NYSE: SOC

On February 14, 2024 (the “Closing Date”), Sable consummated the mergers and related transactions contemplated by the Merger Agreement (the “Business Combination”), following which Flame was renamed “Sable Offshore Corp.” Pursuant to the terms and subject to the conditions set forth in the Sable-EM Purchase Agreement, the transactions contemplated by the Sable-EM Purchase Agreement were also consummated on February 14, 2024, immediately after the Closing, as a result of which Sable purchased the SYU Assets, effective as of January 1, 2022. On February 15, 2024, Sable’s shares of Common Stock, par value $0.0001 per share (“Common Stock”) and warrants to purchase Common Stock at an exercise price of $11.50 per share (the “Public Warrants”) began trading on NYSE under the symbols, “SOC” and “SOC.WS,” respectively.

Since the Closing Date, we have invested significant capital to safely restore production operations to SYU.

Unless otherwise noted or the context otherwise requires, references to (i) the “Company,” “Sable,” “we,” “us,” or “our” are to Sable Offshore Corp, a Delaware corporation, and its consolidated subsidiaries, following the Business Combination, (ii) “Flame” refers to Flame Acquisition Corp. prior to the Business Combination, (iii) the “Santa Ynez Unit” or “SYU” refers to the 16 federal leases, three offshore production platforms (Hondo, Harmony, and Heritage), and associated ancillary facilities located in federal waters offshore California, and (iv) the “Santa Ynez Pipeline System” (or “SYPS”) refers to the interstate pipeline connecting the Santa Ynez Unit to the Pentland Station terminal, inclusive of “Pipeline Segment 324” and “Pipeline Segment 325”, or collectively referred to as “Pipeline Segments 324 and 325” (formerly known as “901/903 Assets” and as defined in the Sable-EM Purchase Agreement), the Las Flores Canyon (“LFC”) onshore processing, storage, and related pipeline assets, and the offshore pipeline connecting the Santa Ynez Unit to LFC. The SYU Assets include the Santa Ynez Unit and the Santa Ynez Pipeline System.

Production Restart

Beginning in 1968 and over the course of 14 years, EM consolidated more than a dozen offshore federal oil leases and organized them into a streamlined production unit known as the SYU. The SYU remained in continuous operation until 2015. In May 2015, Pipeline Segment 324 (then known as “Line 901”) experienced a leak while operated by Plains All American Pipeline, L.P. (“Plains”), as further described below under “—Pipeline 901 Incident.” The SYU suspended production after the Line 901 incident and the facilities were maintained in a safe state.

On May 19, 2025, the Company announced that as of May 15, 2025, it had restarted production at the SYU and begun flowing oil production from six wells at SYU’s Platform Harmony to the Company’s storage and processing facilities at LFC.

Prior to May 15, 2025, the SYU had not produced oil and gas since May 2015; however, all equipment remained in place in an operation-ready state, requiring ongoing inspections, maintenance and surveillance. As part of these efforts, all equipment was drained, flushed and purged in 2016. The Santa Ynez Pipeline System was maintained in a safe state and

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regularly monitored. In 2020, Plains entered into a Consent Decree, described further below under “—Pipeline 901 Incident,” that provides a path for resuming petroleum transportation through Pipeline Segments 324 and 325, which have been maintained in an active state.

Since the Closing Date, the Company has invested significant capital to safely restore production operations to the SYU. The future operating and financial performance of the Company is expected to be driven primarily by our ability to establish a lawful, reliable, and economic pathway to market crude oil and natural gas produced from the SYU, resume sustained offshore production, and manage regulatory, legal, and commodity price risks associated with its federal offshore and California onshore and offshore assets.

Sable was deemed the accounting acquirer in the Business Combination based on an analysis of the criteria outlined in Accounting Standards Codification 805, Business Combinations, with such transactions being accounted for as a forward merger, and the SYU was deemed the predecessor entity for accounting purposes.

SYU Assets

The offshore position is comprised of 16 federal leases across approximately 76,000 acres and includes 100% working interest with an average 83.6% net revenue interest. The Hondo platform and the Harmony platform develop the Hondo Field, and the Heritage platform develops the Pescado and Sacate Fields. The platforms are located 5 to 9 miles offshore of Santa Barbara County in shallow water depths of 900 to 1,200 feet and service 112 wells, comprised of 90 producers, 12 injectors and 10 idle with an additional 102 identified, undrilled opportunities. A 2015 analysis identified step-out potential for untested fault compartments or sub-accumulations and indicated a potential technical opportunity for up to an additional 102 identified, undrilled opportunities based on spacing assumptions ranging from 20 to 80 acres. For each platform, more opportunities exist than there are available donor wellbores based on current spacing assumptions (i.e., each platform is slot-constrained).

From the offshore platforms in the Outer Continental Shelf (“OCS”), crude oil is transported through the Santa Ynez Pipeline System to onshore processing and storage facilities. The wholly owned onshore processing facility is a fully integrated oil and gas processing facility with additional capacity for development. The onshore position is approximately 1,480 surface acres, which include the processing facility and parts of the surrounding canyons. The onshore facilities occupy approximately 35 acres and are comprised of:

•an oil treating plant with capacity of approximately 180 MBop/d where it conducts crude dehydration, crude stabilization, and gas separation and compression;

•a biologic/physical water treating plant with capacity of more than 67 MBwp/d where it conducts free oil removal, degassing, and biological treatment;

•a Pacific Offshore Pipeline Company (“POPCO”) gas plant with approximately 80 MMcf/d sales capacity where it conducts gas sweetening, sulfur recovery, natural gas liquids (“NGL”) fractionation, and gas compression (the “POPCO Facility”);

•another gas processing plant where it conducts gas sweetening, sulfur recovery, and NGL fractionation, and sends fuel gas to the co-generation power plant;

•an almost entirely electric co-generation power plant with a capacity of 50 MW, including a 40 MW gas turbine, a 10 MW steam turbine, and steam generation;

•crude storage capacity of 540 MBbls;

•a produced water pipeline, which is partially offshore;

•liquified petroleum gas storage and loading; and

•a transportation terminal.

Pipeline Segments 324 and 325 and the other 324/325 Assets acquired in the Business Combination, were owned and operated by Plains and were acquired by EM on October 13, 2022. Pipeline Segments 324 and 325 were used to deliver oil to local refinery markets from the onshore processing and storage facilities. Following a crude oil release in May 2015, Plains indicated it suspended petroleum transportation activities through Pipeline Segments 324 and 325, initiated its emergency response plan, and Pipeline Segments 324 and 325 were subsequently emptied of hydrocarbons but filled with an inert gas and maintained in a safe state.

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We operate the Santa Ynez Pipeline System’s onshore processing and storage facilities and pipeline facilities, including the offshore pipeline facilities and Pipeline Segments 324 and 325, as a single pipeline system transporting crude oil from the SYU in the OCS to the Pentland Station terminal in Kern County, California. Pipeline Segment 324 (formerly known as Line 901) is a 24-inch, approximately 10.8 mile long crude oil pipeline that extends from the Las Flores Station on the California Coast to the Gaviota Pump Station in Santa Barbara County, California. Pipeline Segment 325 (formerly known as Line 903) is a 30-inch, approximately 113 mile long crude oil pipeline that extends from the Gaviota Pump Station in Santa Barbara County, California to the 30-inch pig receiver located in Pentland Station in Kern County, California with an intermediate station at Sisquoc mile post 38.5 in San Luis Obispo, California.

SYU Production History

Between 1981 and 2014, the SYU produced over 671 MMBoe of oil and gas. An average of 27 MMcf of natural gas and 29 MBbls of oil and condensate was produced per day (gross) in 2014, the last full year when the assets were online. After the Line 901 incident, the SYU suspended production, and the facilities were maintained in a safe, operation-ready state as described below under “ —Pipeline 901 Incident.”

During the year ended December 31, 2025, the Company successfully produced barrels of crude oil from the SYU, reflecting the initial resumption and ramp-up of operations efforts following an extended period of non-production, with activities focused on asset integrity, regulatory compliance, and the phased return of offshore and onshore facilities to full service. As a result, production volumes for 2025 were limited and are not indicative of expected future production levels once petroleum transportation through Pipeline Segments 324 and 325 is resumed and sustained operations commence.

SYU Contingent Resources

The estimated quantities of petroleum contained in the SYU Assets are classified as “contingent resources” as of December 31, 2025 rather than “reserves” because they are subject to numerous contingencies. There is no assurance that any of the petroleum contained in the SYU Assets will ever be recovered or reclassified as “reserves.”

The resources are contingent upon (1) reestablishment of oil transportation systems to deliver production to market and (2) commitment to restart the remaining wells and facilities. Some or all of the contingent resources may be reclassified as “reserves” if all of the contingencies are successfully resolved but there is no assurance that the contingencies will be resolved or resolved in a timely manner or that any of the petroleum in the SYU Assets will be recovered.

As a result of the contingencies noted above, none of the estimated petroleum quantities attributed to the SYU Assets as of December 31, 2025 meet the requirements for disclosure as reserves pursuant to the guidelines published by the SEC in Rule 4-10(a) of Regulation S-X.

Pipeline 901 Incident

In May 2015, Plains experienced a crude oil release from the Pipeline Segment 324 (then known as “Line 901”) in Santa Barbara County, California (the “Line 901 incident”). According to Plains, a portion of the released crude oil reached the Pacific Ocean at Refugio State Beach through a drainage culvert. Following the release, Plains indicates that it ceased flowing oil through the pipeline segment and initiated its emergency response plan. A Unified Command, which included the U.S. Coast Guard, the Environmental Protection Agency (“EPA”), the State of California Department of Fish and Wildlife (“CDFW”), the California Office of Spill Prevention and Response and the Santa Barbara Office of Emergency Management, was established for the response effort. Clean-up and remediation operations with respect to impacted shoreline and other areas has been determined by the Unified Command to be complete, and the Unified Command has been dissolved. Plains’ estimate of the amount of oil spilled, based on relevant facts, data and information, and as set forth in the Consent Decree described below, is approximately 2,934 barrels; of this amount, Plains estimated that 598 barrels reached the Pacific Ocean.

Several governmental agencies and regulators initiated investigations into the Line 901 incident, various claims were made against Plains and a number of lawsuits were filed against Plains, the majority of which Plains indicates have been resolved.

Following the Line 901 incident, Plains entered into a cooperative Natural Resource Damage Assessment (“NRDA”) process with the federal and state agencies designated or authorized by law to act as trustees for the natural resources of the United States and the State of California (collectively, the “Trustees”). Additionally, various government agencies sought to collect civil fines and penalties from Plains under applicable state and federal regulations. On March 13, 2020, Plains entered into a pre-negotiated settlement agreement in the form of a Consent Decree (the “Consent Decree”) with the U.S. Department of Justice, Environmental and Natural Resources Division, the U.S. Department of Transportation, Pipeline

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and Hazardous Materials Safety Administration (“PHMSA”), the EPA, CDFW, the California Department of Parks and Recreation (“State Parks”), the California State Lands Commission (“SLC”), the California Department of Forestry and Fire Protection’s Office of the State Fire Marshal (“OSFM”), Central Coast Regional Water Quality Control Board (“Regional Board”), and Regents of the University of California. The Consent Decree was approved and entered by the Federal District Court for the Central District of California on October 14, 2020. The Consent Decree resolved all regulatory claims related to the incident and Plains was required to pay various civil penalties and compensation related to the Line 901 incident. The Consent Decree also contains requirements for resuming petroleum transportation through Pipeline Segments 324 and 325.

