EQT PRODUCTION — Notice of Amendment

party submissionOfficial PDF12024040NOA_Operator Response to Notice and Request Time Extension_12032024_(23-276594).pdf#

12024040NOA_Notice of Amendment_11122024_(23-276594)_text.pdf, page 1Official PDFNOTICE OF AMENDMENT OVERNIGHT EXPRESS DELIVERY November 12, 2024 Mr. Justin Trettel Senior Vice President EQT Production Company 2200 Energy Drive Canonsburg, Pennsylvania 15317 CPF 1-2024-040-NOA Dear Mr. Trettel: From October 31, 2022 through March 27, 2023, representatives of the Pipeline and Hazardous Materials Safety Administration (PHMSA) pursuant to Chapter 601 of 49 United States Code (U.S.C.), inspected EQT Production Company’s (EQT))1 procedures for compliance with PHMSA’s gas pipeline integrity regulations2 in Canonsburg, Pennsylvania. As a result of the inspection, PHMSA has identified apparent inadequacies found within EQTs’ plans or procedures. The items inspected and the inadequacies are described below: 1. 49 C.F.R. § 192.605 Procedural manual for operations, maintenance, and emergencies. (a) . . . . (b) Maintenance and normal operations. The manual required by 1 At the time of the inspection, the operator of the pipeline facilities being inspected for compliance with Part 192 was Equitrans Midstream Corporation (PHMSA Operator Identification No. (OPID) 31604). However, Equitrans Midstream Corporation and its pipeline facilities that were the subject of the inspection have since been acquired by EQT Corporation (see, e.g., https://ir.eqt.com/investor-relations/news/news-release-details/2024/EQT-Completes- Acquisition-of-Equitrans-Midstream/default.aspx), and the pipeline facilities are presently operated by EQT Corporation’s subsidiary, EQT Production Company (PHMSA OPID 39491). 2 See, e.g., the requirements established in PHMSA final rule titled “Pipeline Safety: Safety of Gas Transmission Pipelines: MAOP Reconfirmation, Expansion of Assessment Requirements, and Other Related Amendments” (84 Fed. Reg. 52,180 (Oct 1, 2019)) as codified in 49 C.F.R. Part 192. Docket No. PHMSA–2011–0023.#

12024040NOA_Notice of Amendment_11122024_(23-276594)_text.pdf, page 2paragraph (a) of this section must include procedures for the following, if applicable, to provide safety during maintenance and operations. (1) Operating, maintaining, and repairing the pipeline in accordance with each of the requirements of this subpart and subpart M of this part. EQT’s written procedures for operating and maintaining its pipeline in accordance with requirements of Subpart L of 49 CFR Part 192 were inadequate to assure safe operation of a pipeline facility. Specifically, EQT failed to present adequate procedures for verification of material properties and attributes when traceable, verifiable, and complete (TVC) records are missing during maximum allowable operating pressure (MAOP) reconfirmation efforts in accordance with the requirements of § 192.607(c).3 3 § 192.607 Verification of Pipeline Material Properties and Attributes: Onshore steel transmission pipelines. (a) Applicability. Wherever required by this part, operators of onshore steel transmission pipelines must document and verify material properties and attributes in accordance with this section. (b) Documentation of material properties and attributes. Records established under this section documenting physical pipeline characteristics and attributes, including diameter, wall thickness, seam type, and grade (e.g., yield strength, ultimate tensile strength, or pressure rating for valves and flanges, etc.), must be maintained for the life of the pipeline and be traceable, verifiable, and complete. Charpy v-notch toughness values established under this section needed to meet the requirements of the ECA method at § 192.624(c)(3) or the fracture mechanics requirements at § 192.712 must be maintained for the life of the pipeline. (c) Verification of material properties and attributes. If an operator does not have traceable, verifiable, and complete records required by paragraph (b) of this section, the operator must develop and implement procedures for conducting nondestructive or destructive tests, examinations, and assessments in order to verify the material properties of aboveground line pipe and components, and of buried line pipe and components when excavations occur at the following opportunities: Anomaly direct examinations, in situ evaluations, repairs, remediations, maintenance, and excavations that are associated with replacements or relocations of pipeline segments that are removed from service. The procedures must also provide for the following: (1) For nondestructive tests, at each test location, material properties for minimum yield strength and ultimate tensile strength must be determined at a minimum of 5 places in at least 2 circumferential quadrants of the pipe for a minimum total of 10 test readings at each pipe cylinder location. (2) For