SPIRE MOGAS PIPELINE LLC — Warning Letter

32025002WL_Warning Letter_05192024_(22-237906)_text.pdf, page 1Official PDFWARNING LETTER VIA ELECTRONIC MAIL TO: scott.smith@spireenergy.com; mark.lowe@spireenergy.com; randy.wilson@spireenergy.com; dave.feeman@spireenergy.com May 19, 2025 Mr. Scott Smith President, Spire Midstream Spire MOGAS Pipeline LLC 3773 Richmond Avenue, Suite 300 Houston, TX 77002 CPF 3-2025-002-WL Dear Mr. Smith: From May 9 through May 13, 2022 and September 21, 2022, a representative of the Pipeline and Hazardous Materials Safety Administration (PHMSA), Office of Pipeline Safety (OPS), pursuant to Chapter 601 of 49 United States Code (U.S.C.), virtually inspected MoGAS Pipeline, LLC’s (MoGAS) procedures and records for Control Room Management (CRM) in Wentzville, Missouri. Following the inspection, MoGAS was acquired by Spire Missouri Inc. East in January 2024.1 As a result of the inspection, it is alleged that you have committed probable violations of the Pipeline Safety Regulations, Title 49, Code of Federal Regulations (CFR). The items inspected and the probable violations are: 1. § 192.631 Control room management. (a) General. (1) This section applies to each operator of a pipeline facility with a controller working in a control room who monitors and controls all or part of a pipeline facility through a SCADA system. Each operator must have and follow written control room management procedures that implement the requirements of this section. . . . 1 National Registry Notification B-20240423-52614 (April 23, 2024). A new OPID (OPID 40855) was requested and issued under the name Spire MoGAS Pipeline, LLC (SpireMoGAS).#

32025002WL_Warning Letter_05192024_(22-237906)_text.pdf, page 2(a) . . . . (b) Provide adequate information. Each operator must provide its controllers with the information, tools, processes and procedures necessary for the controllers to carry out the roles and responsibilities the operator has defined by performing each of the following: (1) Implement sections 1, 4, 8, 9, 11.1, and 11.3 of API RP 1165 (incorporated by reference, see §192.7) whenever a SCADA system is added, expanded or replaced, unless the operator demonstrates that certain provisions of sections 1, 4, 8, 9, 11.1, and 11.3 of API RP 1165 are not practical for the SCADA system used; MoGAS failed to provide records that demonstrated that it implemented sections 1, 4, 8, 9, 11.1, and 11.3 of API RP 1165, as required by §§ 192.631(c)(1) and 192.631(j)(1). While MoGAS’ “Control Room Manual,” (version 3.2, effective 2019) (CRM Plan), section 4.1 stated, “sections 1, 4, 8, 9, 11.1, and 11.3 of API RP-1165 shall be implemented by MoGAS whenever the SCADA system is added, expanded or replaced after August 1, 2012,” MoGAS indicated to PHMSA that, to establish consistency in their SCADA screen design, it “[u]tilize[d] one of its existing SCADA screens with similar layout to produce the basis layout for new station screens to maintain consistency with other station screens.” While this supported a level of consistency when designing and publishing screens, it was not adequate to demonstrate compliance with §§ 192.631(c)(1) and 192.631(j)(1) because there was no audit or review performed to verify the SCADA design manual was compliant with API RP 1165 and the screens were compliant with API RP 1165. Therefore, MoGAS failed to ensure API RP 1165 sections 1, 4, 8, 9, 11.1, and 11.3 were implemented, as required by §§ 192. 631(c)(1) and 192.631(j)(1). 2. § 192.631 Control room management. (a) General. (1) This section applies to each operator of a pipeline facility with a controller working in a control room who monitors and controls all or part of a pipeline facility through a SCADA system. Each operator must have and follow written control room management procedures that implement the requirements of this section . . . . (b) . . . . (c) Provide adequate information. Each operator must provide its controllers with the information, tools, processes and procedures necessary for the controllers to carry out the roles and responsibilities the operator has defined by performing each of the following: (1) . . . . (2) Conduct a point-to-point verification between SCADA displays and related field equipment when field equipment is added or moved and when other changes that affect pipeline safety are made to field equipment or SCADA displays; MoGAS failed to provide a record to demonstrate the completion of the initial point-to-point when the new SPIRE STL interconnect was added to the SCADA display, per the requirements of § 192.631(c)(2). The SPIRE STL facility became operational on December 11, 2020 and#

32025002WL_Warning Letter_05192024_(22-237906)_text.pdf, page 3published to the SCADA system for controllers to monitor and control that same day. Per MoGAS, a point-to-point (P2P) was completed prior to publishing to the production SCADA system. However, MoGAS was unable to provide a record of the P2P verification, as required by § 192.631(j)(1). In addition, MoGAS’ CRM Plan, section 4.2, was inadequate to support a thorough P2P to demonstrate compliance. MoGAS’ CRM Plan identified two forms—Form 4.2 Alarm Set Point and Verification and Form 6.2c, for safety related points—required to be used to document the P2P verification. MoGAS’ CRM Plan did not provide enough detail on what was required to be documented on each form. For example, subsections 2b and 2c stated, “Controllers will confirm that the SCADA display is reflecting the same values being observed in the field and documented via Form 4.2 Alarm Set Points and Verification Log. If the point is a Safety Related Point it will be verified on Form 6.2c. Information that must be verified:….(b) [d]ata value or status, and (c) any alarm settings.” The intent of a P2P is to verify field conditions and data match SCADA information being presented to the controller. Thus, P2P records need to document the comparison of values/status and not just that the comparison was observed. Therefore, the CRM Plan failed to include required documentation, such as documenting the field value/status and SCADA value/status. For adequate documentation of alarms, the documentation must include verification that the alarms presented at the designated set points with the correct priority and description. CRM Plan section 3 only required a “representative sampling of SCADA screens.” This is not adequate for new commissioned points into SCADA. All screens must be verified and documented. Furthermore, the CRM Plan did not include documentation requirements for: (1) the name of the employee verifying in the field and the name of the employee verifying SCADA, (2) the date of the verification, (3) whether the point was verified live or through simulation, and (4) any comments related to the verification and follow up items to correct and retest the point if required. Therefore, MoGAS’ procedures were deficient and caused MoGAS to be unable to provide adequate records demonstrating the completion of the P2P when the new SPIRE STL interconnect was added to the SCADA display, per the requirements of § 192.631(c)(2). 3. § 192.631 Control room management. (a) General. (1) This section applies to each operator of a pipeline facility with a controller working in a control room who monitors and controls all or part of a pipeline facility through a SCADA system. Each operator must have and follow written control room management procedures that implement the requirements of this section . . . . (b) . . . . (c) Provide adequate information. Each operator must provide its controllers with the information, tools, processes and procedures necessary for the controllers to carry out the roles and responsibilities the operator has defined by performing each of the following: (1) . . . . (4) Test any backup SCADA systems at least once each calendar year, but at intervals not to exceed 15 months;#