On October 13, 2022, Plains sold Pipeline Segments 324 and 325 to Pacific Pipeline Company (“PPC”). As required by the terms of the Consent Decree, PPC assumed responsibility for compliance with the Consent Decree as it relates to the future ownership and operation of Pipeline Segments 324 and 325.

The EM-Plains Purchase Agreement requires Plains to indemnify EM against certain liabilities directly arising out of or directly relating to the oil spilled from Line 901 and the subsequent clean up and remediation. The Sable-EM Purchase Agreement requires EM to indemnify Sable against certain liabilities associated with the Line 901 incident prior to January 1, 2022 and for a period of two years following the closing under the Sable-EM Purchase Agreement.

Resuming Transportation through Pipeline Segments 324 and 325 of the Santa Ynez Pipeline System

Resuming transportation of oil through Pipeline Segments 324 and 325 of the Santa Ynez Pipeline System requires certain regulatory approvals and other actions that may implicate federal, state, and local regulations.

PHMSA Restart Plan Approval

On December 17, 2025, PHMSA confirmed that the Santa Ynez Pipeline System is classified as an active interstate pipeline subject to federal jurisdiction under the Pipeline Safety Act. On December 22, 2025, PHMSA notified the Company that PHMSA had approved the Company’s Restart Plan (as defined below) for Pipeline Segments 324 and 325 after reviewing extensive documentation provided by Sable to PHMSA and conducting a multi-day field inspection. On December 23, 2025, the Company received an Emergency Special Permit from PHMSA related to cathodic protection and seam weld corrosion along Pipeline Segments 324 and 325. This permit requires ongoing compliance with specified operational and reporting obligations, including enhanced integrity management, inspection, testing, and monitoring requirements. The Emergency Special Permit expired on February 21, 2026. By letter dated February 13, 2026 to PHMSA, the Company committed to continued compliance with the conditions of the emergency special permit until PHMSA makes a determination on the Company’s application for Special Permit (which was submitted on January 22, 2026).

On December 31, 2025, the U.S. Court of Appeals for the Ninth Circuit denied a motion to stay PHMSA’s approvals of the Company’s Restart Plan and Emergency Special Permit, allowing those approvals to remain in effect during the pendency of the appeal. While the appeal remains ongoing, the Company may continue to advance activities related to resuming petroleum transportation through Pipeline Segments 324 and 325, subject to satisfaction of all applicable regulatory, operational, and commercial requirements.

On January 23, 2026, a second petition was filed in the U.S. Court of Appeals for the Ninth Circuit by the State of California, also against the U.S. Department of Transportation; Sean Duffy, in his official capacity as Secretary of the U.S. Department of Transportation; PHMSA; and Paul Roberti, in his official capacity as Administrator of PHMSA. The second petition, filed by the State of California, Attorney General and OSFM, challenges the Emergency Special Permit, but also challenges PHMSA’s assertion of jurisdiction over the Santa Ynez Pipeline System. The two petitions have been consolidated and Sable is participating in the consolidated matter.

The Company cannot generate material oil sales without a functioning transportation solution. As a result, any delay, suspension, or revocation of PHMSA’s approvals, or any operational issue encountered during resuming petroleum transportation through Pipeline Segments 324 and 325, could materially delay the resumption of commercial oil sales and adversely affect future revenues and cash flows.

Repair and Maintenance Work and Resuming Petroleum Transportation through Santa Ynez Pipeline Segments 324 and 325

Federal regulations require Sable to promptly “evaluate all anomalous [pipeline] conditions and remediate those that could reduce a pipeline’s integrity.” A Consent Decree that was entered into by Plains and various government agencies in 2020 requires Plains, and, by contract, Sable, to comply with this and other applicable regulatory requirements related to pipeline safety at heightened standards. In addition, Sable was required to comply with California Assembly Bill 864’s

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requirements to install certain safety valves along Pipeline Segments 324 and 325 of the Santa Ynez Pipeline System in Santa Barbara County (the “County”). Accordingly, Sable has undertaken and completed required pipeline repair activities for both Pipeline Segments 324 and 325, and the installation of the sixteen safety valves required under the approved 2021 Coastal Best Available Technology Plan.

On December 17, 2024, OSFM approved Sable’s implementation of enhanced pipeline integrity standards for Pipeline Segments 324 and 325 by granting state waivers of certain regulatory requirements (“State Waivers”) related to cathodic protection and seam weld corrosion for the Pipeline Segments 324 and 325. On February 11, 2025, the PHMSA notified OSFM that PHMSA did not object to OSFM’s granting of the State Waivers.

Two lawsuits were filed against OSFM (as Defendant) and Sable and PPC (as Real Parties in Interest) challenging OSFM’s issuance of the State Waivers. On April 15, 2025, the Center for Biological Diversity and the Wishtoyo Foundation filed a Verified Petition for Writ of Mandate and Complaint for Declaratory and Injunctive Relief alleging that OSFM violated federal and state pipeline safety laws and the California Environmental Quality Act (“CEQA”) in issuing the State Waivers (Case No. 25CV02244). The Environmental Defense Center, Get Oil Out!, Santa Barbara County Action Network, Sierra Club, and Santa Barbara Channelkeeper also filed a Verified Petition for Writ of Mandate and Complaint for Declaratory and Injunctive Relief against OSFM (as Defendant) and Sable and PPC (as Real Parties in Interest) alleging similar claims (Case No. 25CV02247). Both groups of Petitioners seek a court order declaring the State Waivers void and directing OSFM to vacate and set aside the State Waivers until OSFM complies with its obligations under federal and state pipeline safety laws and CEQA.

On May 15, 2025, Sable restarted oil production from six wells on Platform Harmony at SYU and began flowing oil production through the Santa Ynez Pipeline System to the System’s onshore processing and storage facilities at LFC at an initial rate of approximately 6,000 barrels of oil per day.

On May 18, 2025, Sable completed anomaly repairs on Pipeline Segment 324 (formerly known as Line 901), which extends from LFC, on the California coast to the Gaviota Pump Station in Santa Barbara County, California, and Pipeline Segment 325 (formerly known as Line 903), which extends from the Gaviota Pump Station to Pentland Station in Kern County, California, the point of sale. With the completion of such repairs, Sable has completed its anomaly repair program on Pipeline Segments 324 and 325 as specified by the Consent Decree.

The Consent Decree requires the approval of restart plans for each of Pipeline Segments 324 and 325 (the “Restart Plan”) prior to resuming petroleum transportation through the Segments. The Consent Decree prescribes what must be submitted in the Restart Plans. On July 29, 2024, PPC submitted the Restart Plans to OSFM for approval. As of May 27, 2025, Sable conducted successful hydrotests on all sections of Pipeline Segments 324 and 325.

A hearing was held in the State Waivers litigation on July 18, 2025, and on July 29, 2025, the court entered an order granting petitioners’ application for issuance of preliminary injunction in part, ruling that, absent further order of the court, Sable may resume petroleum transportation through the Pipeline Segments 324 and 325 10 court days after Sable files notice that Sable has received all necessary approvals and permits for such resumption. The court clarified that Sable is not prevented from taking steps toward resuming petroleum transportation through Pipeline Segments 324 and 325, and that OSFM is not prevented from taking steps it finds appropriate in its regulatory capacity with respect to Sable’s Restart Plans as contemplated by the federal Consent Decree.

On October 22, 2025, OSFM sent a letter to Sable alleging deficiencies in the Company’s compliance with the State Waivers. Sable strongly disagrees with the allegations, which are inconsistent with the plain language and numerous discussions with OSFM experts confirming that Sable was in compliance with the State Waivers. Sable responded to OSFM’s letter on October 23, 2025, setting forth the Company’s objections to OSFM’s new interpretation of the State Waiver conditions.

On November 26, 2025, the Company notified PHMSA of its determination that the Santa Ynez Pipeline System, including Pipeline Segments 324 and 325, constitutes an interstate pipeline facility under the Pipeline Safety Act (“PSA”), and requested that PHMSA exercise regulatory oversight over the Santa Ynez Pipeline System and transition oversight from OSFM. On December 17, 2025, PHMSA issued a letter to the Company concurring in its determination that the Santa Ynez Pipeline System is an interstate pipeline under the PSA, and informed the Company that “PHMSA is notifying OSFM that [Pipeline Segments 324 and 325 are] subject to the regulatory oversight of PHMSA.” On December 22, 2025, PHMSA notified the Company that PHMSA had approved the Company’s Restart Plan for Pipeline Segments 324 and 325 after reviewing extensive documentation provided by Sable to PHMSA and conducting a multi-day field inspection. On December 23, 2025, PHMSA issued an Emergency Special Permit to the Company related to cathodic protection and seam weld corrosion along Pipeline Segments 324 and 325. The emergency special permit expired on February 21, 2026.

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On December 24, 2025, in the U.S. Court of Appeals for the Ninth Circuit, the Environmental Defense Center, Get Oil Out!, Santa Barbara County Action Network, Santa Barbara Channelkeeper, the Center for Biological Diversity, and the Wishtoyo Foundation (as Petitioners) filed a Petition for Review and Emergency Motion to Stay with respect to PHMSA’s approval of the Company’s Restart Plan and issuance of the Emergency Special Permit (Case No. 25-8059) (the “PHMSA Litigation”). The Petitioners named the U.S. Department of Transportation and PHMSA and their respective heads as Respondents. On December 25, 2025, the Company and PPC filed an Emergency Motion for Leave to Intervene in the PHMSA Litigation. Both the U.S. government entities and the Company parties opposed the stay request. On December 31, 2025, the Ninth Circuit Court of Appeals granted the Company’s Motion for Leave to Intervene and denied the Petitioners’ Motion to Stay PHMSA’s approval of the Company’s Restart Plan and issuance of the Emergency Special Permit. The Court also granted expedited review of the Petition.

On January 23, 2026, a second petition was filed in the U.S. Court of Appeals for the Ninth Circuit by the State of California, also against the U.S. Department of Transportation; Sean Duffy, in his official capacity as Secretary of the U.S. Department of Transportation; PHMSA; and Paul Roberti, in his official capacity as Administrator of PHMSA. The second petition, filed by the State of California, Attorney General and OSFM, challenges the Emergency Special Permit, but also challenges PHMSA’s assertion of jurisdiction over the Santa Ynez Pipeline System. The two petitions have been consolidated and Sable is participating in the consolidated matter. Sable intends to defend the cases vigorously.