destructive tests, at each test location, a set of material properties tests for minimum yield strength and ultimate tensile strength must be conducted on each test pipe cylinder removed from each location, in accordance with API Specification 5L. (3) Tests, examinations, and assessments must be appropriate for verifying the necessary material properties and attributes. (4) If toughness properties are not documented, the procedures must include accepted industry methods for verifying pipe material toughness. (5) Verification of material properties and attributes for non-line pipe components must comply with paragraph (f) of this section. (d) Special requirements for nondestructive Methods. Procedures developed in accordance with paragraph (c) of this section for verification of material properties and attributes using nondestructive methods must: (1) Use methods, tools, procedures, and techniques that have been validated by a subject matter expert based on comparison with destructive test results on material of comparable grade and vintage; (2) Conservatively account for measurement inaccuracy and uncertainty using reliable engineering tests and analyses; and (3) Use test equipment that has been properly calibrated for comparable test materials prior to usage. (e) Sampling multiple segments of pipe. To verify material properties and attributes for a population of multiple, comparable segments of pipe without traceable, verifiable, and complete records, an operator may use a sampling program in accordance with the following requirements:#

12024040NOA_Notice of Amendment_11122024_(23-276594)_text.pdf, page 3During the inspection, PHMSA reviewed EQT’s Operations and Maintenance Manual Revision 15, Effective 10/17/22 (O&M Manual), and EQT’s procedures titled Establishing Maximum Allowable Operating Pressure, Revision 2, Effective 10/3/2022 (MAOP-1); MAOP Reconfirmation, Revision 2, Effective 10/5/2022 (MAOP-2); TVC Recordkeeping, Revision 2, (1) The operator must define separate populations of similar segments of pipe for each combination of the following material properties and attributes: Nominal wall thicknesses, grade, manufacturing process, pipe manufacturing dates, and construction dates. If the dates between the manufacture or construction of the pipeline segments exceeds 2 years, those segments cannot be considered as the same vintage for the purpose of defining a population under this section. The total population mileage is the cumulative mileage of pipeline segments in the population. The pipeline segments need not be continuous. (2) For each population defined according to paragraph (e)(1) of this section, the operator must determine material properties at all excavations that expose the pipe associated with anomaly direct examinations, in situ evaluations, repairs, remediations, or maintenance, except for pipeline segments exposed during excavation activities pursuant to § 192.614, until completion of the lesser of the following: (i) One excavation per mile rounded up to the nearest whole number; or (ii) 150 excavations if the population is more than 150 miles. (3) Prior tests conducted for a single excavation according to the requirements of paragraph (c) of this section may be counted as one sample under the sampling requirements of this paragraph (e). (4) If the test results identify line pipe with properties that are not consistent with available information or existing expectations or assumed properties used for operations and maintenance in the past, the operator must establish an expanded sampling program. The expanded sampling program must use valid statistical bases designed to achieve at least a 95% confidence level that material properties used in the operation and maintenance of the pipeline are valid. The approach must address how the sampling plan will be expanded to address findings that reveal material properties that are not consistent with all available information or existing expectations or assumed material properties used for pipeline operations and maintenance in the past. Operators must notify PHMSA in advance of using an expanded sampling approach in accordance with § 192.18. (5) An operator may use an alternative statistical sampling approach that differs from the requirements specified in paragraph (e)(2) of this section. The alternative sampling program must use valid statistical bases designed to achieve at least a 95% confidence level that material properties used in the operation and maintenance of the pipeline are valid. The approach must address how the sampling plan will be expanded to address findings that reveal material properties that are not consistent with all available information or existing expectations or assumed material properties used for pipeline operations and maintenance in the past. Operators must notify PHMSA in advance of using an alternative sampling approach in accordance with § 192.18. (f) Components. For mainline pipeline components other than line pipe, an operator must develop and implement procedures in accordance with paragraph (c) of this section for establishing and documenting the ANSI rating or pressure rating (in accordance with ASME/ANSI B16.5 (incorporated by reference, see § 192.7)), (1) Operators are not required to test for the chemical and mechanical properties of components in compressor stations, meter stations, regulator stations, separators, river crossing headers, mainline valve assemblies, valve operator piping, or cross-connections with isolation valves from the mainline pipeline. (2) Verification of material properties is required for non-line pipe components, including valves, flanges, fittings, fabricated assemblies, and other pressure retaining components and appurtenances that are: (i) Larger than 2 inches in nominal outside diameter, (ii) Material grades of 42,000 psi (Grade X-42) or greater, or (iii) Appurtenances of any size that are directly installed on the pipeline and cannot be isolated from mainline pipeline pressures. (3) Procedures for establishing material properties of non-line pipe components must be based on the documented manufacturing specification for the components. If specifications are not known, usage of manufacturer's stamped, marked, or tagged material pressure ratings and material type may be used to establish pressure rating. Operators must document the method used to determine the pressure rating and the findings of that determination. (g) Uprating. The material properties determined from the destructive or nondestructive tests required by this section cannot be used to raise the grade or specification of the material, unless the original grade or specification is unknown and MAOP is based on an assumed yield strength of 24,000 psi in accordance with § 192.107(b)(2).#

12024040NOA_Notice of Amendment_11122024_(23-276594)_text.pdf, page 4Effective 10/5/2022 (MAOP-3); Verification of Pipeline Material Properties and Attributes, Revision 1, Effective 10/7/2022 (MAOP-4). PHMSA identified the following inadequacies in EQTs procedures: • EQT’s O&M Manual did not incorporate references to applicable procedures addressing § 192.607 (MAOP-1, MAOP-2, MAOP-3 and MAOP-4) presented during the inspection, including operator qualification requirements for personnel conducting material verifications as required by § 192.8014. The conduct of material verifications is a covered task under Part 192; • Section 5 of procedure MAOP-4 failed to include adequate procedures for verification of material properties and attributes when TVC records are missing during MAOP reconfirmation efforts. For example, EQT’s procedures did not address processes for attaining or establishing such records, including for how affected pipeline segments would be identified or scheduled for consideration opportunistically, or the dissemination of applicable requirements to relevant involved parties (e.g., communications between the EQT’s Pipeline Integrity Group and field personnel conducting activities required under § 192.607); • Section 5.2 of procedure MAOP-4 (Line Pipe Item 4) lacked adequate information addressing material verification via new non-destructive examination (NDE) technology readily available for attaining in-situ toughness properties, including any specifications or scope of work; • Section 5.2 of procedure MAOP-4 (Line Pipe Item 4) also lacked adequate information addressing material verification of NDE technology readily available for attaining in-situ yield strength and ultimate tensile strength (UTS), including any specifications or scope of work; and, • Section 6 of procedure MAOP-3 (Initial Procedure) and Appendix A – Acceptable Completion Matrix (Appendix A) address the requirement of MAOP reconfirmation and evaluation of TVC status when applicable. Appendix A serves as a guideline in determining the minimum amount and type of documentation required to support MAOP reconfirmation. During the inspection, numerous MAOP records were reviewed and the TVC records status was determined via utilization of Appendix A. However in several instances, it was discussed that material properties information (e.g., material grade) was captured from identical notes within field survey books and transposed across several project records, including alignment sheets. This process inflated the number of material grade reference records, and thus, prematurely considered the records as TVC without separate documentation (e.g. material test reports) per the requirements governing TVC records.5 4 § 192.801 Scope. (a) This subpart prescribes the minimum requirements for operator qualification of individuals performing covered tasks on a pipeline facility. (b) For the purpose of this subpart, a covered task is an activity, identified by the operator, that: (1) Is performed on a pipeline facility; (2) Is an operations or maintenance task; (3) Is performed as a requirement of this part; and (4) Affects the operation or integrity of the pipeline. 5 See 85 Fed. Reg. 52,180.#

