oil and natural gas sector that are under common control will be considered part of the same source if they are located on the same surface site or on individual surface sites that share equipment and are within (1/4) mile of each other.
According to information provided by UGC in their Part 71 renewal application, the RBU 11-2F Wellsite and Tap 5 are located on the same surface site. Therefore, the EPA has determined that RBU 11-2F Wellsite is contiguous with Tap 5 and thus part of the same stationary source.
Area Classification - Local Air Quality and Attainment Status
Tap 5 is located within the exterior boundaries of Uintah and Ouray (U&O) Indian Reservation and within an area designated as Marginal nonattainment for the 2015 ozone National Ambient Air Quality Standard (NAAQS) of 70 parts per billion. The exact location for this source is Latitude 39.9750760N, Longitude<PHONE_NUMBER>W, in Uintah County, Utah.
Tribal Reservation Contact
Mike Natchees
Air Quality Program Director
Ute Indian Tribe
P.O. Box 70
Fort Duchesne, Utah  84026
(435) 725-4974 or<EMAIL_ADDRESS>
Identification of Emission Generating Activities
The Part 71 Permit Program allows the Permittee to separately list in the permit application units or activities that qualify as "insignificant" based on potential emissions below 2 tons tpy for all regulated pollutants that are not listed as HAP under section 112(b) and below 1,000 lbs/year or the de minimis level established under section 112(g), whichever is lower, for HAP. However, the application may not omit information needed to determine the applicability of or to impose, any applicable requirement. Units and activities that qualify as "insignificant" for the purposes of the Part 71 application are in no way exempt from applicable requirements or any requirements of the Part 71 permit. Tables 3 and 4 list emission units and emission generating activities, including any air pollution control devices.

Table 3: Emission Units and Emission Generating Activities

                                   Unit I.D.

                                            Description

                               Control Equipment

                                     T5C-1
                        Caterpillar 3516 TALE; 1,112 hp
 4-Stroke Lean-Burn Reciprocating Internal Combustion Engine Natural Gas-Fired

             Serial No. WPW00339	Installed: 4/21/2021 Mfd: 5/2006

                              Oxidation Catalyst

                                     T5C-2
                        Caterpillar 3516 TALE; 1,340 hp
 4-Stroke Lean-Burn Reciprocating Internal Combustion Engine Natural Gas-Fired

                          Serial No. 4EK03995	Installed: 9/27/2021 Mfd: 3/2004

                               Oxidation Catalyst

                                       T5BC-2
                         Caterpillar 3516 LE; 1,340 hp
 4-Stroke Lean-Burn Reciprocating Internal Combustion Engine Natural Gas-Fired

                         Serial No. WPW01800	Installed: 6/28/2013 Mfd: 11/2/2007

                               Oxidation Catalyst

                                        T5D-1
                        40 MMscfd TEG Dehydration Unit

                     Serial No. 28111	Installed: 5/10/2007

                                Thermal Oxidizer
                                    (T5TO-1)
                                     T5F-1
                              Fugitive Emissions
                                     None
                                     T5F-2
                    Fugitive Emissions (RBU 11-2F Wellsite)
                                     None

                                      T-1
                 300 bbl Oil Storage Tank (RBU 11-2F Wellsite)

                    Serial No. F1433 	Installed: 11/29/2012

                                     None

                                      T-2
                 300 bbl Oil Storage Tank (RBU 11-2F Wellsite)

                     Serial No. 77924 	Installed: Pre-2011

                                     None

                                 RBU 11-2F PU
                    Arrow C-66 Well Site Pump Engine; 19 hp
 4-Stroke Rich-Burn Reciprocating Internal Combustion Engine Natural Gas-Fired

             Serial No. 210121C	Installed: 04/2019 Mfd: 3/17/2009

                                     None

                                   T5-ENGBD

                               Engine Blowdowns

                                     None

                                    T5TO-1

                          Thermal Oxidizer for T5D-1

                                      N/A

Table 4: Insignificant Emission Units[*]
                                                   Description
                      Two 400-bbl Condensate Tanks (Tap 5)
                        Condensate Truck Loading (Tap 5)
                Two Capstone 65 kW Microturbine Gensets (Tap 5)
              0.50 MMBtu/hr TEG Dehydration Unit Reboiler (Tap 5)
                    Two 0.25 MMBtu/hr** Tank Heaters (Tap 5)
            0.25 MMBtu/hr Natural Gas-Fired Separator Heater (Tap 5)
               2.0 MMBtu/hr* Heater for Thermal Oxidizer (Tap 5)
                      Pipeline Pigging Operations (Tap 5)
      0.50 MMBtu/hr  RBU 11-02F Wellsite Tank Heater (RBU 11-2F Wellsite)
      0.25 MMBtu/hr  RBU 11-02F Wellsite Tank Heater (RBU 11-2F Wellsite)
             RBU 11-02F Wellsite Truck Loading (RBU 11-2F Wellsite)
*Insignificant emission units can change at the facility as long as the new or replacement units meet the criteria for insignificance, and UGC supplies information as required under 40 C.F.R. part 71 and this permit. The insignificant emission unit status does not exempt these emission units from the requirements of any standards that may apply under 40 C.F.R. parts 60 or 63.