Petitioners’ Opening Brief in the consolidated matter is due on March 23, 2026. On January 5, 2026, the Company filed a Motion for Reconsideration of the Preliminary Injunction in the State Waivers litigation. The Motion requested that the preliminary injunction be rescinded as moot given PHMSA’s determination and exercise of regulatory oversight for Pipeline Segments 324 and 325. On February 26, 2026, the Company notified OSFM that, effective immediately, it had “relinquishe[d], surrender[ed] and abandon[ed] the State Waivers” given PHMSA’s determination and exercise of regulatory oversight for Pipeline Segments 324 and 325. On February 27, 2026, the Santa Barbara County Superior Court denied the Company’s Motion for Reconsideration of the Preliminary Injunction. Sable and PPC intend to continue to defend both cases vigorously.

On January 14, 2026, the Company submitted a letter to the United States Department of Justice Environment and Natural Resources Division and the California Office of the Attorney General Natural Resources Law Section regarding the termination of the Consent Decree because the prerequisites for termination have been satisfied.

California Coastal Commission

On September 27, 2024, the California Coastal Commission (the “Coastal Commission”) issued Notice of Violation No. V-9-24-0152 to Sable, which asserted that Sable’s safety valve installation work and certain maintenance and repair activities undertaken by Sable on Pipeline Segments 324 and 325 in the California coastal zone (the “Coastal Zone”) to address anomalies and install safety valves constituted unpermitted development activities under the California Coastal Act (Cal. Pub. Res. Code Section 30000, et seq.) (the “Coastal Act”) and the County’s Local Coastal Program (“LCP”). Sable undertook the subject repair and maintenance work, including the safety valve installation work, based on its understanding that no new coastal development permit or other Coastal Act authorization was required, consistent with the County’s practice of authorizing repair work on Pipeline Segments 324 and 325 since they were first permitted and built over 30 years ago. Following good faith negotiations with Coastal Commission staff, on November 12, 2024, the Coastal Commission issued Executive Director Cease and Desist Order No. ED-24-CD-02 (the “Order”) requiring Sable to, among other requirements, prepare and submit an interim restoration plan and submit an application either to the Coastal Commission or the County to obtain a coastal development permit for the valve installation and other maintenance and repair work. In compliance with the Order, Sable prepared, submitted, and implemented the Interim Restoration Plan as approved by Coastal Commission staff. Sable separately submitted certain applications to the County related to some of the maintenance and repair work that was subject to Notice of Violation No. V-9-24-0152. The Order expired on February 10, 2025.

On February 11, 2025, the Coastal Commission issued Notice of Violation No. V-9-25-0013 to Sable, which asserted that certain maintenance and repair activities on the offshore pipeline segments of the Santa Ynez Pipeline System in the Coastal Zone constituted unpermitted development activities under the Coastal Act. Sable undertook the subject maintenance and repair activities based on its understanding that no new coastal development permit or other Coastal Act authorization was required for such work, consistent with similar work that previously had been performed along the offshore pipeline segments of the Santa Ynez Pipeline System by prior operators.

On February 12, 2025, the County delivered a letter to Sable confirming that certain anomaly maintenance and repair work on Pipeline Segments 324 and 325, referenced in the Coastal Commission’s Notice of Violation V-9-24-0152, was “authorized by the existing permits (Final Development Plan, Major Conditional Use Permit, and associated Coastal

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Development Permits) and was analyzed in the prior Environmental Impact Report/Environmental Impact Statement (EIR/EIS).” The letter states in part that “[t]he County previously exercised its authority under its Local Coastal Program and delegated Coastal Act authority in approving the permits and the requested anomaly repair work is within the scope of those approved permits.” Sable subsequently recommenced the repair and maintenance activities which were subject to Notice of Violation V-9-24-0152.

In addition, also on February 12, 2025, the County delivered a letter to the Coastal Commission. In this letter, the County responded to a request by the Coastal Commission to consent to a consolidated coastal development permit process for certain activities undertaken and planned by Sable on the Santa Ynez Pipeline System. The County’s letter also stated that certain maintenance and repair work on Pipeline Segments 324 and 325 that was referenced in the Coastal Commission’s Notice of Violation V-9-24-0152 is “authorized by the existing permits (Final Development Plan, Major Conditional Use Permit, and associated Coastal Development Permits) and was analyzed in the prior Environmental Impact Report/Environmental Impact Statement. Thus, no further application to or action by the County is required.”

On February 14, 2025, Sable submitted a written response to the Coastal Commission’s Notice of Violation V-9-24-0152 detailing that, consistent with the County’s letters, certain of the alleged unpermitted development activities subject to the Notice of Violation were previously approved and that no further coastal development permit was required.

On February 18, 2025, Sable filed a complaint against the Coastal Commission in the Superior Court of the State of California for the County of Santa Barbara (Case No. 25CV00974). In the complaint, Sable challenges the Coastal Commission’s prior Notices of Violations and Executive Director Cease and Desist Order as procedurally improper and asserts that the Coastal Commission lacks authority to prohibit work authorized by existing permits. Sable seeks a declaration that the Coastal Commission’s actions are unlawful, an injunction prohibiting further enforcement actions by the Coastal Commission, damages for the alleged taking of property rights, and attorneys’ fees and costs. The Coastal Commission proceeded to issue an Executive Director Cease and Desist Order to Sable on February 18, 2025, related to certain of Sable’s pipeline repair and maintenance activities and safety valve installation work.

On April 10, 2025, the Coastal Commission approved Cease and Desist Order CCC-25-CD-01, Restoration Order CCC-25-RO-01, and Administrative Penalty Order CCC-25-AP3-01, whereby the Coastal Commission ordered the Company to cease and desist from all ongoing development in the Coastal Zone “as part of the effort to restart the Santa Ynez Unit oil production operations and bring the pipelines back into use,” apply for new Coastal Act authorization for all previously completed, ongoing, and future development in the Coastal Zone to the extent “part of the effort to restart the Santa Ynez Unit oil production operations and bring the pipelines back into use,” and imposed an administrative penalty of approximately $18.0 million on the Company. Sable will continue to vigorously pursue all available legal remedies related to the orders, including the administrative penalty, imposed by the Coastal Commission.

On April 16, 2025 the Coastal Commission filed a request in the Santa Barbara County Superior Court for a temporary restraining order against the Company to restrain the Company from violating the Cease and Desist Order CCC-25-CD-01 and to halt repair and maintenance activities on the Santa Ynez Pipeline System within the Coastal Zone. The request was filed within the Company’s ongoing litigation against the Coastal Commission (Case No. 25CV00974). On April 17, 2025, the court denied the Coastal Commission’s request for a temporary restraining order and set the matter for further hearing on May 14, 2025, which date was later continued to May 28, 2025.

On April 22, 2025, counsel for the Coastal Commission filed a Petition for Stay, Writ of Supersedeas, or Other Appropriate Order, and Request for Temporary Stay with the Second Division California Court of Appeal, seeking a temporary stay of the Santa Barbara County Superior Court’s denial of the Coastal Commission’s request for a TRO and an order requiring Sable to comply with the cease and desist order. Sable filed an Opposition to the Coastal Commission’s Petition with the Court of Appeal on April 28, 2025. On May 15, 2025, the Court of Appeal denied the Coastal Commission’s request for a temporary stay.

On May 28, 2025, the court granted the Coastal Commission’s application for issuance of a preliminary injunction, enjoining Sable from conducting any further “development” in violation of Cease and Desist Order CCC-25-CD-01. On July 9, 2025, the court denied Sable’s motion to stay the Cease and Desist Order CCC-25-CD-01. On July 16, 2025, Sable filed a notice of appeal of challenging the court’s issuance of preliminary injunction. On July 29, 2025, counsel for Sable filed a Petition for Writ of Mandate or Other Appropriate Relief with the Second Division California Court of Appeal, seeking a writ of mandate reversing the Santa Barbara County Superior Court’s denial of Sable’s motion to the stay Cease and Desist Order CCC-25-CD-01. On August 4, 2025, the Court of Appeal denied Sable’s Petition for Writ of Mandate. On October 6, 2025, Sable filed a motion to file an amended complaint which quantifies its monetary damages in excess of $347 million. On October 15, 2025, the Santa Barbara County Superior Court denied the Company’s request for the issuance of a writ of mandate on its first cause of action and set procedural motions related to Sable’s four additional

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causes of action for December 3, 2025. On November 5, 2025, Sable filed its opening brief in support of its appeal challenging the Superior Court’s issuance of the preliminary injunction. Sable also filed a Petition for Writ of Mandate or Other Appropriate Relief, seeking a writ of mandate reversing the Superior Court’s October 15, 2025, denial of Sable’s first cause of action.

On December 3, 2025, the Santa Barbara Superior Court denied the Coastal Commission’s motion for judgment on the pleadings as to its first amended cross complaint, granted Sable’s motion to file the second amended complaint, and requested further briefing on Sable’s four remaining causes of action. On February 18, 2026, the Santa Barbara Superior Court denied Sable’s Motion for Reconsideration of the Preliminary Injunction for lack of jurisdiction pending Sable’s appeal of the preliminary injunction to the Second Division California Court of Appeal. The Santa Barbara Superior Court also denied Sable’s Motion for Reconsideration of Sable’s Writ of Mandate. A hearing on the Coastal Commission’s to-be-filed Motion for Judgment on the Pleadings is set for May 20, 2026.

On December 23, 2025, the Coastal Commission’s Executive Director sent PHMSA a letter requesting to review the Company’s Restart Plan application materials pursuant to the Coastal Zone Management Act (“CZMA”), which PHMSA had approved on December 22, 2025. The letter also requested that PHMSA provide the Commission with the Company’s Emergency Special Permit application materials to allow for a similar review by the Commission under the CZMA. The letter asserts that PHMSA’s approval of the Company’s Restart Plan and the Emergency Special Permit should be considered stayed pending the Commission’s review. The letter also notified PHMSA that the Commission is reviewing PHMSA’s concurrence with the Company’s determination that Pipeline Segments 324 and 325 constitute part of an interstate pipeline facility under the PSA. On February 20, 2026, PHMSA responded to the Coastal Commission’s December 23 letter, advising the Commission that PHMSA’s records are available by submitting a request for information pursuant to the Freedom of Information Act, advising that some of the records may already be public owing to litigation that has been filed challenging the Restart Plan approval, and otherwise abstaining from comment owing to ongoing litigation.

State Parks

On May 8, 2025, the State Parks issued a Right of Entry (“ROE”) Permit that allowed the Company to perform certain specified repair and maintenance activities on portions of Segment 325 located within Gaviota State Park. On July 27, 2025, State Parks issued an annual ROE Permit relating to Segment 325 within Gaviota State Park. Sable is also working with State Parks on the terms of a long-term easement agreement.