12024040NOA_Notice of Amendment_11122024_(23-276594)_text.pdf, page 5Therefore, EQT’s written procedures required by § 192.605(b)(1) were inadequate. Equitrans must amend its written procedures to address the deficiencies noted above pertaining to the requirements of § 192.607. 2. § 192.605 Procedural manual for operations, maintenance, and emergencies. (a) … (b) Maintenance and normal operations. The manual required by paragraph (a) of this section must include procedures for the following, if applicable, to provide safety during maintenance and operations. (1) Operating, maintaining, and repairing the pipeline in accordance with each of the requirements of this subpart and subpart M of this part. Equitrans’ written procedures for operating and maintaining its pipeline in accordance with requirements of Subpart M of 49 CFR Part 192 were inadequate to assure safe operation of a pipeline facility. Specifically, EQT’s O&M Manual and its Integrity Management Plan Compliance (10/15/22) (IMP Compliance) procedure fail to adequately address the requirements of § 192.710.6 6 As in effect during the 2022-2023 PHMSA inspection: § 192.710 Transmission lines: Assessments outside of high consequence areas. (a) Applicability: This section applies to onshore steel transmission pipeline segments with a maximum allowable operating pressure of greater than or equal to 30% of the specified minimum yield strength and are located in: (1) A Class 3 or Class 4 location; or (2) A moderate consequence area as defined in § 192.3, if the pipeline segment can accommodate inspection by means of an instrumented inline inspection tool (i.e., “smart pig”). (3) This section does not apply to a pipeline segment located in a high consequence area as defined in § 192.903. (b) General — (1) Initial assessment. An operator must perform initial assessments in accordance with this section based on a risk- based prioritization schedule and complete initial assessment for all applicable pipeline segments no later than July 3, 2034, or as soon as practicable but not to exceed 10 years after the pipeline segment first meets the conditions of § 192.710(a) (e.g., due to a change in class location or the area becomes a moderate consequence area), whichever is later. (2) Periodic reassessment. An operator must perform periodic reassessments at least once every 10 years, with intervals not to exceed 126 months, or a shorter reassessment interval based upon the type of anomaly, operational, material, and environmental conditions found on the pipeline segment, or as necessary to ensure public safety. (3) Prior assessment. An operator may use a prior assessment conducted before July 1, 2020 as an initial assessment for the pipeline segment, if the assessment met the subpart O requirements of part 192 for in-line inspection at the time of the assessment. If an operator uses this prior assessment as its initial assessment, the operator must reassess the pipeline segment according to the reassessment interval specified in paragraph (b)(2) of this section calculated from the date of the prior assessment. (4) MAOP verification. An integrity assessment conducted in accordance with the requirements of § 192.624(c) for establishing MAOP may be used as an initial assessment or reassessment under this section. (c) Assessment method. The initial assessments and the reassessments required by paragraph (b) of this section must be capable of identifying anomalies and defects associated with each of the threats to which the pipeline segment is susceptible and must be performed using one or more of the following methods: (1) Internal inspection. Internal inspection tool or tools capable of detecting those threats to which the pipeline is susceptible, such as corrosion, deformation and mechanical damage (e.g., dents, gouges and grooves), material cracking and crack-like defects (e.g., stress corrosion cracking, selective seam weld corrosion, environmentally assisted cracking, and girth weld cracks), hard spots with cracking, and any other threats to which the covered segment is susceptible. When performing an assessment using an in-line inspection tool, an operator must comply#