32025002WL_Warning Letter_05192024_(22-237906)_text.pdf, page 4MoGAS failed to adequately test its backup SCADA system and failed to provide a record of the tests for the backup SCADA system in 2019 and 2021, per the requirements of §§ 192.631(c)(4) and 192.631(j)(1). MoGAS also failed to follow its CRM Plan, section 4.4, which required testing both control room backup systems, “[a]t least monthly, in periods not to exceed 15 months.” Specifically, in 2019 and 2021, MoGAS only tested the functionality to transfer and operate on the backup SCADA servers and did not travel to the backup control room and operate from the facility. Backup SCADA systems include SCADA servers, HMIs, printers, IT business systems, FAX machines, building access and anything related to the function of a control room. In addition, MoGAS’ CRM Plan section 4.4 was inadequate to provide instructions to MoGAS’ controllers on how to thoroughly conduct and document the test. The CRM Plan failed to contain any instructions on (1) how the transfer was to be completed, (2) how controllers were to relocate, (3) who and what are the qualifications to monitor the system during travel between facilities, as the procedure stated, “[field] personnel [at the back up location] may monitor the system until [primary control room] gas controllers can travel to the [backup] location to take over,” and (4) how the system would be transferred back from the backup control room to primary control room. While MoGAS’ CRM Plan contained a requirement to “confirm reception of good data,” it did not require the use of a check list, or other documentation tools, to document the testing of key SCADA functions or to document the operating server. Therefore, MoGAS failed to adequately test its backup SCADA system, per the requirements of § 192.631(c)(4). 4. § 192.631 Control room management. (a) General. (1) This section applies to each operator of a pipeline facility with a controller working in a control room who monitors and controls all or part of a pipeline facility through a SCADA system. Each operator must have and follow written control room management procedures that implement the requirements of this section. . . . (b) . . . . (h) Training. Each operator must establish a controller training program and review the training program content to identify potential improvements at least once each calendar year, but at intervals not to exceed 15 months. An operator's program must provide for training each controller to carry out the roles and responsibilities defined by the operator. In addition, the training program must include the following elements: (1) . . . . (6) Control room team training and exercises that include both controllers and other individuals, defined by the operator, who would reasonably be expected to operationally collaborate with controllers (control room personnel) during normal, abnormal or emergency situations. Operators must comply with the team training requirements under this paragraph no later than January 23, 2018. MoGAS failed to have a procedure to address the requirements to conduct team training and failed to conduct team training for 2019, 2020, 2021, as required by §§ 192.605(b)(12) and 192.631(h)(6). When asked by PHMSA during the inspection, MoGAS failed to (1) provide a#

32025002WL_Warning Letter_05192024_(22-237906)_text.pdf, page 5procedure for the team training, or (2) conduct control room team training, and (3) identify personnel that would operationally collaborate with controllers as required by the code. Therefore, MoGAS failed to follow the requirements of §§ 192.605(b)(12) and 192.631(h)(6). Under 49 U.S.C. § 60122 and 49 CFR § 190.223, you are subject to a civil penalty not to exceed $272,926 per violation per day the violation persists, up to a maximum of $2,729,245 for a related series of violations. For violation occurring on or after December 28, 2023 and before December 30, 2024 the maximum penalty may not exceed $266,015 per violation per day the violation persists, up to a maximum of $2,660,135 for a related series of violations. For violation occurring on or after January 6, 2023 and before December 28, 2023 the maximum penalty may not exceed $257,664 per violation per day the violation persists, up to a maximum of $2,576,627 for a related series of violations. For violation occurring on or after March 21, 2022 and before January 6, 2023 the maximum penalty may not exceed $239,142 per violation per day the violation persists, up to a maximum of $2,391,142 for a related series of violations. For violation occurring on or after May 3, 2021 and before March 21, 2022 the maximum penalty may not 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. No reply to this letter is required. If you choose to reply, in your correspondence please refer to CPF 3-2025-002-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). Sincerely, David Barrett Acting Director, Central Region, Office of Pipeline Safety Pipeline and Hazardous Materials Safety Administration cc: Mark Lowe, Senior VP- Eng, Gas Supply & Ops Services, Spire MOGAS Pipeline, LLC, mark.lowe@spireenergy.com Randy Wilson, Director Compliance, Spire MOGAS Pipeline, LLC, randy.wilson@spireenergy.com David Feeman, Director, Spire MOGAS Pipeline, LLC, dave.feeman@spireenergy.com#