Offshore Storage and Treating Vessel Alternative

On September 29, 2025, Sable announced that it is evaluating and pursuing an offshore storage and treating vessel (“OS&T”) strategy to provide access to domestic and global markets via shuttle tankers for federal crude oil produced from the SYU in the Pacific Outer Continental Shelf Area (the “OS&T Strategy”). Continued delays related to the Santa Ynez Pipeline System have prompted Sable to evaluate and pursue the OS&T Strategy. On October 9, 2025, Sable submitted a Development and Production Plan update for the SYU to the Bureau of Ocean Energy Management (“BOEM”). Prior to implementation of the OS&T Strategy, regulatory authorizations are required, including clearance from BOEM.

Preparations for the OS&T Strategy include the acquisition of a suitable OS&T vessel, certain refitting and upgrades to the vessel and the SYU equipment, transportation of the vessel to SYU, and related installation. In connection with implementation of the OS&T Strategy, the Company expects to opportunistically acquire an existing OS&T in the first quarter of 2026, with delivery of the vessel to SYU expected in the third quarter of 2026. Following the acquisition of the vessel, and vessel and platform upgrades and installation, Sable would expect to begin sales from all SYU platforms in the fourth quarter of 2026, with expected comprehensive oil production rates of over 50,000 barrels of oil per day, utilizing the OS&T within the SYU federal leases, provided the Company receives regulatory clearances. Sable estimates that the total capital required to execute the OS&T Strategy is approximately $475.0 million. The Company has already incurred a small portion of such capital expenditures, with the vast majority of such capital expenditures remaining, provided the Company receives regulatory clearances. See “Risk Factors—Risks Associated with Our Operations—In order to commence operations pursuant to the OS&T Strategy, we will require clearances and permitting, including from BOEM.”

Amendment of the Senior Secured Term Loan

On November 3, 2025, the Company and Exxon entered into an amendment (the “Second Debt Amendment”) to the $625.0 million five year Senior Secured Term Loan with Exxon (the “Senior Secured Term Loan”), which extended the maturity date of the Senior Secured Term Loan to the earlier of (i) March 31, 2027 or (ii) 90 days after first sales of Hydrocarbons (as defined in the Senior Secured Term Loan). The Second Debt Amendment increased the interest rate

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under the Senior Secured Term Loan from ten percent (10%) per annum to fifteen percent (15%) per annum, compounded annually, payable in arrears on January 1st of each year. At the Company’s election, accrued but unpaid interest may be deemed paid on each interest payment date by adding the amount of interest owed to the outstanding principal (paid-in-kind) amount under the Senior Secured Term Loan. The Second Debt Amendment also includes additional reporting covenants and a financial liquidity covenant that requires the Company to have not less than $25.0 million in unrestricted cash, measured at the end of each month.

Government Requests

On December 2, 2025, the Company received subpoenas from the United States Attorney’s Office for the Southern District of New York (“SDNY”) and SEC requesting documents (the “Government Requests”). The document requests relate to issues raised in an October 31, 2025 report published by Hunterbrook Media (the “Hunterbrook Report”) and the trading of Company securities, as well as related issues. The Company is providing documents and cooperating with the Government Requests.

Operations

General

Sable is the owner of the SYU Assets. Prior to consummation of the Business Combination, EM was the owner and operator of the platforms and onshore processing facility and Plains was the owner and operator of the Pipeline Segments 324 and 325. EM acquired the Pipeline Segments 324 and 325 from Plains on October 13, 2022 pursuant to the EM-Plains Purchase Agreement. In connection with the Business Combination, a substantial portion of the existing employees of SYU Assets have continued in their same capacity with Sable. The offshore platforms have permanent drilling systems in place.

Title to Properties

The interests in the properties on which the SYU Assets are located and their operations are conducted derive from ownership, leases, easements, rights-of-way, permits, or licenses from landowners or governmental authorities, permitting the use of such real property for their operations. Other than as described under “Risk Factors—We do not own all of the land on which our assets are located or all of the land that we must traverse in order to conduct our operations. There are disputes with respect to certain of the rights-of-way or other interests and any unfavorable outcomes of such disputes could require us to incur additional costs”, the Company believes it has satisfactory title or other rights to all such properties in accordance with industry standards, and Sable conducted thorough diligence and title investigations in advance of the Business Combination. Individual properties may be subject to burdens that do not materially interfere with the use or affect the value of the properties. Burdens on properties may include customary royalty interests, liens incident to operating agreements and for current taxes, obligations or duties under applicable laws, development obligations under natural gas leases, or net profits interests. Separately, Sable currently maintains all 16 federal leases within the Santa Ynez Unit.

Delivery Commitments

Sable has no commitments to deliver a fixed and determinable quantity of its oil or natural gas production in the near future under any existing sales contracts.

Derivative Activities

Sable is not currently party to any commodity derivative contracts. After recommencing oil sales, Sable may enter into commodity derivative contracts with unaffiliated third parties to achieve more predictable cash flows and to reduce exposure to fluctuations in oil and natural gas prices. Sable may enter into commodity derivative contracts at times and on terms desired to maintain a portfolio of commodity derivative contracts covering a specified percentage or range of its estimated production, typically over a one-to-three-year period, at any given point of time. It may, however, hedge more or less than this approximate amount from time to time.

Sable is not currently party to any interest rate swaps and substantially all of Sable’s indebtedness from the Business Combination consists of fixed-rate indebtedness. However, if Sable incurs variable rate indebtedness in the future it may periodically enter into interest rate swaps to mitigate exposure to market rate fluctuations by converting variable interest rates to fixed interest rates.

Sable will only enter into derivative contracts with creditworthy counterparties (generally, financial institutions) deemed by management as competent and competitive market makers. Those counterparties may include existing or future lenders or their affiliates. Sable will continue to evaluate the benefit of employing derivatives in the future.

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Competition

Sable operates in a highly competitive environment for securing trained personnel, contracting for drilling equipment, and from time to time leasing or otherwise acquiring new acreage. Many of its competitors possess and employ financial, technical and personnel resources substantially greater than Sable’s, which can be particularly important in the areas in which it operates. As a result, Sable’s competitors may be able to pay more for productive oil and natural gas properties and exploratory prospects, as well as evaluate, bid for and purchase a greater number of properties and prospects than its financial or personnel resources permit. Sable’s ability to acquire additional properties and to find and develop reserves and resources will depend on its ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, there is substantial competition for capital available for investment in the oil and natural gas industry and many of its competitors have access to capital at a lower cost than that available to Sable.

Seasonality

Sable’s offshore operations can be impacted by inclement weather from time to time. The price Sable receives for natural gas production is typically impacted by seasonal fluctuations in demand for natural gas. The demand for natural gas typically peaks during the coldest months and tapers off during the milder months, with a slight increase during the summer to meet the demands of electric generators. The weather during any particular season can affect this cyclical demand for natural gas. Seasonal anomalies such as mild winters or hot summers can lessen or intensify this fluctuation. In addition, certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer. This can also lessen seasonal demand fluctuations. Recently there has been elevated global demand for natural gas due to shortages exacerbated by geopolitical issues and conflicts but there is no assurance that demand will remain elevated.

Insurance

In accordance with customary industry practice, Sable will maintain insurance against many, but not all, potential losses or liabilities arising from its operations and at costs that it believes to be economic. Sable will regularly review its risks of loss and the cost and availability of insurance and revise its insurance accordingly. Its insurance will not cover every potential risk associated with its operations, including the potential loss of significant revenues. Sable can provide no assurance that its coverage will adequately protect it against liability from all potential consequences, damages and losses. Prior to the resumption of sales, or shortly thereafter, Sable expects to have or be in the process of obtaining the following insurance policies:

Commercial General Liability;Oil Pollution Act Liability;

Primary Umbrella / Excess Liability;Pollution Legal Liability;

Property;Charterer’s Legal Liability;

Workers’ Compensation;Non-Owned Aircraft Liability;

Employer’s Liability;Automobile Liability;

Maritime Employer’s Liability;Directors & Officers Liability;

U.S. Longshore and Harbor Workers’;Employment Practices Liability;

Energy Package/Control of Well;Crime;

Loss of Production Income;Fiduciary Liability; and Cybersecurity.

Sable monitors regulatory changes and comments and considers their impact on the insurance market, along with the SYU Assets’ overall risk profile. As necessary, Sable expects to adjust its risk and insurance program to provide protection at a level it considers appropriate while weighing the cost of insurance against the potential and magnitude of disruption to its operations and cash flows. Changes in laws and regulations could lead to changes in underwriting standards, limitations on scope and amount of coverage, and higher premiums, including possible increases in liability caps for claims of damages from oil spills.

Potential Opportunities for Carbon Sequestration

Sable may pursue new opportunities on the OCS for long-term sequestration of carbon dioxide that may otherwise go into the atmosphere. The 2021 Infrastructure Investment and Jobs Act gives the Secretary of the Interior new authority to allow the long-term sequestration of carbon dioxide on the OCS and directs the Secretary to promulgate regulations to implement

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the authority. As the regulatory program is developed over time, Sable intends to evaluate the potential to leverage its infrastructure for carbon sequestration in light of the new program and applicable local, state, and federal permitting requirements.

Environmental, Occupational Safety and Health Matters and Regulations

General

Our oil and natural gas development and production operations are subject to stringent and complex federal, state and local laws and regulations governing the release or discharge of materials into the environment, health and safety aspects of its operations, or otherwise relating to protection of the environment and natural resources. These laws and regulations impose numerous obligations applicable to the Company’s operations, as well as future plug and abandonment and decommissioning activities, including the issuance of certain permits before conducting regulated drilling activities; the restriction of types, quantities and concentration of materials that can be released or discharged into or through the environment; the limitation or prohibition of drilling activities on certain lands lying within protected or preserved areas; the application of specific health and safety criteria addressing worker protection; and the imposition of substantial liabilities for pollution and natural resources damages potentially resulting from its operations.

Numerous governmental authorities, such as the EPA, Bureau of Safety and Environmental Enforcement (“BSEE”), PHMSA, OSFM, California Department of Conservation’s Geologic Energy Management Division (“CalGEM”), Coastal Commission, CDFW, Central Coast Regional Water Quality Control Board (“Regional Board”), and the SLC, and other governmental agencies have the power to enforce compliance with these laws and regulations and the permits issued under them, often requiring difficult and costly compliance or corrective actions. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil or criminal penalties, the imposition of investigatory or remedial obligations, injunctive relief, the suspension or revocation of necessary permits, licenses and authorizations, the requirement that additional pollution controls be installed and in some instances, the issuance of orders limiting or prohibiting some or all of its operations. We may also experience delays in obtaining or be unable to obtain required permits, including authorizations necessary to resume petroleum transportation through the Pipeline Segments 324 and 325 or maintain operations, which may delay or interrupt our operations and limit its growth and revenue. In addition, the long-term trend in environmental regulation has been to place more restrictions and limitations on activities that may affect the environment. The SYU Assets’ costs of compliance may increase if existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to its operations. Changing perspectives within the Executive Branch of the U.S. federal government and environmental litigation involving the validity of certain regulatory requirements associated with exploration, development and decommissioning may materially impact our compliance costs. Consequently, the SYU Assets’ costs of compliance may increase if existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to its operations.