12024040NOA_Notice of Amendment_11122024_(23-276594)_text.pdf, page 6During the inspection, PHMSA reviewed EQT’s O&M Manual and IMP Compliance procedures. PHMSA identified the following inadequacies: • EQT’s O&M Manual failed to incorporate references to applicable § 192.710 requirements residing within EQT’s IMP Compliance procedure; • EQT’s IMP Compliance procedure failed to adequately address how moderate consequence areas (MCAs) are initially and subsequently identified to support a proper initial and periodic assessment schedule under § 192.710(b). The assessment schedule produced during the inspection and utilized by EQT also requires management of change via a revision date to differentiate original MCA baseline segments as compared to newly added MCA segments; with § 192.493; (2) Pressure test. Pressure test conducted in accordance with subpart J of this part. The use of subpart J pressure testing is appropriate for threats such as internal corrosion, external corrosion, and other environmentally assisted corrosion mechanisms; manufacturing and related defect threats, including defective pipe and pipe seams; and stress corrosion cracking, selective seam weld corrosion, dents and other forms of mechanical damage; (3) Spike hydrostatic pressure test. A spike hydrostatic pressure test conducted in accordance with § 192.506. A spike hydrostatic pressure test is appropriate for time-dependent threats such as stress corrosion cracking; selective seam weld corrosion; manufacturing and related defects, including defective pipe and pipe seams; and other forms of defect or damage involving cracks or crack-like defects; (4) Direct examination. Excavation and in situ direct examination by means of visual examination, direct measurement, and recorded non-destructive examination results and data needed to assess all applicable threats. Based upon the threat assessed, examples of appropriate non-destructive examination methods include ultrasonic testing (UT), phased array ultrasonic testing (PAUT), Inverse Wave Field Extrapolation (IWEX), radiography, and magnetic particle inspection (MPI); (5) Guided Wave Ultrasonic Testing. Guided Wave Ultrasonic Testing (GWUT) as described in Appendix F; (6) Direct assessment. Direct assessment to address threats of external corrosion, internal corrosion, and stress corrosion cracking. The use of use of direct assessment to address threats of external corrosion, internal corrosion, and stress corrosion cracking is allowed only if appropriate for the threat and pipeline segment being assessed. Use of direct assessment for threats other than the threat for which the direct assessment method is suitable is not allowed. An operator must conduct the direct assessment in accordance with the requirements listed in § 192.923 and with the applicable requirements specified in §§ 192.925, 192.927 and 192.929; or (7) Other technology. Other technology that an operator demonstrates can provide an equivalent understanding of the condition of the line pipe for each of the threats to which the pipeline is susceptible. An operator must notify PHMSA in advance of using the other technology in accordance with § 192.18. (d) Data analysis. An operator must analyze and account for the data obtained from an assessment performed under paragraph (c) of this section to determine if a condition could adversely affect the safe operation of the pipeline using personnel qualified by knowledge, training, and experience. In addition, when analyzing inline inspection data, an operator must account for uncertainties in reported results (e.g., tool tolerance, detection threshold, probability of detection, probability of identification, sizing accuracy, conservative anomaly interaction criteria, location accuracy, anomaly findings, and unity chart plots or equivalent for determining uncertainties and verifying actual tool performance) in identifying and characterizing anomalies. (e) Discovery of condition. Discovery of a condition occurs when an operator has adequate information about a condition to determine that the condition presents a potential threat to the integrity of the pipeline. An operator must promptly, but no later than 180 days after conducting an integrity assessment, obtain sufficient information about a condition to make that determination, unless the operator demonstrates that 180 days is impracticable. (f) Remediation. An operator must comply with the requirements in §§ 192.485, 192.711, and 192.713, where applicable, if a condition that could adversely affect the safe operation of a pipeline is discovered. (g) Analysis of information. An operator must analyze and account for all available relevant information about a pipeline in complying with the requirements in paragraphs (a) through (f) of this section.#