Permitting, Construction and Compliance History

Tap 5 Compressor Station, owned by UGC, was initially permitted on September 22, 2017, and operates under the Part 71 Operating Permit V-UO-000018-2007.00. On May 3, 2021, the EPA received a minor modification request to add a new compressor engine (Emission Unit T5C-1 in Table 3) at the facility. On November 3, 2021, the EPA received a notification of off-permit change notifying that UGC replaced the existing compressor engine (Emission Unit T5C-2 in Table 3) with a like kind engine on September 27, 2021. The EPA did not issue a modified permit at that time and decided to incorporate the changes at the facility into the current renewal permit. The initially issued permit expired on September 22, 2022. A timely application to renew the Part 71 permit was received by the EPA on March 2, 2022, and was deemed complete on April 29, 2022.

Emission Inventory

Pursuant to 40 C.F.R. § 52.21, PTE is defined as the maximum capacity of a stationary source to emit a pollutant under its physical and operational design. Any physical or operational limitation on the capacity of the source to emit a pollutant, including air pollution control equipment and restrictions on hours of operation or on the type or amount of material combusted, stored, or processed, shall be treated as part of its design if the limitation, or the effect it would have on emissions, is federally enforceable. Independently enforceable applicable requirements are considered enforceable to the extent that the source is in compliance with the standard. In addition, beneficial reductions in non-targeted pollutants resulting from compliance with an independently enforceable applicable requirement may be counted towards PTE provided the emission reduction of the non-targeted pollutant is enforceable as a practical matter and compliance is being met. See the 1995 guidance memo signed by John Seitz, Director of the Office of Air Quality Planning and Standards titled, "Options for Limiting Potential to Emit of a Stationary Source under Section 112 and Title V of the Clean Air Act."

UGC reported the controlled emission unit-specific PTE in their Part 71 renewal permit application. The controlled emissions in Table 5 are based on the legally and practicably enforceable requirements set forth in this draft permit.

Table 5: Potential-to-Emit With Legally and Practicably Enforceable Controls
                         Regulated Air Pollutants (tpy)

                                   Unit I.D.

                                      NOX

                                      CO

                                      VOC

                                       PM

                                      SO2

                                      CH2O
                                    Total HAP
                                      T5C-1
                                     16.09
                                     27.06
                                     4.76
                                      0.42
                                      0.02
                                      1.56
                                      2.22
                                      T5C-2
                                     19.39
                                     33.10
                                     6.03
                                      0.45
                                      0.03
                                      1.79
                                      2.49
                                     T5BC-2
                                     25.88
                                     30.28
                                     7.50
                                      0.50
                                      0.03
                                      1.81
                                      2.59
                                     T5D-1

                                     0.79

                                      0.49
                                     T5F-1

                                     6.08

                                      0.95
                                     T5F-2

                                     2.89

                                      0.44
                                 T-1 & T-2

                                     2.33

                                      0.11
                                  RBU 11-2F PU
                                     2.18
                                     0.93
                                     0.04
                                      0.01

                                      0.01
                                      0.02
                                       T5-
                                      ENGBD

                                     2.88

                                      0.10
                                     T5TO-1
                                     3.04
                                     2.55
                                     0.05
                                      0.23

                                      IEUs
                                     1.99
                                     4.81
                                     1.98
                                      0.19
                                      0.01
                                      0.31
                                      0.69
                                     TOTAL
                                     68.57
                                     98.73
                                     35.33
                                      1.80
                                      0.09
                                      5.48
                                      10.10

Regulatory Analysis

The discussions in the following sections are based on the information provided by UGC in their Part 71 renewal application, certified to be true and accurate by the Responsible Official of this facility.