Under certain environmental laws that impose strict as well as joint and several liability, the Company may be required to remediate contaminated properties currently or formerly owned or operated by it or facilities of third parties that received waste generated by its operations, regardless of whether such contamination resulted from its conduct or the conduct of others that was in compliance with all applicable laws at the time of such conduct. In addition, claims for damages to persons or property, including natural resources, may result from the environmental, health and safety impacts of its operations. Moreover, public interest in the protection of the environment has increased in recent years. New laws and regulations continue to be enacted, particularly at the state level, and the long-term trend of more expansive and stringent environmental legislation and regulations applied to the crude oil and natural gas industry could continue, resulting in increased costs of doing business and consequently affecting profitability. To the extent new or more stringent laws are enacted or other governmental action is taken that restricts drilling or imposes more stringent and costly operating, waste handling, disposal and cleanup requirements, our business, prospects, financial condition or results of operations could be materially adversely affected.

The following is a summary of the more significant existing environmental, occupational safety and health laws and regulations to which our business operations are subject and for which compliance may have a material adverse impact on its capital expenditures, results of operations or financial position.

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Offshore Operations

Our oil and gas operations are conducted on offshore leases in federal waters and those operations are regulated by agencies such as BOEM and BSEE, which have broad authority to regulate our oil and gas operations.

BOEM is responsible for managing environmentally and economically responsible development of the nation’s offshore resources. Its functions include offshore leasing, resource evaluation, review and administration of oil and gas exploration and development plans, renewable energy development, and National Environmental Policy Act (“NEPA”) analysis and environmental review. Lessees must obtain BOEM approval for exploration and development and production plans prior to the commencement of offshore operations. BOEM generally requires that lessees have substantial net worth, post supplemental bonds or provide other acceptable assurances that the lease obligations will be met. In April 2024, BOEM published a final rule that substantially revises the financial assurance requirements applicable to offshore oil and gas operations by requiring certain oil, gas, and sulfur lessees; right-of-use and easement grant holders; and pipeline right-of-way grant holders to obtain supplemental financial assurance for decommissioning activities on OCS leases, rights-of-way and rights-of-use and easements. The Department of the Interior initiated a review of this rule pursuant to Secretary’s Order No. 3418, issued February 3, 2025, to implement President Trump’s January 20, 2025 Unleashing American Energy Executive Order 14154, which identifies this BOEM financial assurance rule for potential suspension, revision, or rescission. In litigation filed in the Western District of Louisiana challenging the rule, in April 2025 the court granted a stay of the proceedings as a result of the Department of the Interior’s review of the rule. The rule remains effective, but its scope and application may change depending on the outcome of the agency’s rulemaking review and related litigation.

BSEE is responsible for safety and environmental oversight of offshore oil and gas operations. Its functions include the development and enforcement of safety and environmental regulations, permitting offshore exploration, development and production, inspections, offshore regulatory programs, oil spill response and training and environmental compliance programs. BSEE regulations require offshore production facilities and pipelines located on the OCS to meet stringent engineering and construction specifications, and BSEE has proposed and/or promulgated additional safety-related regulations concerning the design and operating procedures of these facilities and pipelines, including regulations to safeguard against or respond to well blowouts and other catastrophes. BSEE regulations also restrict the flaring or venting of natural gas, prohibit the flaring of liquid hydrocarbons and govern the plugging and abandonment of wells located offshore and the installation and removal of all fixed drilling and production facilities. In April 2023, BSEE issued a final rule clarifying and providing transparency to the process by which BSEE will enforce decommissioning obligations on existing lessees and rights-of-use and easement grant holders. BSEE’s final rule adopted new timeframes for predecessors to respond to a decommissioning order to perform accrued decommissioning obligations, and clarified that right-of-use and easement grant holders also accrue decommissioning obligations.

BOEM and BSEE have adopted regulations providing for enforcement actions, including civil penalties and lease forfeiture or cancellation for failure to comply with regulatory requirements for offshore operations. If we fail to pay royalties or comply with safety and environmental regulations, BOEM and BSEE may take action that seeks the curtailment, suspension, or termination of our operations and we may be subject to civil or criminal liability.

Additionally, delays in the approval or refusal of plans and issuance of permits by BOEM or BSEE because of staffing, economic, environmental, legal or other reasons (or other actions taken by BOEM or BSEE) could adversely affect the offshore SYU Assets’ operations. The requirements imposed by BOEM and BSEE regulations are frequently changed and subject to new interpretations. Also, in addition to permits and approvals required by BOEM and BSEE, approvals and permits may be required from other agencies for the oil and gas operations associated with the SYU Assets offshore properties, such as the U.S. Coast Guard, the EPA, U.S. Department of Transportation, U.S. Army Corps of Engineers and state and local authorities, such as the Coastal Commission, the SLC, and the Santa Barbara County Air Pollution Control District.

Hazardous Substances and Waste Handling

Our operations are subject to environmental laws and regulations relating to the management and release of hazardous substances, solid and hazardous wastes and petroleum hydrocarbons. These laws generally regulate the generation, storage, treatment, transportation and disposal of solid and hazardous waste and may impose strict and, in some cases, joint and several liability for the investigation and remediation of affected areas where hazardous substances may have been released or disposed. The Comprehensive Environmental Response, Compensation and Liability Act, as amended (“CERCLA”), also referred to as the Superfund law and comparable state laws, impose liability, without regard to fault or the legality of the original conduct, on certain potentially responsible parties. These persons include current owners or operators of the site where a release of hazardous substances occurred, prior owners or operators that owned or operated the site at the time of the release or disposal of hazardous substances and companies that disposed or arranged for the disposal of the

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hazardous substances found at the site. Under CERCLA, these persons may be subject to strict and joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover the costs they incur from the responsible classes of persons. Despite the “petroleum exclusion” of Section 101(14) of CERCLA, which currently encompasses natural gas, we may nonetheless handle hazardous substances within the meaning of CERCLA, or similar state statutes, in the course of its ordinary operations and as a result, may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment. Also, comparable state statutes may not contain a similar exemption for petroleum, and it is also not uncommon for neighboring landowners and other third parties to file common law-based claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. In addition, we may have liability for releases of hazardous substances at its properties by prior owners or operators or other third parties.

The Oil Pollution Act is the primary federal law imposing oil spill liability. The Oil Pollution Act contains numerous requirements relating to the prevention of, and response to petroleum releases into waters of the United States, including the requirement that operators of offshore facilities and certain onshore facilities near or crossing waterways must maintain certain significant levels of financial assurance to cover potential environmental cleanup and restoration costs. Under the Oil Pollution Act, strict, joint and several liability may be imposed on “responsible parties” for all containment and cleanup costs and certain other damages arising from a release, including, but not limited to, the costs of responding to a release of oil to surface waters and natural resource damages resulting from oil spills into or upon navigable waters, adjoining shorelines or in the exclusive economic zone of the United States. A “responsible party” includes the owner or operator of an onshore facility. The Oil Pollution Act establishes a liability limit for onshore facilities, but these liability limits may not apply if: a spill is caused by a party’s gross negligence or willful misconduct; the spill resulted from violation of a federal safety, construction or operating regulation; or a party fails to report a spill or to cooperate fully in a cleanup. We are also subject to analogous state statutes that impose liabilities with respect to oil spills. For example, the CDFW’s Office of Oil Spill Prevention and Response has adopted oil-spill prevention regulations that overlap with federal regulations.

We also generate solid wastes, including hazardous wastes, which are subject to the requirements of the Resource Conservation and Recovery Act, as amended (“RCRA”), and comparable state statutes. Although RCRA regulates both solid and hazardous wastes, it imposes stringent requirements on the generation, storage, treatment, transportation and disposal of hazardous wastes. Certain petroleum production wastes are excluded from RCRA’s hazardous waste regulations. These wastes, instead, are regulated under RCRA’s less stringent solid waste provisions, state laws or other federal laws. It is possible that these wastes, which could include wastes expected to be generated during our operations, could be designated as “hazardous wastes” in the future and, therefore, be subject to more rigorous and costly disposal requirements. Indeed, legislation has been proposed from time to time in Congress to re-categorize certain oil and gas exploration and production wastes as “hazardous wastes.” Also, in December 2016, the EPA entered into a consent decree requiring it to review its regulation of oil and gas waste. In April 2019, the EPA determined that revisions to the RCRA regulations were not required, concluding that any adverse effects related to oil and gas waste are more appropriately and readily addressed within the framework of existing state regulatory programs. However, any such changes to state programs could result in an increase in our costs to manage and dispose of oil and gas waste, which could have a material adverse effect on its maintenance capital expenditures and operating expenses.

It is possible that our oil and natural gas operations may require us to manage naturally occurring radioactive materials (“NORM”). NORM is present in varying concentrations in sub-surface formations, including hydrocarbon reservoirs, and may become concentrated in scale, film and sludge in equipment that comes into contact with crude oil and natural gas production and processing streams. Some states have enacted regulations governing the handling, treatment, storage and disposal of NORM.

Administrative, civil and criminal penalties can be imposed for failure to comply with hazardous substance and waste handling requirements. For ownership and operation of the SYU Assets, we believe that we are in substantial compliance with the requirements of CERCLA, Oil Pollution Act, RCRA and other applicable federal and related state and local laws and regulations, and that we hold all necessary and up-to-date permits, registrations and other authorizations required under such laws and regulations. Although we believe that the costs of managing the Company’s hazardous substances and wastes as they are presently classified are reflected in the Company’s budget, any legislative or regulatory reclassification of oil and natural gas exploration and production wastes could increase its costs to manage and dispose of such wastes.

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Water Discharges

The Federal Water Pollution Control Act (the “Clean Water Act”), the Safe Drinking Water Act (“SDWA”), the Oil Pollution Act and analogous state laws, impose restrictions and strict controls with respect to the discharge of pollutants, including oil and hazardous substances, into navigable waters of the United States, as well as state waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. These laws and regulations also prohibit certain activity in wetlands unless authorized by a permit issued by the U.S. Army Corps of Engineers. In May 2023, the Supreme Court issued an opinion in Sackett v. EPA that limited the jurisdiction of the U.S. Army Corps of Engineers to wetlands with a continuous surface connection to a permanent body of water connected to traditional navigable waters, such as streams, oceans, rivers, and lakes. To the extent a new rule or further litigation expands the scope of the Clean Water Act’s jurisdiction or impacts available agency resources, we could face increased costs and/or delays with respect to obtaining permits for dredge and fill activities in wetland areas.

The EPA has also adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain individual permits or coverage under general permits for storm water discharges. Costs may be associated with the treatment of storm water or developing and implementing storm water pollution prevention plans, as well as for monitoring and sampling the storm water runoff from certain of our facilities. Some states also maintain groundwater protection programs that require permits or specify other requirements for discharges or operations that may impact groundwater conditions. These same regulatory programs may also limit the total volume of water that can be discharged, hence limiting the rate of development and requiring us to incur compliance costs. Additionally, we are required to develop and implement spill prevention, control and countermeasure plans, in connection with on-site storage of significant quantities of oil.