12024040NOA_Notice of Amendment_11122024_(23-276594)_text.pdf, page 7• EQT’s IMP Compliance procedure (Section 14.10, Assessments Outside of High Consequence Area (§ 192.710)) lacks a process which exemplifies the application of a formal risk-based prioritization schedule as prescribed by § 192.710(b)(1) for segments outside of high consequence areas (HCAs) other than elective assessments, and an Interstate Natural Gas Association of America initiative that is based upon population density within respective potential impact radius (PIR); • EQT’s IMP Compliance procedure (Section 14.10.2) addresses § 192.710 requirements governing periodic reassessment intervals every 10 years, not to exceed 126-months. However, the procedures governing analysis of whether shorter intervals are necessary based upon previous assessment results as prescribed in § 192.710(b)(2) is inadequate. For example, the reference to Section 5.6 depicts shorter intervals for integrity management segments based on predicted failure pressures per ASME B31G. However, the procedure is unclear if the same process is to be utilized for pipeline segments addressed by the requirements of § 192.710; • EQT’s IMP Compliance procedures were inadequate with regard to identification of segments that will be covered under those procedures as compared to any remaining segments, and also does not address tool selection or other methods of assessment as addressed by § 192.710(c)(1). During the inspection, EQT indicated its IMP Compliance procedure is followed for segments addressed by § 192.710. However, a review of documents, including tool selection for pipeline segment H-125, which is governed by the requirements of § 192.710, indicates the IMP Compliance procedure was not applied to that segment. Therefore, EQT’s procedures required by § 192.605(b)(1) were inadequate to address the requirements of § 192.710. EQT must amend its written procedures to address the deficiencies noted above. 3. § 192.605 Procedural manual for operations, maintenance, and emergencies. (a) … (b) Maintenance and normal operations. The manual required by paragraph (a) of this section must include procedures for the following, if applicable, to provide safety during maintenance and operations. (1) Operating, maintaining, and repairing the pipeline in accordance with each of the requirements of this subpart and subpart M of this part. EQT’s written procedures for operating and maintaining its pipeline in accordance with requirements of Subpart L of 49 CFR Part 192 were inadequate to assure safe operation of a pipeline facility. Specifically, Equitrans’ procedures addressing § 192.613 were inadequate. Section 192.613(a) states, in part, that “[e]ach operator shall have a procedure for continuing surveillance of its facilities…” The requirement for continuing surveillance applies to the entire pipeline facility, including non-covered pipeline segments not subject to the requirements of Subpart O of Part 192 (addressing gas transmission pipeline integrity management (IMP)). The#

12024040NOA_Notice of Amendment_11122024_(23-276594)_text.pdf, page 8procedures required by § 192.605(e)7, which includes surveillance, must also be included within the manual of written procedures for conducting operations and maintenance activities. During the inspection, PHMSA reviewed EQT’s O&M Manual Section 6.1 (Continuing Surveillance). However, Section 6.1 appeared to be solely applicable to covered segments within EQT’s IMP via reference specifically explaining that issues such as “[l]eakage history, corrosion, and substantial changes in cathodic protection requirements are reviewed as part of the Integrity Management Program. The Integrity Management Program addresses the appropriate actions for each of these potential issues”. During the inspection, PHMSA also noted a lack of specific procedures within the O&M Manual, or specific references to other documents for the continuing surveillance of its pipeline facilities, addressing determination of and appropriate actions addressing changes in class location, failures, leakage history, corrosion, substantial changes in cathodic protection requirements, and other unusual operating and maintenance conditions. The O&M Manual also does not address relevant applicable roles, responsibilities or timeframes to manage MCAs or class locations once changes to population density or other unusual operations and maintenance conditions are identified or occur. Therefore, EQT’s procedures required by § 192.605(b)(1) were inadequate to address the requirements of § 192.613 and subpart L of Part 192. EQT must amend its written procedures to address the deficiencies noted above. 4. § 192.605 Procedural manual for operations, maintenance, and emergencies. (a) … (b) Maintenance and normal operations. The manual required by paragraph (a) of this section must include procedures for the following, if applicable, to provide safety during maintenance and operations. (1) Operating, maintaining, and repairing the pipeline in accordance with each of the requirements of this subpart and subpart M of this part. EQT’s written procedures for operating and maintaining its pipeline in accordance with requirements of Subpart L of 49 CFR Part 192 were inadequate to assure safe operation of a pipeline facility. Specifically, EQT’s procedures for complying with § 192.611(d)8 were inadequate. 7 § 192.605 Procedural manual for operations, maintenance, and emergencies. (a) . . . (e) Surveillance, emergency response, and accident investigation. The procedures required by §§ 192.613(a), 192.615, and 192.617 must be included in the manual required by paragraph (a) of this section. 8 §192.611 Change in class location: Confirmation or revision of maximum allowable operating pressure. (a) … (d) Confirmation or revision of the maximum allowable operating pressure that is required as a result of a study under §192.609 must be completed within 24 months of the change in class location. Pressure reduction under paragraph (a) (1) or (2) of this section within the 24-month period does not preclude establishing a maximum allowable operating pressure under paragraph (a)(3) of this section at a later date.#