PSD, 40 C.F.R. Part 52.21
The Prevention of Significant Deterioration Permit Program at 40 C.F.R. part 52 is a preconstruction review requirement of the CAA that applies to proposed projects that are sufficiently large (in terms of emissions) to be a "major" stationary source or "major" modification of an existing stationary source. Source size is defined in terms of "potential to emit," which is its capability at maximum design capacity to emit a pollutant, except as constrained by existing legally and practically enforceable conditions applicable to the source. A new stationary source or a modification to an existing minor stationary source is major if the proposed project has the PTE of any pollutant regulated under 40 C.F.R. part 52 in amounts equal to or exceeding specified major source thresholds, which are 100 tpy for 28 listed industrial source categories and 250 tpy for all other sources. PSD also applies to modifications at existing major sources that cause a "significant net emissions increase" at that source. Significance levels for each pollutant are defined in the PSD regulations at 40 C.F.R. § 52.21.
According to the information provided by UGC in their Part 71 renewal application, at the time of its construction and subsequent modifications, Tap 5 was not a major source of emissions with respect to the PSD Permit Program as the PTE did not exceed the major source thresholds of criteria pollutants regulated under PSD Permit Program. As such, the source was not subject to the preconstruction permitting requirements of the PSD Permit Program.
NSR, 40 C.F.R. Part 49
40 C.F.R. § 49.166 - Federal Major New Source Review Program for Nonattainment Areas in Indian Country:
The Federal Major NSR Program for Nonattainment Areas in Indian Country (NNSR Permit Program) at 40 C.F.R. part 49 is a preconstruction review requirement of the CAA that applies to proposed projects that are sufficiently large (in terms of emissions) to be a "major" stationary source or "major modification" of an existing stationary source in an area that the EPA has designated nonattainment for a NAAQS (See 40 C.F.R. § 49.167). Similar to the PSD Permit Program, source size is defined in terms of PTE, but a new stationary source or a modification to an existing stationary source is major if the proposed project has the PTE for any pollutant regulated under the 40 C.F.R. part 49 requirements in amounts equal to or exceeding specified major source thresholds defined in 40 C.F.R. part 51, appendix S.
On April 30, 2018, the EPA designated portions of the Indian country lands within the U&O Reservation as marginal nonattainment for the 2015 ozone NAAQS effective on August 3, 2018. Tap 5 is located within that marginal ozone nonattainment area. Appendix S lists the marginal ozone nonattainment major source threshold for VOC or NOX emissions as 100 tpy. As explained previously, Tap 5 was not considered a major source with respect to the PSD Permit Program at the time of construction and it is also not a major source with respect to the NNSR Permit Program, as the PTE of VOC and NOX, precursor pollutants to ozone, are both below 100 tpy with respect to the Marginal ozone nonattainment area within which the Tap 5 facility is located.
40 C.F.R. § 49.151 - Federal Minor New Source Review Program in Indian Country:
The Federal Minor New Source Review (MNSR) Permit Program at 40 C.F.R. part 49, subpart C (§§49.151 through 49.165), is a preconstruction review requirement of the CAA that applies to all new and modified minor sources, synthetic minor sources and minor modifications at major sources, located in Indian country where no EPA-approved program is in place. True minor sources and modifications and minor modifications at existing major sources are proposed projects that have PTE for any pollutant regulated under the MNSR Permit Program that are below the major source thresholds in the PSD Permit Program or the NNSR Permit Program at 40 C.F.R. part 49, subpart C, and above the minor source thresholds in Table 1 of 40 C.F.R.        § 49.153 (thresholds differ depending on the pollutant). The MNSR Permit Program also provides the EPA authority to establish enforceable restrictions for an otherwise major source to establish that source as a synthetic minor source for NSR-regulated pollutants or HAP for the purposes of the PSD, NNSR or title V Permit Programs, or for the purposes of major source requirements of the NESHAP at 40 C.F.R. part 63. Additionally, the MNSR Permit Program established a Federal Implementation Plan (FIP) (§§ 49.101 through 49.105) for true minor sources in the oil and natural gas production and natural gas processing segments that are in Indian country.
Tap 5 is currently a true minor source and was originally constructed and commenced operations before August 30, 2011. As such, Tap 5 was registered as an existing true minor source per 40 C.F.R. § 49.160 (registration number: REG-UO-000018-2013.001). No other pre-construction requirements applied to Tap 5 under the MNSR Permit Program.
NSPS, 40 C.F.R. Part 60
40 C.F.R. Part 60, Subpart A: This subpart applies to the owner or operator of any stationary source which contains an affected facility, the construction or modification of which is commenced after the date of publication of any standard in 40 C.F.R. part 60 (Part 60). The general provisions under subpart A apply to sources that are subject to the specific subparts of Part 60.

As explained below, Emission Unit RBU 11-2F PU is subject to subpart JJJJ of Part 60; therefore, the General Provisions of Part 60 apply.

40 C.F.R. Part 60, Subpart GG: This rule applies to stationary gas turbines, with a heat input at peak load equal to or greater than 10.7 gigajoules per hour (10 MMBtu/hr), that commenced construction, modification or reconstruction after October 3, 1977.

Based on the information provided by UGC in their Part 71 renewal application, the stationary gas turbines located at Tap 5 have a maximum heat input less than 10.7 gigajoules per hour; therefore, this rule does not apply. The maximum heat input for each of the Capstone Microturbine at the facility is 0.68 MMBtu/hr.

40 C.F.R. Part 60, Subpart Kb: This subpart establishes requirements for controlling VOC emissions from storage vessels with a capacity greater than or equal to 75 cubic meters (471.74 bbls) that are used to store volatile organic liquids for which construction, reconstruction or modification commenced after July 23, 1984.

Based on the information provided by UGC in their Part 71 renewal application, the condensate tanks (Two 400 bbl condensate tanks located at Tap 5 and tanks T-1 and T-2 located at RBU 11-2F Wellsite) at this facility are exempt from these requirements, because each tank has a capacity of less than 472 bbls.

40 C.F.R. Part 60, Subpart KKK: This subpart establishes requirements for controlling fugitive VOC emissions from onshore natural gas processing plants. It applies to natural gas processing plants that commenced construction, reconstruction, or modification after January 20, 1984, and on or before August 23, 2011.

Based on the information provided by UGC in their Part 71 renewal application, Tap 5 is not a natural gas processing plant, therefore the facility is not subject to this subpart.