These laws and any implementing regulations provide for administrative, civil and criminal penalties for any unauthorized discharges of oil and other substances in reportable quantities and may impose substantial potential liability for the costs of removal, remediation and damages. Additionally, obtaining permits has the potential to delay the development of natural gas and oil projects. For ownership and operation of the SYU Assets, we believe that we maintain all required discharge permits necessary to conduct our operations and that we are in substantial compliance with their terms.

In addition, in some instances the operation of underground injection wells for the disposal of wastewater has been alleged to cause earthquakes. For example, the EPA released a report with findings and recommendations related to public concern about induced seismic activity from disposal wells. The report recommended strategies for managing and minimizing the potential for significant injection-induced seismic events. Any future orders or regulations addressing concerns about seismic activity from well injection could affect or curtail our operations.

On December 13, 2024, the Regional Board issued three letters to the Company related to the Pipeline Segments 324 and 325: (i) a Notice of Violation for an alleged unauthorized discharge of waste to waters of the state at an ephemeral stream in the County; (ii) a Directive to obtain regulatory coverage for an alleged unauthorized discharge of waste to waters of the state at the same ephemeral stream identified in item (i); and (iii) a First Notice of Non-Compliance for an alleged failure to obtain coverage under the Regional Board’s General Permit for Stormwater Discharges Associated with Industrial Activities in the County and San Luis Obispo and Kern Counties in California.

On December 17, 2024, CDFW issued a Notice of Potential Violation to Sable for alleged violations of the California Fish and Game Code at four separate sites within the County and San Luis Obispo County in California for alleged placement or fill of waste to waters. On January 13, 2025, Sable submitted a written response to CDFW’s Notice of Potential Violation.

On January 10, 2025, Sable submitted a written response to the Regional Board’s December 2024 letters. On January 22, 2025, the Regional Board issued two additional letters to Sable related to the Pipeline Segments 324 and 325: (i) a Second and Final Notice of Non-Compliance for an alleged failure to obtain coverage under the Regional Board’s General Permit for Construction Stormwater Discharges in Santa Barbara, San Luis Obispo, and Kern Counties; and (ii) an order requiring Sable to submit a technical report associated with the discharge of earthen material to waters of the state.

On January 31, 2025, Sable submitted an application to the Regional Board for regulatory coverage for the alleged discharge of waste to waters of the state at the location identified in the Regional Board’s December 13, 2024, Notice of Violation, and coverage was approved and issued by the Regional Board on March 20, 2025. On February 18, 2025, Sable submitted an application to CDFW for the same site, that application was deemed complete in March 2025, and work at the site was approved to proceed in May 2025. On February 21, 2025, the Company submitted a written response to the Regional Board’s Second and Final Notice of Non-Compliance. On March 7, 2025, Sable submitted its initial responses to

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the Regional Board’s order requiring Sable to submit a technical report, and on April 15, 2025, the Company submitted a supplemental response, that Sable committed to provide in its March initial response.

Sable submitted after-the-fact permitting applications to the Regional Board and CDFW with respect to potential discharges at the four sites identified in CDFW’s December 2024 notice during the first two weeks of March 2025. The Regional Board provided responses and requests for additional information in April 2025, to which the Company provided supplemental information on April 25, 2025. These sites were fully permitted by the Regional Board in June 2025 and by CDFW as of September 2025.

On April 15, 2025, the Regional Board issued a second Notice of Violation to the Company for an alleged failure to provide a sufficient response to the Regional Board’s request for a technical report and continued allegations of unauthorized discharges. On that same day, the Company submitted to the Regional Board further responses and additional information in response to the Regional Board’s request for a technical report, in which the Company identified additional sites that may require after-the-fact permitting. On April 17, 2025, the Regional Board issued Resolution R3-2025-0024, which referred any assessment of civil liability, injunctive and declaratory relief against the Company for its alleged violations of the California Water Code to the California Attorney General via the California Superior Court. After the issuance of Resolution R3-2025-0024, the Company continued to work with the Regional Board and CDFW to identify locations and submit additional after-the-fact permit applications. On July 24, 2025, the Regional Board issued a third Notice of Violation, requiring the Company to provide additional information in order to satisfy the request for a technical report, to which the Company timely responded on August 13, 2025 with all requested information. As a result of this process, nine additional sites were identified. As of January 29, 2026, the Regional Board has issued permits for the nine additional locations (for a total of 14 locations) identified by the Regional Board, CDFW, and the Company. CDFW has issued a draft permit for the nine locations, and the Company expects the final permit will be issued by mid-March 2026. At that point, all locations will be permitted. Based on the information provided by Sable in response to the Notices of Non-Compliance associated with the Regional Board’s General Permit for Construction Stormwater Discharges, the Regional Board is not further requiring Sable to obtain coverage under that permit for the work performed.

On September 16, 2025, the Santa Barbara County District Attorney’s office filed a criminal Complaint in Santa Barbara County Superior Court, with 21 Counts being pursued (sixteen (16) misdemeanors and five (5) felonies) for alleged violation of the California Fish & Game Code and Water Code. The Complaint references some of the 14 locations where the Company has already sought after-the-fact permitting from the Regional Board and CDFW, but also includes other locations where neither the Regional Board nor the CDFW are requiring any further action or permitting. The Company has retained counsel for defense. On October 3, 2025, the Regional Board filed a civil action in Santa Barbara County Superior Court alleging that the Company failed to secure permits at the 14 locations prior to undertaking the work, though the Complaint also notes the Company’s after-the-fact permitting efforts. The Complaint also alleges failure to comply with the request for a technical report. The Regional Board is seeking civil penalties and potentially limited injunctive relief. The Company filed its response to the Complaint on November 25, 2025. A case management conference is scheduled for May 15, 2026, and the parties have scheduled mediation for April 8, 2026.

Air Emissions

The federal Clean Air Act, as amended (“CAA”), and comparable state laws restrict the emission of air pollutants from many sources, including compressor stations, through the issuance of permits and the imposition of other requirements. Our properties and associated facilities are also subject to regulation by state and local authorities. Federal and state laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions of certain pollutants. The EPA has developed, and continues to develop, stringent regulations governing emissions of air pollutants at specified sources. New facilities may be required to obtain permits before work can begin, and modified and existing facilities may be required to obtain additional permits.

In June 2016, the EPA finalized regulations establishing New Source Performance Standards, known as Subpart OOOOa, for methane and volatile organic compounds from new and modified oil and natural gas production and natural gas processing and transmission facilities. In September 2020, the EPA finalized two sets of amendments to the 2016 Subpart OOOOa standards. The first, known as the 2020 Technical Rule, reduced the 2016 rule’s fugitive emissions monitoring requirements and expanded exceptions to pneumatic pump requirements, among other changes. The second, known as the 2020 Policy Rule, rescinded the methane-specific requirements for certain oil and natural gas sources in the production and processing segments. On January 20, 2021, President Biden issued an Executive Order directing the EPA to rescind the 2020 Technical Rule by September 2021 and consider revising the 2020 Policy Rule. On June 30, 2021, President Biden

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signed a Congressional Review Act (“CRA”) resolution passed by Congress that revoked the 2020 Policy Rule. The CRA did not address the 2020 Technical Rule.

Further, on March 8, 2024, the EPA issued a final rule intended to reduce methane emissions from oil and gas sources. The rule made the existing regulations in Subpart OOOOa more stringent and created a Subpart OOOOb to expand reduction requirements for new, modified, and reconstructed oil and gas sources, including standards focusing on certain source types that had never been regulated under the CAA (including intermittent vent pneumatic controllers, associated gas, and liquids unloading facilities). In addition, the rule established “Emissions Guidelines,” creating a Subpart OOOOc that requires states to develop plans to reduce methane emissions from existing sources that must be at least as effective as presumptive standards set by the EPA. The rule also aims to reduce methane emissions from oil and natural gas operations by adding requirements for additional sources. In November 2025, EPA finalized deadline exemptions for certain provisions of the Subpart OOOOb/OOOOc rule.

In March 2024, the Bureau of Land Management (“BLM”) finalized a rule that modernizes regulations to curb the waste of natural gas during oil and gas production on federal and Tribal lands. This rule requires oil and gas companies to implement measures to avoid wasteful practices, find and fix leaks, and ensure fair compensation through royalty payments. BLM is in the process of considering revisions to these regulations and has stated it will delay enforcement of certain compliance deadlines for an additional year until December 10, 2026.

On August 16, 2022, President Biden signed into law the Inflation Reduction Act of 2022 (the “Inflation Reduction Act”). The Inflation Reduction Act amended the Clean Air Act to impose a fee on the emission of methane from sources required to report their greenhouse gas (“GHG”) emissions to the EPA, including those sources in the petroleum and natural gas production category. The methane emissions charge started in calendar year 2024 at $900 per ton of methane, increases to $1,200 in 2025, and will be set at $1,500 for 2026 and each year thereafter. Calculation of the fee is based on certain thresholds established in the Inflation Reduction Act. On November 18, 2024, the EPA published a final rule to implement this waste emissions charge as required by the Inflation Reduction Act (the “IRA”). However, on March 14, 2025, Congress through a joint resolution under the Congressional Review Act disapproved EPA’s final rule, and EPA removed the implementing regulations in May 2025. Subsequently, Congress amended the Clean Air Act in July 2025 as part of the One Big Beautiful Bill Act to delay the start of this methane emissions charge until emissions reported for calendar year 2034 and to constrain EPA’s implementation authority and funding for that program.

Any future changes to the regulations governing methane emissions, and other air quality programs, may require us to obtain pre-approval for the expansion or modification of existing facilities or the construction of new facilities expected to produce air emissions, impose stringent air permit requirements, or utilize specific equipment or technologies to control emissions. Compliance with such rules could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our business.

We may be required to incur certain capital expenditures in the next few years for air pollution control equipment in connection with maintaining or obtaining operating permits addressing air emission related issues, which may have a material adverse effect on the Company’s operations. Obtaining permits also has the potential to delay the development of oil and natural gas projects and increase the Company’s costs of development, which costs could be significant. We believe that we are currently in substantial compliance with all air emissions regulations and that the Company holds all necessary and valid construction and operating permits for the Company’s current operations.

Regulation of “Greenhouse Gas” Emissions

In December 2015, the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change resulted in nearly 200 countries, including the United States, coming together to develop the Paris Agreement, which calls for the parties to undertake “ambitious efforts” to limit the average global temperature. Although the agreement does not create any binding obligations for nations to limit their greenhouse gas emissions, it does include pledges to voluntarily limit or reduce future emissions. On June 1, 2017, President Trump announced that the U.S. would withdraw from the Paris Agreement and completed the process of withdrawing on November 4, 2020. However, on January 20, 2021, President Biden issued written notification to the United Nations of the United States’ intention to rejoin the Paris Agreement, which became effective on February 19, 2021. In addition, in September 2021, President Biden publicly announced the Global Methane Pledge, a pact that aims to reduce global methane emissions at least 30% below 2020 levels by 2030. Since its formal launch at the United Nations Climate Change Conference (“COP26”), over 100 countries have joined the pledge. On January 20, 2025, President Trump signed an executive order initiating the re-withdrawal of the United States from the agreement, and the United States’ exit became effective in January 2026. In addition, various states and local governments have vowed to continue to enact regulations to achieve the goals of the Paris Agreement.