12024040NOA_Notice of Amendment_11122024_(23-276594)_text.pdf, page 9During the inspection, PHMSA reviewed EQT’s O&M Manual, Section 7.1, addressing class location determination in accordance with § 192.611. The following inadequacies were identified: • EQT’s procedures did not address process(es) for instances where current MAOP may not be in accordance with requirements for an existing Class location; • EQT’s procedures did not address the process for actions from identification to resolution that shall be taken in order to satisfy the specified 24-month timeline requirement of § 192.611(d); and, • EQT’s procedures did not address roles, responsibilities or applicable timeframes to manage class location changes once changes to population density, PIR, and/or identified sites that are identified or occur. Therefore, EQT’s procedures required by § 192.605(b)(1) were inadequate in addressing the requirements of§ 192.611. EQT must amend its written procedures to address the deficiencies noted above. Response to this Notice This Notice is provided pursuant to 49 U.S.C. § 60108(a) and 49 C.F.R. § 190.206. Enclosed as part of this Notice is a document entitled Response Options for Pipeline Operators in Enforcement Proceedings. Please refer to this document and note the response options. 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). Following the receipt of this Notice, you have 30 days to submit written comments, revised procedures, or a request for a hearing under § 190.211. If you do not respond within 30 days of receipt of this Notice, this constitutes a waiver of your right to contest the allegations in this Notice and authorizes the Associate Administrator for Pipeline Safety to find facts as alleged in this Notice without further notice to you and to issue an Order Directing Amendment. If your plans or procedures are found inadequate as alleged in this Notice, you may be ordered to amend your plans or procedures to correct the inadequacies (49 C.F.R. § 190.206). If you are not contesting this Notice, we propose that you submit your amended procedures to my office within 30 days of receipt of this Notice. This period may be extended by written request for good cause. Once the inadequacies identified herein have been addressed in your amended procedures, this enforcement action will be closed. It is requested (not mandated) that EQT maintain documentation of the safety improvement costs associated with fulfilling this Notice of Amendment (preparation/revision of plans, procedures) and submit the total to Robert Burrough, Director, Eastern Region, Pipeline and Hazardous Materials Safety Administration. In correspondence concerning this matter, please refer to CPF 1-#

12024040NOA_Notice of Amendment_11122024_(23-276594)_text.pdf, page 102024-040-NOA and, for each document you submit, please provide a copy in electronic format whenever possible. Sincerely, Robert Burrough Director, Eastern Region Pipeline and Hazardous Materials Safety Administration Enclosure: Response Options for Pipeline Operators in Enforcement Proceedings#

12024040NOA_Closure Letter_05132025_(23-276594)_text.pdf, page 1Official PDFVIA ELECTRONIC MAIL TO: justin.trettel@eqt.com May 13, 2025 Mr. Justin Trettel Senior Vice President EQT Production Company 2200 Energy Drive Canonsburg, Pennsylvania 15317 CPF 1-2024-040-NOA Dear Mr. Trettel: On October 31, 2022, through March 27, 2023, representatives of the Pipeline and Hazardous Materials Safety Administration (PHMSA) pursuant to Chapter 601 of 49 United States Code (U.S.C.) conducted an inspection of EQT Production Company (EQT) procedures in Canonsburg, PA. As a result of the inspection, EQT was issued a Notice of Amendment on November 12, 2024, to amend certain aspects of its procedures. On December 3, 2024, EQT requested an extension until January 31, 2025, which PHMSA granted. EQT timely submitted its amended procedures on January 31, 2025. My staff reviewed the amended procedures, and it appears that the inadequacies outlined in this Notice of Amendment have been corrected. This letter is to inform you no further action is necessary and this case is now closed. Thank you for your cooperation. Sincerely, Robert Burrough Director, Eastern Region Pipeline and Hazardous Materials Safety Administration#