SUMMIT MIDSTREAM PARTNERS, LLC — Warning Letter

32022005WL_Warning Letter_01032022_(21-199716)_text.pdf, page 1Official PDFWARNING LETTER VIA ELECTRONIC MAIL TO: heath.deneke@summitmidstream.com and MStratmann@summitmidstream.com January 3, 2022 Mr. Heath Deneke President/CEO Summit Midstream Partners, LLC (SMP) 910 Louisiana Street, Suite 4200 Houston, TX 77002 CPF 3-2022-005-WL Dear Mr. Deneke: From March 23, April 26 to 29, May 10 to 12 and June 8 to 10, 2021, a representative of the Pipeline and Hazardous Materials Safety Administration (PHMSA) pursuant to Chapter 601 of 49 United States Code (U.S.C.) inspected your procedures, records and field assets virtually and in Epping, North Dakota. As a result of the inspection, it is alleged that Summit Midstream Partners (SMP) have committed probable violations of the Pipeline Safety Regulations, Title 49, Code of Federal Regulations (CFR). The items inspected and the probable violations are:#

32022005WL_Warning Letter_01032022_(21-199716)_text.pdf, page 21. §195.404 Maps and records. (a)… (c) Each operator shall maintain the following records for the periods specified; (3) A record of each inspection and test required by this subpart shall be maintained for at least 2 years or until the next inspection or test is performed, whichever is longer. §195.428 Overpressure safety devices and overfill protection systems. (a) Except as provided in paragraph (b) of this section, each operator shall, at intervals not exceeding 15 months, but at least once each calendar year, or in the case of pipelines used to carry highly volatile liquids, at intervals not to exceed 7½ months, but at least twice each calendar year, inspect and test each pressure limiting device, relief valve, pressure regulator, or other item of pressure control equipment to determine that it is functioning properly, is in good mechanical condition, and is adequate from the standpoint of capacity and reliability of operation for the service in which it is used. (b) In the case of relief valves on pressure breakout tanks containing highly volatile liquids, each operator shall test each valve at intervals not exceeding 5 years. (c) Aboveground breakout tanks that are constructed or significantly altered according to API Std 2510 (incorporated by reference, see § 195.3) after October 2, 2000, must have an overfill protection system installed according to API Std 2510, section 7.1.2. Other aboveground breakout tanks with 600 gallons (2271 liters) or more of storage capacity that are constructed or significantly altered after October 2, 2000, must have an overfill protection system installed according to API RP 2350 (incorporated by reference, see § 195.3). However, an operator need not comply with any part of API RP 2350 for a particular breakout tank if the operator describes in the manual required by § 195.402 why compliance with that part is not necessary for safety of the tank. (d) After October 2, 2000, the requirements of paragraphs (a) and (b) of this section for inspection and testing of pressure control equipment apply to the inspection and testing of overfill protection systems. Based on a July 9, 2021 data response, SMP failed to produce records showing that overfill protection devices for all five tanks were tested in 2019. Furthermore, the 2020 data was not provided for the two surge tanks (Little Muddy and Stampede). 2#

32022005WL_Warning Letter_01032022_(21-199716)_text.pdf, page 32. §195.452 Pipeline integrity management in high consequence areas. (a)… (l) What records must an operator keep to demonstrate compliance? (1) An operator must maintain, for the useful life of the pipeline, records that demonstrate compliance with the requirements of this subpart. At a minimum, an operator must maintain the following records for review during an inspection: (ii) Documents to support the decisions and analyses, including any modifications, justifications, deviations and determinations made, variances, and actions taken, to implement and evaluate each element of the integrity management program listed in paragraph (f) of this section. (f) What are the elements of an integrity management program? An integrity management program begins with the initial framework. An operator must continually change the program to reflect operating experience, conclusions drawn from results of the integrity assessments, and other maintenance and surveillance data, and evaluation of consequences of a failure on the high consequence area. An operator must include, at minimum, each of the following elements in its written integrity management program: (1) A process for identifying which pipeline segments could affect a high consequence area; Based on a July 9, 2021 data response, SMP failed to provide the assumptions used in their water transport analysis covering all the jurisdictional pipelines in the Polar Divide unit. Specifically, SMP provided the results, but not the assumptions as required. Also, another July 9, 2021 data response failed to address whether buffer zones were used and if so, the criteria and assumptions set forth for buffer zones application. 3. §195.452 Pipeline integrity management in high consequence areas. (a)… (l) What records must an operator keep to demonstrate compliance? (1) An operator must maintain, for the useful life of the pipeline, records that demonstrate compliance with the requirements of this subpart. At a minimum, an operator must maintain the following records for review during an inspection: 3#