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While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant, economy-wide activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of significant federal climate legislation, a number of states have taken legal measures to reduce emissions of GHGs, including through the planned development of GHGs emission inventories and/or regional GHGs cap and trade programs.

On February 12, 2026, EPA rescinded its 2009 “Endangerment Finding” under Clean Air Act Section 202(a) that six greenhouse gases threaten public health and welfare, which had served as the basis for EPA’s regulation of greenhouse gas emissions from new motor vehicles and engines. In the rescission rule, EPA determined that Clean Air Act Section 202(a)(1) does not authorize EPA to prescribe emission standards in response to global climate change for multiple reasons, and accordingly EPA rescinded GHG emission standards and related regulatory provisions for new vehicles and engines. This rescission rule has been challenged in federal court.

In March 2024, the Securities and Exchange Commission (“SEC”) adopted climate-related disclosure rules, which were stayed by federal courts shortly thereafter. In March 2025, the SEC announced that it would not defend the rules in ongoing litigation, and they remain stayed. The ultimate scope and timing of any SEC climate disclosure requirements is uncertain. In contrast, several states are advancing climate-related disclosure or emissions programs. In California, the Climate Corporate Data Accountability Act (SB 253) requires certain companies “doing business” in California with over $1 billion in annual revenues to publicly disclose Scope 1 and Scope 2 greenhouse gas emissions beginning in 2026 and Scope 3 emissions beginning in 2027, with rulemaking by the California Air Resources Board ongoing. California’s separate climate-related financial risk reporting law (SB 261) applicable to certain companies with more than $500 million in annual revenues is currently enjoined pending appeal; California has announced it will not enforce the January 1, 2026 deadline during the injunction. Other states and regional programs continue to pursue greenhouse gas-related initiatives, including emissions inventories, performance standards, and cap-and-trade mechanisms.

The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs or could adversely affect demand for the oil and natural gas it produces. For example, any GHG regulation could increase its costs of compliance by potentially delaying the receipt of permits and other regulatory approvals; requiring it to monitor emissions, install additional equipment or modify facilities to reduce GHG and other emissions; purchase emission credits; or utilize electric driven compression at facilities to obtain regulatory permits and approvals in a timely manner. Such climate change regulatory and legislative initiatives could have a material adverse effect on our business, financial condition and results of operations.

While we are subject to certain federal GHG monitoring and reporting requirements, our operations are not adversely impacted by existing federal, state and local climate change initiatives and, at this time, it is not possible to accurately estimate how potential future laws or regulations addressing GHG emissions would impact its business.

In addition, claims have been made against certain energy companies alleging that GHG emissions from oil and natural gas operations constitute a public nuisance or have caused other redressable injuries under federal and/or state common law. While our business is not a party to any such litigation, we could be named in actions making similar allegations. An unfavorable ruling in any such case could adversely impact our business, financial condition and results of operations.

Moreover, any legislation or regulatory programs to reduce GHG emissions could increase the cost of consumption, and thereby reduce demand for, the oil and natural gas we produce. Consequently, legislation and regulatory programs to reduce emissions of GHGs could have an adverse effect on our business, financial condition and results of operations. Incentives to conserve energy or use alternative energy sources as a means of addressing climate change could also reduce demand for the oil and natural gas we produce. In addition, parties concerned about the potential effects of climate change have directed their attention at sources of funding for energy companies, which has resulted in certain financial institutions, funds and other sources of capital restricting or eliminating their investment in oil and natural gas activities. Finally, it should be noted that most scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events. If any such effects were to occur in sufficient proximity to our facilities, they could have an adverse effect on our development and production operations, as well as potentially increased costs for insurance coverages in the aftermath of such effects.

National Environmental Policy Act

Oil and natural gas exploration and production activities on federal lands may be subject to NEPA, as amended. NEPA requires federal agencies, including the U.S. Departments of the Interior and Transportation, to evaluate major federal

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actions having the potential to significantly impact the human environment. Following an Executive Order from President Trump, on February 25, 2025, the White House’s Council on Environmental Quality (“CEQ”) published an interim final rule removing CEQ’s NEPA implementing regulations effective April 11, 2025, and later finalized that removal effective January 8, 2026. CEQ has issued nonbinding guidance directing federal agencies to revise or establish their own NEPA implementing procedures within twelve months to expedite permitting and align with NEPA as amended by the Fiscal Responsibility Act of 2023, and several agencies have begun adopting updated procedures, including the US Department of the Interior which issued an interim final rule substantially revising its regulations and issuing a non-binding implementing procedures. As a result, NEPA compliance is now governed primarily by the statute and agency-specific procedures rather than centralized CEQ regulations. Courts continue to address the scope of required analysis under NEPA, including in a 2025 Supreme Court decision that interpreted the deferential standard of review for an agency’s compliance with NEPA and narrowed when certain indirect effects must be considered. Future development and production activities and plans on federal lands and waters, including those in the Pacific Ocean, may require governmental approvals that could be subject to the requirements of NEPA in the future. This environmental review process has the potential to delay the development of oil and natural gas projects. Actions under NEPA also may be subject to comment, appeal or litigation, which can delay or halt projects. There has been and may continue to be litigation regarding the environmental review requirements of NEPA, and, accordingly, there may be uncertainty as to the NEPA requirements applicable to future development and production activities that require NEPA review.

Endangered Species Act and Migratory Bird Treaty Act

The federal ESA and analogous state statutes restrict activities that may adversely affect endangered and threatened species or their habitat. In August 2019, the U.S. Fish and Wildlife Service (“FWS”) and National Marine Fisheries Service (“NMFS”) issued three rules amending the implementation of the ESA regulations revising, among other things, the process for listing species and designating critical habitats. In addition, on December 18, 2020, the FWS amended its regulations governing critical habitat designations. In June 2021, FWS and NMFS announced plans to begin rulemaking processes to rescind these rules. By March 2024, the Biden administration had restored several protections that were amended under the Trump administration, including reinstating the blanket prohibitions against take for newly classified threatened species and ensuring that economic impacts are not considered when deciding if animals and plants need protection. On November 21, 2025, FWS and NMFS proposed additional rules that would largely restore the 2019–2020 ESA regulatory framework on a prospective basis. Those rules have not been finalized and their implementation remains uncertain.

Similar protections are offered to migratory birds under the Migratory Bird Treaty Act (“MBTA”), which makes it illegal to, among other things, hunt, capture, kill, possess, sell, or purchase migratory birds, nests, or eggs without a permit. This prohibition covers most bird species in the U.S. On January 7, 2021, FWS finalized a rule limiting the application of the MBTA. However, FWS revoked the rule in October 2021 and simultaneously issued an advanced notice of proposed rulemaking seeking comment on FWS’s plan to develop regulations to authorize incidental take under certain prescribed conditions. Subsequently, in April 2025, FWS withdrew this advanced notice of proposed rulemaking. Additionally, on April 11, 2025, the Solicitor of the US Department of the Interior issued a legal opinion withdrawing the Biden administration interpretation of the MBTA take provisions, and reinstated a prior interpretation that the MBTA take prohibition only applied to directed take of migratory birds.

Future implementation of the rules implementing the ESA and the MBTA are uncertain. The designation of previously unidentified endangered or threatened species in areas where we operate could cause us to incur additional costs or become subject to operating delays, restrictions or bans. Numerous species have been listed or proposed for protected status in areas in which we currently, or could in the future, undertake operations. The presence of protected species in areas where we operate could impair our ability to timely complete or carry out those operations, lose leaseholds if it is not permitted to timely commence drilling operations, cause us to incur increased costs arising from species protection measures, and consequently, adversely affect its results of operations and financial position.

Occupational Safety and Health

We are also subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) and comparable state laws that regulate the protection of the health and safety of employees. In addition, OSHA’s hazard communication standard requires that information be maintained about hazardous materials used or produced in the SYU Assets’ operations and that this information be provided to employees, state and local government authorities and citizens. Other OSHA standards regulate specific worker safety aspects of our operations. For example, under an OSHA standard limiting respirable silica exposure, the oil and gas industry was required to implement engineering controls and work practices to

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limit exposures below the new limits by June 2021. Failure to comply with OSHA requirements can lead to the imposition of penalties. We believe that our operations are in substantial compliance with the OSHA requirements.

Other Regulation of the Oil and Natural Gas Industry

The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden on our assets. For instance, PHMSA, which regulates the Santa Ynez Pipeline System, is reauthorized by Congress every four years by statute. When reauthorizing PHMSA’s authority to regulate natural gas and hazardous liquid pipelines and facilities, Congress often imposes mandates that require PHMSA to implement new regulatory requirements. Congress is currently considering legislation for PHMSA’s reauthorization, but its timeline for passage is uncertain.

Numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations that are binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the oil and natural gas industry with similar types, quantities and locations of production.

Legislation continues to be introduced in Congress, and the development of regulations continues by the U.S. Department of Homeland Security and other agencies concerning the security of industrial facilities, including oil and natural gas facilities. Our operations may be subject to such laws and regulations. Presently, it is not possible to accurately estimate the costs we could incur to comply with any such facility security laws or regulations, but such expenditures could be substantial.

Drilling and Production

Our operations are subject to various types of regulation at federal, state and local levels. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations, including regulating one or more of the following:

•the location of wells;

•the method of drilling and casing wells;

•the surface use and restoration of properties upon which wells are drilled;

•the plugging and abandoning of wells;

•transportation of materials and equipment to and from the well sites and facilities;

•transportation and disposal of produced fluids and natural gas; and

•notice to surface owners and other third parties.

Sale and Transportation of Gas and Oil

At the federal level, PHMSA regulates hazardous liquid and natural gas pipelines and pipeline facilities, including associated storage, pursuant to the Hazardous Liquids Pipeline Safety Act of 1979, as amended (the “HLPSA”), and the Natural Gas Pipeline Safety Act of 1968, as amended (the “NGPSA”). Federal regulations implementing the HLPSA and NGPSA establish minimum safety standards for pipeline transportation applicable to owners or operators of pipeline facilities regarding the design, installation, inspection, emergency plans and procedures, testing, construction, extension, operation, replacement, and maintenance of pipeline facilities. Among other things, these regulations require pipeline operators to conduct extensive emergency incident response training for pipeline personnel, including spill response drills for hazardous liquids pipelines. These regulations also require pipeline operators to develop and maintain a written qualification program for individuals performing covered tasks on pipeline facilities.

As part of its authority, PHMSA regulates the safety of pipeline transportation in or affecting interstate or foreign commerce. The Santa Ynez Pipeline System is subject to regulation by PHMSA.