40 C.F.R. Part 60, Subpart LLL: This subpart applies to sweetening units and sulfur recovery units at onshore natural gas processing facilities. As defined in this subpart, sweetening units are process devices that separate hydrogen sulfide (H2S) and carbon dioxide (CO2) from a sour natural gas stream. Sulfur recovery units are defined as process devices that recover sulfur from the acid gas (consisting of H2S and CO2) removed by a sweetening unit.

Based on the information provided by UGC in their Part 71 renewal application, neither sweetening nor sulfur recovery are performed at the facility. Therefore, this facility is not subject to this subpart.

40 C.F.R. Part 60, Subpart JJJJ: This subpart establishes emission standards and compliance requirements for the control of emissions from stationary spark ignition internal combustion engines that commenced construction, modification, or reconstruction after June 12, 2006, and are manufactured on or after specified manufacture trigger dates. The manufacture trigger dates are based on the engine type, fuel used and maximum engine horsepower.

Based on the information provided by UGC in their Part 71 application, the manufacture trigger dates are January 1, 2008, for engines T5C-1, T5C-2 and T5BC-2, and July 1, 2008, for engine RBU 11-2F PU. Engine RBU 11-2F PU was manufactured in 2009; therefore, this subpart applies to this engine only. The other engines operating at the facility (T5C-1, T5C-2 and T5BC-2) were manufactured prior to January 1, 2008, and therefore are not subject to the requirements of this subpart.

40 C.F.R. Part 60, Subpart KKKK: The rule applies to stationary combustion turbines with a heat input at peak load equal to or greater than 10.7 gigajoules (10 MMBtu) per hour.

Based on the information provided by UGC in their Part 71 renewal application, the stationary gas turbines located at Tap 5 have a maximum heat input less than 10.7 gigajoules per hour; therefore, this rule does not apply. The maximum heat input for each of the Capstone Microturbine at the facility is 0.68 MMBtu/hr.

40 C.F.R. Part 60, Subpart OOOO: This subpart establishes emission standards for the control of VOC and SO2 emissions from affected facilities that commence construction, modification, or reconstruction after August 23, 2011, and on or before September 18, 2015. Affected facilities include, but are not limited to well completions, centrifugal compressors, reciprocating compressors, pneumatic controllers, storage vessels and sweetening units.

Based on the information provided by UGC in their Part 71 renewal application, storage vessel (Emission Unit T-1 located at RBU 11-2F Wellsite) commenced construction after August 23, 2011, and prior to September 18, 2015. However, according to UGC, the potential emissions from the storage vessel is below 6 tpy VOC and does not satisfy the criteria for an affected source under the rule. UGC shall maintain records of each VOC emissions determination made under § 60.5365(e) as specified in § 60.5420(c)(5)(ii).

Based on the information provided by UGC in their Part 71 renewal application, all other potential affected facilities under the rule commenced construction before August 23, 2011. Therefore, this rule does not apply to other equipment.

40 C.F.R. part 60, Subpart OOOOa: This subpart establishes emission standards for the control of VOC and SO2 emissions from affected facilities that commence construction, modification or reconstruction after September 18, 2015. Affected facilities include, but are not limited to well completions, centrifugal compressors, reciprocating compressors, pneumatic controllers, storage vessels and sweetening units.

Based on the information provided by UGC in their Part 71 renewal application, the current equipment at Tap 5 predates the applicability date for this subpart. Therefore, this facility is not subject to this subpart.

NESHAP, 40 C.F.R. Part 63
40 C.F.R. Part 63, Subpart A: The requirements of 40 C.F.R. part 63, subpart A apply to sources that are subject to the specific subparts of 40 C.F.R. part 63.
As explained below, Tap 5 is subject to 40 C.F.R. part 63, subpart HH, National Emission Standards for Hazardous Air Pollutants from Oil and Natural Gas Production Facilities and subpart ZZZZ, National Emission Standards for Hazardous Air Pollutants for Stationary Reciprocating Internal Combustion Engines; therefore, the General Provisions of 40 C.F.R. part 63 apply.
40 C.F.R. Part 63, Subpart HH: This subpart establishes emission standards for the control of HAP emissions from affected units located at natural gas production facilities that process, upgrade or store natural gas prior to the point of custody transfer, or that process, upgrade or store natural gas prior to the point at which natural gas enters the natural gas transmission and storage source category or is delivered to a final end user. The affected units are glycol dehydration units, storage vessels with the potential for flash emissions (as defined in the rule) and the group of ancillary equipment and compressors intended to operate in volatile HAP service which are located at natural gas processing plants.
Based on the information provided by UGC in their Part 71 renewal application, there are no storage vessels at Tap 5 or RBU 11-2F wellsite with the potential for flash emissions (as defined in § 63.761). Uncontrolled emissions from dehydration unit T5D-1 exceed the major source thresholds for HAP. Therefore, dehydration unit T5D-1 is subject to the major source requirements of this subpart.
40 C.F.R. Part 63, Subpart YYYY: This rule establishes national emission limitations and work practice standards for HAPs emitted from Stationary Combustion Turbines. The affected source includes the stationary combustion turbine located at a major source of HAP emissions.
As defined in § 63.6090(b)(3), an existing, new or reconstructed stationary combustion turbine with a rated peak power output of less than 1.0 megawatt (MW) does not have to meet the requirements of this subpart. Based on the information provided by UGC in their Part 71 renewal application, the 65 kW Capstone Microturbine Generators at the facility are exempt from the requirements of this subpart because according to UGC, they each have a peak power output of less than 1.0 MW. The maximum rated peak power output for each of the Capstone Microturbines at the facility is 0.065 MW.
40 C.F.R. Part 63, Subpart ZZZZ (Subpart ZZZZ or maximum achievable control technology (MACT) ZZZZ): This subpart establishes emission standards and operating limitations for the control of HAP emissions from stationary spark ignition (SI) and compression ignition (CI) reciprocating internal combustion engines (RICE).
According to the regulations at § 63.6585(b), a major source of HAP emissions is a plant site that emits or has the potential to emit any single HAP at a rate of 10 tons (9.07 megagrams) or more per year or any combination of HAP at a rate of 25 tons (22.68 megagrams) or more per year, except that for oil and gas production facilities, a major source of HAP emissions is determined for each surface site.
The potential HAP emissions from the reciprocating internal combustion engines (T5C-1, T5C-2 and T5BC-2) at Tap 5 are less than the major source thresholds described in the previous paragraph. However, the engines were previously subject to a consent decree that required compliance with the requirements of Subpart ZZZZ for major sources.
As defined in § 63.6675, emissions from any oil and gas exploration or production well and emissions from any pipeline compressor station or pump station shall not be aggregated with emissions from other similar units to determine whether such emission points or stations are major sources, even when emission points are in a contiguous area or common control. For production field facilities, only HAP emissions from glycol dehydration units, storage vessels with the potential for flash emissions, combustion turbines and reciprocating internal combustion engines shall be aggregated for a major source determination. Since the RBU 11-2F wellsite is an area source of HAP emissions, the Arrow C-96 pumping unit engine at the RBU 11-2F wellsite (Emission Unit RBU 11-2F PU) is subject to area source requirements of Subpart ZZZZ, which requires compliance with the requirements of 40 C.F.R. part 60, subpart JJJJ.
40 C.F.R. Part 63, Subpart DDDDD (Boiler MACT): This rule establishes national emission limitations and operating limitations for HAPs emitted from new and existing industrial boilers, institutional boilers, commercial boilers and process heaters that are located at major sources of HAPs. For the purposes of this subpart, a major source of HAPs is as defined in § 63.2, except that for oil and natural gas production facilities, a major source of HAPs is as defined in               § 63.761. Boilers or process heaters that combust natural gas for fuel or have a maximum designed heat input capacity less than 10 MMBtu/hr are subject to work practice standards in lieu of emission limits. For the purposes of this subpart, an affected unit is an existing unit if it was constructed prior to June 4, 2010.
The dehydration unit reboiler and heaters at Tap 5 meet the definition of process heaters in the rule. However, because Tap 5 is subject to the major source requirements of 40 C.F.R. part 63, subpart HH, UGC may account for the reductions of PTE achieved through compliance with previous MACT standards prior to the first compliance date of subsequent MACT standards. Based on the information provided by UGC in their Part 71 application, the PTE at Tap 5 with federally enforceable controls was below major source thresholds for HAP as of the first compliance date of this subpart (January 1, 2016, for existing process heaters and April 1, 2013 for new process heaters). Therefore, Tap 5 does not meet the definition of a major source under the rule and this subpart does not apply. This subpart does not apply to the RBU 11-2F wellsite because it does not meet the definition of a major source under the rule.
40 C.F.R. Part 63, Subpart JJJJJJ (Subpart JJJJJ or Boiler MACT (for area sources)): This rule establishes national emission standards and operating limitations for HAPs emitted from new and existing industrial boilers, institutional boilers, and commercial boilers that are fueled by coal, biomass, or oil and are located at area sources of HAPs. For the purposes of this subpart, an affected unit is an existing unit if it was constructed prior to June 4, 2010.
Based on the information provided by UGC in their Part 71 renewal application, there are no industrial, commercial, or institutional boilers located at Tap 5 as defined in the rule. Therefore, Subpart JJJJJJ does not apply.
40 C.F.R. Part 64 (Compliance Assurance Monitoring (CAM) Rule):
Pursuant to requirements concerning enhanced monitoring and compliance certification under the CAA, the EPA promulgated regulations to implement compliance assurance monitoring (CAM) for major stationary sources of air pollution, for purposes of title V permitting that are required to obtain operating permits under Part 71. The rule requires owners or operators of such sources to conduct monitoring that provide a reasonable assurance of compliance with applicable requirements under the CAA.
    CAM Applicability

According to § 64.2(a), CAM applies to each pollutant specific emission unit (PSEU) located at a major source which is required to obtain a Part 71 permit if the unit satisfies all of the following criteria:

 The unit is subject to an emission limitation or standard for the applicable regulated air pollutant other than an emissions limitation or standard that is exempt under § 64.2(b)(1);

 The unit uses a control device to achieve compliance with any such limit or standard; and

 The unit has pre-control device emissions of the applicable regulated pollutant that are equal to or greater than 100 percent of the amount, in tpy, required for a source to be classified as a major Title V source.

    CAM Plan Submittal Deadlines

 Large pollutant-specific emissions units. A CAM plan submittal for all PSEUs with the PTE (taking into account control devices) of any one regulated air pollutant in an amount equal to or greater than 100 percent of the amount, in tpy, required for a source to be classified as a major source, is due at the following times:

 On or after April 20, 1998, if by that date, a Part 71 application has either:
 Not been filed; or
 Not yet been determined to be complete.

 On or after April 20, 1998, if a Part 71 permit application for a significant modification is submitted with respect to those PSEUs for which the requested permit revision is applicable; or

 Upon application for a renewed Part 71 permit and a CAM plan has not yet been submitted with an initial or a significant modification application, as specified above.

 Other pollutant-specific emissions units. A CAM Plan must be submitted for all PSEUs that are not large PSEUs, but are subject to this rule, upon application for a Part 71 renewal permit.

Based on the information provided by UGC in their Part 71 renewal application, dehydration unit (Emission Unit T5D-1) is a PSEU with pre-controlled emissions that equal or exceed 100 percent of major HAP thresholds. However, Emission Unit T5D-1 is subject to the major source requirements of 40 C.F.R. part 63, subpart HH and thus meets the exemption criteria of
§ 64.2(b)(1). Since no other PSEUs at the facility have pre-controlled emissions that exceed or equal 100% of major source thresholds, Tap 5 is not subject to CAM requirements.

40 C.F.R. Part 68 (Chemical Accident Prevention Provisions): This rule applies to stationary sources that manufacture, process, use, store or otherwise handle more than the threshold quantity of a regulated substance in a process. Regulated substances include 77 toxic and 63 flammable substances which are potentially present in the natural gas stream entering the facility and in the storage vessels located at the facility. The quantity of a regulated substance in a process is determined according to the procedures presented under § 68.115. Sections 68.115(b)(l) and (2)(i) indicate that toxic and flammable substances in a mixture do not need to be considered when determining whether more than a threshold quantity is present at a stationary source if the concentration of the substance is below one percent by weight of the mixture. Section 68.115(b)(2)(iii) indicates that prior to entry into a natural gas processing plant, regulated substances in naturally occurring hydrocarbon mixtures need not be considered when determining whether more than a threshold quantity is present at a stationary source. Naturally occurring hydrocarbon mixtures include condensate, field gas, and produced water.
Based on the updated information provided in UGC's Part 71 renewal application, Tap 5 does not have regulated substances above the threshold quantities in this rule; and therefore, are not subject to the requirement to develop and submit a risk management plan.
EPA Trust Responsibility  -  consultation requirements
Endangered Species Act (ESA), 16 U.S.C. § 1531 et seq.
Under section 7(a)(2) of the ESA, federal agencies are required to ensure that actions they authorize, fund, or carry out are not likely to jeopardize the continued existence of any listed, threatened, or endangered species, or destroy or adversely modify the designated critical habitat of such species. 16 U.S.C. § 1536(a)(2). The U.S. Fish and Wildlife Service and National Marine Fisheries Service have promulgated ESA implementing regulations at 50 C.F.R. part 402.
The CAA title V permit program requires the EPA to issue a permit specifically describing the permittee's existing pollution control obligations under the CAA. A title V permit does not generally create any new substantive requirements, but rather simply incorporates all existing CAA requirements, called "applicable requirements," into a single unified operating permit applicable to a particular facility. The title V permit the EPA is issuing to UGC does not authorize the construction of new emission units, or emission increases from existing units, nor does it otherwise authorize any physical modifications to the facility or its operations. The EPA has concluded that the permit appropriately incorporates all existing CAA requirements applicable to the facility. The EPA lacks discretion in this title V permitting decision to take action that could inure to the benefit of any listed species or their critical habitat. The EPA has concluded that issuance of this permit will have no effect on any listed species or their critical habitat. Accordingly, this permit action is consistent with the requirements of ESA section 7.
National Historic Preservation Act (NHPA), Public Law 89-665; 54 U.S.C. 300101 et seq.
The title V permit EPA is issuing to UGC does not authorize the construction of new emission units, or emission increases from existing units, nor does it otherwise authorize any physical modifications to the facility or its operations. The EPA has concluded that issuance of this permit will have no effect on any property under the NHPA of 1966 pursuant to section 106 of the NHPA, which requires federal agencies to consider the impact of their actions on historic properties.
Environmental Justice (EJ)
Executive Order 12898 directs federal agencies "to the greatest extent practicable and permitted by law," to "make achieving environmental justice part of its mission by identifying and addressing as appropriate, disproportionately high and adverse human health or environmental effects of its programs, policies, and activities on minority populations and low-income populations." Executive Order 14008 further directs federal agencies to "to address the disproportionately high and adverse human health, environmental, climate-related and other cumulative impacts on disadvantaged communities, as well as the accompanying economic challenges of such impacts." In addition, Executive Order 13985 calls on each federal agency to "pursue a comprehensive approach to advancing equity for all, including people of color and others who have been historically underserved, marginalized, and adversely affected by persistent poverty and inequality." Accordingly, advancing environmental justice and equity is one of EPA's highest priorities as set forth in the Agency's FY22-26 Strategic Plan.

The EPA defines "Environmental Justice" (EJ) to include the fair treatment and meaningful involvement of all people regardless of race, color, national origin, or income with respect to the development, implementation, and enforcement of environmental laws, regulations, and polices. The EPA's goal is to provide an opportunity for overburdened populations or communities to participate in the permitting process. "Overburdened" is used to describe the minority, low-income, tribal and indigenous populations or communities in the United States that potentially experience disproportionate environmental harms and risks due to exposures or cumulative impacts or greater vulnerability to environmental hazards.

As part of EPA's trust responsibility to the Ute Indian Tribe and the above noted Executive Orders, the EPA has kept the Tribe informed about this permit action by copying them on key communications such as the emailed application completeness determination and will provide a minimum 30-day public comment period, and opportunity for a public hearing if requested. The EPA does not routinely offer tribal consultation on Title V renewal permits for existing operating sources that do not incorporate any significant changes from the previously issued permit unless there is a request or known interest from the Tribe.

Permit Content

Draft permit sections 1 - 5

The draft permit contains all of the required elements for Part 71 permits, as specified in 40 C.F.R. § 71.5, including, but not limited to:

 Emissions limitations and standards, including those operational requirements and limitations that assure compliance with all applicable requirements at the time of permit issuance, as identified and discussed in this Statement of Basis;

 The permit duration, not to exceed 5 years;

 Monitoring and related recordkeeping and reporting requirements sufficient to assure and demonstrate compliance with all applicable requirements;

 A severability clause to ensure the continued validity of the various permit requirements in the event of a challenge to any portions of the permit;

 Specific provisions stating that: (a) any noncompliance constitutes a violations of the CAA and is grounds for enforcement action; (b) it is not a defense for the Permittee in an enforcement action that it would have been necessary to halt or reduce the permitted activity in order to maintain compliance with the permit; (c) instructions for how the permit may be modified, revoked, reopened, reissued, or terminated for cause; (d) the permit does not convey and property rights or exclusive privilege; (e) and upon request, the Permittee shall furnish to the permitting authority copies of required records;

 A provision to ensure that the Permittee pays fees to the EPA consistent with the fee schedule approved in 40 C.F.R. § 71.9;

 A provision to ensure that the permit expires upon five years elapsing from the effective date; and

 An off-permit changes provision allowing changes that are not addressed or prohibited by the permit.
Changes Between the Previous Permit and Draft Permit

The permit has been reformatted using the EPA's new Part 71 permit and statement of basis standard templates. As a result, the permit condition numbering system has changed from the previous permit. For national consistency, the semi-annual reporting timeframe in the renewed permit (permit condition 45) is 30 days following the end of reporting period instead of 90 days listed in the previously issued permit. The renewed permit incorporates the minor modification request to add a 1,112 hp (site rated) compressor engine. Also, like-kind replacement Emission Unit's power ratings, dates of manufacture and installation and serial numbers have been updated.
Public Participation

Public Notice

As described in 40 C.F.R. § 71.11(a)(5), all Part 71 draft operating permits shall be publicly noticed and made available for public comment. The public notice of permit actions and public comment period is described in 40 C.F.R. § 71(d).

There will be a 30-day public comment period for actions pertaining to a draft permit. Notification will be given for this draft permit to the permit applicant, the affected tribe, the affected state, the tribal and local air pollution control agencies, the city and county executives, and the state and federal land managers which have jurisdiction over the area where the source is located. A notification will also be provided to all persons who have submitted a written request to be included on the notification list. If you would like to be added to our notification list to be informed of future actions on this or other CAA permits issued in Indian country, please send an email using the link for Region 8 CAA permit public comment opportunities at http://www.epa.gov/caa-permitting/caa-permit-public-comment-opportunities-region-8.

Public notice will be provided at http://www.epa.gov/caa-permitting/caa-permit-public-comment-opportunities-region-8 giving opportunity for public comment on the draft permit and the opportunity to request a public hearing.

Opportunity to Comment

Members of the public will be given an opportunity to review a copy of the draft permit prepared by the EPA, the application, this Statement of Basis for the draft permit and all supporting materials for the draft permit. An electronic copy of the draft permit and related documents may be viewed online at the website cited below. Information is also available by emailing or speaking with the following contact:

Contact: Suman Kunwar, Environmental Engineer,<PHONE_NUMBER> or<EMAIL_ADDRESS>
Electronic copies of the draft permit, Statement of Basis and supporting permit record may be accessed for review at:
https://www.epa.gov/caa-permitting/caa-permit-public-comment-opportunities-region-8.

Any interested person may submit written comments on the draft Part 71 operating permit during the public comment period by email using the instructions on the public comment opportunities web site address listed above or through https://www.regulations.gov (Docket I.D. #EPA-R08-OAR-2021-0770). All comments will be considered and answered by the EPA in making the final decision on the permit. The EPA keeps a record of the commenters and of the issues raised during the public participation process.

Anyone, including the applicant, who believes any condition of the draft permit is inappropriate should raise all reasonable ascertainable issues and submit all arguments supporting their position by the close of the public comment period. Any supporting materials submitted must be included in full and may not be incorporated by reference, unless the material has already been submitted as part of the administrative record in the same proceeding or consists of state or federal statutes and regulations, EPA documents of general applicability or other generally available reference material.

The final permit will be a public record that can be obtained upon request. A statement of reasons for changes made to the draft permit and responses to comments received will be sent to all persons who comment on the draft permit. The final permit and response to comments document will also be available online at: https://www.epa.gov/caa-permitting/caa-permits-issued-epa-region-8. Anyone may request a copy of the final permit at any time by contacting the Tribal Air Permit Program at<PHONE_NUMBER> or by sending an email to<EMAIL_ADDRESS>

Opportunity to Request a Hearing

A person may submit a written request for a public hearing to the Part 71 Permitting Lead, U.S. EPA Region 8, by stating the nature of the issues to be raised at the public hearing. Based on the number of hearing requests received, the EPA will hold a public hearing whenever it finds there is a significant degree of public interest in a draft operating permit. The EPA will provide public notice of the public hearing. If a public hearing is held, any person may submit oral or written statements and data concerning the draft permit.

Appeal of Permits

Within 30 days after the issuance of a final permit decision, any person who filed comments on the draft permit or participated in the public hearing may petition to the Environmental Appeals Board (EAB) to review any condition of the permit decision. Any person who failed to file comments or participate in the public hearing may petition for administrative review, only if the changes from the draft to the final permit decision or other new grounds were not reasonably foreseeable during the public comment period. The 30-day period to appeal a permit begins with the EPA's service of the notice of the final permit decision.

The petition to appeal a permit must include a statement of the reasons supporting the review, a demonstration that any issues were raised during the public comment period, a demonstration that it was impracticable to raise the objections within the public comment period or that the grounds for such objections arose after such a period. When appropriate, the petition may include a showing that the condition in question is based on a finding of fact or conclusion of law which is clearly erroneous; or, an exercise of discretion, or an important policy consideration that the EAB should review.

The EAB will issue an order either granting or denying the petition for review, within a reasonable time following the filing of the petition. Public notice of the grant of review will establish a briefing schedule for the appeal and state that any interested person may file an amicus brief. Notice of denial of review will be sent only to the permit applicant and to the person requesting the review. To the extent review is denied, the conditions of the final permit decision become final agency action.

A motion to reconsider a final order shall be filed within ten days after the service of the final order. Every motion must set forth the matters claimed to have been erroneously decided and the nature of the alleged errors. Motions for reconsideration shall be directed to the Administrator rather than the EAB. A motion for reconsideration shall not stay the effective date of the final order unless it is specifically ordered by the EAB.

Petition to Reopen a Permit for Cause

Any interested person may petition the EPA to reopen a permit for cause, and the EPA may commence a permit reopening on its own initiative.

The EPA will only revise, revoke and reissue, or terminate a permit for the reasons specified in 40 C.F.R. § 71.7(f) or 71.6(a)(6)(i). All requests must be in writing and must contain facts or reasons supporting the request. If the EPA decides the request is not justified, it will send the requester a brief written response giving a reason for the decision. Denial of these requests is not subject to public notice, comment or hearings. Denials can be informally appealed to the EAB by a letter briefly setting forth the relevant facts.
Abbreviations and Acronyms

ASTM  		American Society for Testing and Materials
bbl			barrel
CAA  			Clean Air Act [42 U.S.C. § 7401, et seq.]
CEDRI		Compliance and Emission Reporting Data Interface
C.F.R.			Code of Federal Regulations
CH2O			Formaldehyde
CO			Carbon Monoxide
EPA  			U.S. Environmental Protection Agency, Region 8
EU  			Emission Unit
Facility  		Tap 5 Compressor Station: Latitude 39.9750760N, Longitude<PHONE_NUMBER>W
gal  			gallon
g  			grams
HAP  			Hazardous Air Pollutant
hp			horsepower
hr  			hour
I.D.		         	Identification Number
kg  			kilogram
kW			kilowatt
lb  			pound
MACT  		Maximum Achievable Control Technology
Mfd			Manufactured
Mg  			Megagram
MMBtu/hr  	Million British Thermal Units per Hour
MMscfd		Million Standard Cubic Feet per Day
NESHAP  		National Emission Standards for Hazardous Air Pollutants
NOx  			Nitrogen Oxides
NSPS  			New Source Performance Standards
NSR  			New Source Review
Operator	                 Utah Gas Corporation
Permittee	                 Utah Gas Corporation
PM  			Particulate Matter
PM10  			Particulate Matter less than 10 microns in diameter
ppm  			parts per million
PSD  			Prevention of Significant Deterioration
PTE   			Potential to Emit
SO2  			Sulfur Dioxide
VOC  			Volatile Organic Compounds