32022005WL_Warning Letter_01032022_(21-199716)_text.pdf, page 4(ii) Documents to support the decisions and analyses, including any modifications, justifications, deviations and determinations made, variances, and actions taken, to implement and evaluate each element of the integrity management program listed in paragraph (f) of this section. (f) What are the elements of an integrity management program? An integrity management program begins with the initial framework. An operator must continually change the program to reflect operating experience, conclusions drawn from results of the integrity assessments, and other maintenance and surveillance data, and evaluation of consequences of a failure on the high consequence area. An operator must include, at minimum, each of the following elements in its written integrity management program: (6) Identification of preventive and mitigative measures to protect the high consequence area (see paragraph (i) of this section); (i) What preventive and mitigative measures must an operator take to protect the high consequence area? (1) General requirements. An operator must take measures to prevent and mitigate the consequences of a pipeline failure that could affect a high consequence area. These measures include conducting a risk analysis of the pipeline segment to identify additional actions to enhance public safety or environmental protection. Such actions may include, but are not limited to, implementing damage prevention best practices, better monitoring of cathodic protection where corrosion is a concern, establishing shorter inspection intervals, installing EFRDs on the pipeline segment, modifying the systems that monitor pressure and detect leaks, providing additional training to personnel on response procedures, conducting drills with local emergency responders and adopting other management controls. (4) Emergency Flow Restricting Devices (EFRD). If an operator determines that an EFRD is needed on a pipeline segment to protect a high consequence area in the event of a hazardous liquid pipeline release, an operator must install the EFRD. In making this determination, an operator must, at least, consider the following factors—the swiftness of leak detection and pipeline shutdown capabilities, the type of commodity carried, the rate of potential leakage, the volume that can be released, topography or pipeline profile, the potential for ignition, proximity to power sources, location of nearest response personnel, specific terrain between the pipeline segment and the high consequence area, and benefits expected by reducing the spill size. Based on the inspection interview, there are no records of EFRD studies on the Polar and Divide purchased assets or on the Little Muddy pipeline built by SMP. Specifically, the record of the SMP EFRD study on the Polar Divide system is missing. See the SMP data response below: 4#

32022005WL_Warning Letter_01032022_(21-199716)_text.pdf, page 5Summit purchased the Polar 10” and Divide 8” from Bear Tracker. No EFRD study was performed by Bear Tracker prior to construction of these pipelines. However, Summit installed remote control valves (RCVs) at Epping station for the Polar 10” at the inlet of the station and at the outlet of the station to Colt Hub. The Divide 8” has a RCV at the outlet of Divide station and at the inlet of the DAPL valve yard. Summit built the Little Muddy pipeline in three phases in 2014 and 2015. A check valve was not considered because the line is bi-directional. A remote control valve is located at the inlet of the Little Muddy station. Summit’s control room in Houston operates the RCVs. An EFRD analysis has been performed and implemented by Summit’s Engineering team but an official document or record of the EFRD study cannot be located. Under 49 U.S.C. § 60122 and 49 CFR § 190.223, you are subject to a civil penalty not to exceed $225,134 per violation per day the violation persists, up to a maximum of $2,251,334 for a related series of violations. For violation occurring on or after January 11, 2021 and before May 3, 2021, the maximum penalty may not exceed $222,504 per violation per day the violation persists, up to a maximum of $2,225,034 for a related series of violations. For violation occurring on or after July 31, 2019 and before January 11, 2021, the maximum penalty may not exceed $218,647 per violation per day the violation persists, up to a maximum of $2,186,465 for a related series of violations. For violation occurring on or after November 27, 2018 and before July 31, 2019, the maximum penalty may not exceed $213,268 per violation per day, with a maximum penalty not to exceed $2,132,679. For violation occurring on or after November 2, 2015 and before November 27, 2018, the maximum penalty may not exceed $209,002 per violation per day, with a maximum penalty not to exceed $2,090,022. We have reviewed the circumstances and supporting documents involved in this case, and have decided not to conduct additional enforcement action or penalty assessment proceedings at this time. We advise you to correct the items identified in this letter. Failure to do so will result in Summit Midstream Partners, LLC being subject to additional enforcement action. No reply to this letter is required. If you choose to reply, in your correspondence please refer to CPF 3-2022-005-WL. Be advised that all material you submit in response to this enforcement action is subject to being made publicly available. If you believe that any portion of your responsive material qualifies for confidential treatment under 5 U.S.C. 552(b), along with the complete original document you must provide a second copy of the document with the portions you believe qualify for confidential treatment redacted and an explanation of why you believe the redacted information qualifies for confidential treatment under 5 U.S.C. 552(b). 5#

32022005WL_Warning Letter_01032022_(21-199716)_text.pdf, page 6Sincerely, Gregory A. Ochs Director, Central Region, Office of Pipeline Safety Pipeline and Hazardous Materials Safety Administration CC: Mr. Matthew Stratmann, Senior Director, Integrity and Health & Safety, Summit Midstream Partners, LLC, 910 Louisiana Street, Suite 4200, Houston, TX 77002, (MStratmann@summitmidstream.com) 6#