Opposition from community members or state and local government officials to pipeline infrastructure could delay or prevent us from obtaining permits required for the operation of or updates made to the Santa Ynez Pipeline System.

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PHMSA has broad authority to investigate potential compliance issues, issue requests for information, inspect pipelines facilities, and issue enforcement. PHMSA’s enforcement authority includes the ability to issue corrective actions, which may include the shut down or restriction of the operation pressure of a pipeline pending completion of the corrective measures. Federal pipeline safety regulations include reporting, design, construction, testing, operations and maintenance, qualification, corrosion control, and other minimum requirements.

Operators are required to prepare procedural manuals to implement these minimum requirements and those procedures are enforceable by PHMSA.

PHMSA updates the maximum administrative civil penalties each year to account for inflation, and as of January 2025, the penalty limits are up to $272,926 per violation per day and up to $2,729,245 for a related series of violations.

PHMSA is active in proposing and finalizing additional regulations for natural gas and hazardous liquids pipelines. For example, in October 2019 PHMSA finalized new regulations for hazardous liquid pipelines that significantly extend and expand the reach of certain PHMSA integrity management requirements (i.e., periodic assessments, repairs and leak detection), regardless of the pipeline’s proximity to a high consequence area (“HCA”). The final rule also requires all pipelines in or affecting an HCA to be capable of accommodating in-line inspection tools within the next 20 years. In addition, the final rule extends annual and accident reporting requirements to gravity lines and all liquids gathering lines and also imposes inspection requirements on pipelines in areas affected by extreme weather events and natural disasters, such as hurricanes, landslides, floods, earthquakes, or other similar events that are likely to damage infrastructure.

In addition, in April 2016, PHMSA proposed a rule regarding the safety of natural gas transmission pipelines and gas gathering pipelines. This proposed rule resulted in three separate final rules applicable to natural gas pipelines: (1) an October 2019 final rule on the natural gas transmission lines focused on material verification and maximum allowable operating pressure reconfirmation; (2) a November 2021 final rule applicable to onshore gas gathering lines; and (3) an August 24, 2022 final rule applicable to gas transmission lines with a focus on repair criteria and corrosion. Under the final November 2021 rules applicable to gas gathering lines, operators of certain onshore natural gas gathering pipelines that were previously excluded from certain PHMSA regulations face additional testing, safety and reporting requirements or may be forced to reduce their allowable operating pressures, which would reduce the amount of capacity available to us. Certain reporting requirements arising from the new PHMSA gas gathering rule took effect in May 2022, with additional requirements taking effect later in 2022 and 2023. Other recent rules include an April 8, 2022 final rule requiring installation of remote control or automatic shutoff valves (or equivalent technology) on certain newly constructed or entirely replaced onshore transmission pipelines, gathering pipelines (liquid and gas), and hazardous liquids pipelines.

In May 2023, PHMSA also issued a notice of proposed rulemaking that proposes to implement new and additional leak detection and repair requirements for natural gas pipelines. This proposed rule seeks to reduce methane emissions associated with the operation of natural gas pipelines by strengthening leakage survey and patrolling requirements, imposing an advanced leak detection program performance standard, implementing grading and repair schedules for identified leaks, requiring operators to reduce intentional sources of methane emissions, and expanding reporting requirements for methane emissions. PHMSA issued a final rule on January 17, 2025, but it has not been published in the Federal Register and was subject to President Trump’s January 20, 2025 “Regulatory Freeze Pending Review”. Thus, implementation of a final rule regarding gas pipeline leak detection and repair is uncertain at this time.

Federal and state legislative and regulatory initiatives relating to pipeline safety that require the use of new or more stringent safety controls or result in more stringent enforcement of applicable legal requirements could subject us to increased capital costs, operational delays and costs of operation.

Anti-Market Manipulation Laws and Regulations

Our sales of oil and natural gas are also subject to anti-manipulation and anti-disruptive practices authority under (i) the Commodity Exchange Act (“CEA”) and regulations promulgated thereunder by the CFTC, and (ii) the Energy Independence and Security Act of 2007 (“EISA”) and regulations promulgated thereunder by the FTC. The CEA prohibits any person from using or employing any manipulative or deceptive device in connection with any swap, or a contract for sale of any commodity, or for future delivery on such commodity, in contravention of the CFTC’s rules and regulations. It also prohibits knowingly delivering or causing to be delivered false, misleading or inaccurate reports concerning market information or conditions that affect or tend to affect the price of any commodity. The FTC’s Petroleum Market Manipulation Rule, issued pursuant to EISA, prohibits fraudulent or deceptive conduct (including false or misleading statements of material fact) in connection with wholesale purchases or sales of crude oil or refined petroleum products.

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Under both the CEA and the EISA, fines for violations can be up to $1,000,000 per day per violation (subject to adjustment for inflation) and certain knowing or willful violations may also lead to a felony conviction.

Derivatives Regulation

The Dodd-Frank Act directed the Commodities Futures Trading Commission (“CFTC”) to regulate certain markets for derivative products, including over-the-counter derivatives. Among other mandates, the CFTC has issued several new relevant regulations and rulemakings that require significant portions of the derivatives markets to clear through clearinghouses. While some of these rules have been finalized, some have not and the final form and timing of those rules remain uncertain.

In January 2020, the CFTC withdrew prior proposals and issued a new proposed rule, which includes limits on positions in (1) certain “Core Referenced Futures Contracts,” including contracts for several energy commodities; (2) futures and options on futures that are directly or indirectly linked to the price of a Core Referenced Futures Contract, or to the same commodity for delivery at the same location as specified in that Core Referenced Futures Contract; and (3) economically equivalent swaps. The proposal also includes exemptions from position limits for bona fide hedging activities. The proposal is not yet final and it remains subject to public comment and revision by the CFTC. Consequently, the potential impact of the proposed rule on us and our counterparties is uncertain at this time.

The Dodd-Frank Act and new related regulations may prompt potential derivative counterparties to spin off some of their derivatives activities to separate and less creditworthy entities. Any new regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure existing derivative contracts, and increase its exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the regulations, its results of operations may become more volatile and its cash flows may become less predictable, which could adversely affect its ability to plan for and fund capital expenditures and to generate sufficient cash flow to pay dividends. Its revenues could be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material, adverse effect on our financial condition and results of operations. Our use of derivative financial instruments does not eliminate its exposure to fluctuations in commodity prices and interest rates and could in the future result in financial losses or reduce its income.

Additional proposals and proceedings that may affect the crude oil and natural gas industry are pending before the U.S. Congress, federal agencies and the courts. We cannot predict the ultimate impact these proposals may have on its crude oil and natural gas operations, but it does not expect to be affected differently than its competitors.

State Regulation of Oil and Gas Operations

The State of California also regulates the drilling for, and the production, gathering and sale of, oil and natural gas, and imposes taxes and drilling permit requirements. Among other things, the State of California also regulates the method of developing new fields, the spacing and operation of wells and the prevention of waste of natural gas resources. It does not regulate wellhead prices or engage in other similar direct economic regulation, but there can be no assurance that it will not do so in the future. The effect of these regulations may be to limit the amount of oil and natural gas that may be produced from our wells and to limit the number of wells or locations it can drill. The State of California has significantly increased the jurisdiction, duties and enforcement authority of CalGEM, the SLC and other state agencies with respect to oil and natural gas activities in recent years, and CalGEM and other state agencies have also significantly revised their regulations, regulatory interpretations and data collection and reporting requirements. In addition, from time to time legislation has been introduced in the California Legislature seeking to further restrict or prohibit certain oil and gas operations. For additional information see “Risk Factors—Attempts by the California state government to restrict the production of oil and gas could negatively impact our operations and result in decreased demand for fossil fuels in California.”

The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to resource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect on us.

Human Capital

Overview

As of December 31, 2025, we have approximately 200 employees, none of whom are represented by labor unions or covered by collective bargaining agreements. Under EM management, approximately 32 employees were previously represented by labor unions or covered by collective bargaining agreements prior to February 15, 2024. We strive to create

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a high-performing culture and positive work environment that allows us to attract and retain a diverse group of talented individuals who contribute to our success. To attract and retain top talent, our human resources programs are designed to reward and incentivize our employees through competitive compensation practices, our commitment to employee health and safety, training and talent development.

Safety

Safety is our highest priority and we are dedicated to the well-being of our employees, contractors, business partners, stakeholders and the environment. We promote safety with a robust health and safety program, which includes employee orientation and training, contractor management, risk assessments, hazard identification and mitigation, audits, incident reporting and investigation, and corrective and preventative action development.

In addition, we employ environmental, health and safety personnel at each of our asset locations, who provide in-person safety training and regular safety meetings. We also utilize learning management software to provide safety training on a variety of topics, and we contract with third-party technical experts as needed to facilitate training on specialized topics that are unique to each of our areas of operation.

Compensation

We operate in a highly competitive environment and designed its compensation program to attract, retain and motivate talented and experienced individuals. Its compensation philosophy is designed to align its workforce’s interests with those of its stakeholders and to reward them for achieving its business and strategic objectives and driving stockholder value. We consider competitive market compensation paid by our peers and other companies comparable to us in size, geographic location and operations in order to ensure compensation remains competitive and fulfills the goal of recruiting and retaining talented employees.

Training and Development

We are committed to the training and development of our employees. Employees are regularly provided training opportunities to develop skills in leadership, safety, and technical acumen, which bolster our efforts in conducting business in a safe manner and with high ethical standards. Further, supporting our employees in achieving their career and development goals is a key element of our approach to attracting and retaining top talent. We encourage our employees to advance their knowledge and skills and to network with other professionals in order to pursue career advancement and potential future opportunities with us. Our employees are able to attend training seminars and off-site workshops and to join professional associations that will enable them to remain up-to-date on the latest changes and best practices in their respective fields.

Health and Wellness

We support our employees and their families by offering a robust package of health and welfare benefits, medical, dental, and vision insurance plans for employees and their families, life insurance and long-term disability plans, paid time off for holidays, vacation, sick leave, and other personal leave, and health and dependent care savings accounts. We also provide our employees with a 401(k) plan that includes a competitive company match, and employees have access to a variety of resources and services to help them plan for retirement.

In addition to these programs, we have several other programs designed to further promote the health and wellness of its employees, as well as an employee assistance program that offers counseling and referral services for a broad range of personal and family situations.

Available Information

Through our corporate website at http://www.sableoffshore.com, you can access electronic copies of our governing documents free of charge, including our Corporate Governance Guidelines and the charters of the committees of our board of directors. In addition, through our website, you can access the documents we file with the SEC, including our annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K, and all amendments thereto, as soon as reasonably practicable after we file or furnish them. Investors and others should note that we routinely announce information material to investors and the marketplace using SEC filings, press releases and our website. While not all of the information that we post to our website is of a material nature, some information could be deemed to be material. Accordingly, we encourage investors, the media and others interested in Sable to review the information that we share on our website. Information contained on our website is not incorporated herein by reference and should not be considered part of this report.

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In addition, the SEC maintains an Internet site (www.sec.gov) that contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC.