UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K | ||||||||||||||
(Mark One)
| x | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | ||||
For the fiscal year ended December 31, 2025
| o | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | ||||
For the transition period from _________ to _________
Commission File No. 001-40111
SABLE OFFSHORE CORP.
(Exact name of registrant as specified in its charter)
| Delaware | 85-3514078 | |||||||
| (State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) | |||||||
845 Texas Avenue, Suite 2920 Houston, TX | 77002 | |||||||
(Address of principal executive offices) | (Zip Code) | |||||||
(713) 579-6161 | ||||||||
| (Registrant’s telephone number, including area code) | ||||||||
Securities registered pursuant to Section 12(b) of the Act:
| Title of each class | Trading Symbol(s) | Name of each exchange on which registered | ||||||||||||
| Common Stock, par value $0.0001 per share | SOC | The New York Stock Exchange | ||||||||||||
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.☐ Yes x No
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. ☐ Yes x No
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No o
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes x No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
| Large accelerated filer | x | Accelerated filer | o | |||||||||||
| Non-accelerated filer | o | Smaller reporting company | o | |||||||||||
| Emerging growth company | o | |||||||||||||
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. x
If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐
Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant's executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act): Yes o No x
The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant was approximately $1.2 billion as of June 30, 2025 (based on the closing stock price of such stock as quoted on the New York Stock Exchange).
As of February 26, 2026, there were 147,244,086 shares of Common Stock, $0.0001 par value, issued and outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of Sable Offshore Corp.’s Proxy Statement for the 2026 Annual Meeting of Stockholders are incorporated by reference in
Part III of this Form 10-K.
SABLE OFFSHORE CORP.
FORM 10-K
FOR THE YEAR ENDED DECEMBER 31, 2025
TABLE OF CONTENTS
| PAGE | ||||||||
i
CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS
Some of the statements contained in this annual report may constitute “forward-looking statements” for purposes of the federal securities laws. Our forward-looking statements include, but are not limited to, statements regarding our or our management team’s expectations, hopes, beliefs, intentions or strategies regarding the future. In addition, any statements that refer to projections, forecasts or other characterizations of future events or circumstances, including any underlying assumptions, are forward-looking statements. The words “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “intends,” “may,” “might,” “plan,” “possible,” “potential,” “predict,” “project,” “should,” “would” and similar expressions may identify forward-looking statements, but the absence of these words does not mean that a statement is not forward-looking. Forward-looking statements in this annual report may include, for example, statements about:
•our ability to recommence full production of the SYU Assets (as defined below), including bringing oil to market, and the cost and time required therefor, and production levels once recommenced;
•our financial performance;
•our ability to satisfy future cash obligations;
•restrictions in existing or future debt agreements or structured or other financing arrangements;
•commodity price volatility, low prices for oil and/or natural gas, global economic conditions, inflation, increased operating costs, lack of availability of drilling and production equipment, supplies, services and qualified personnel, processing volumes and pipeline throughput;
•uncertainties related to new technologies, geographical concentration of operations, environmental risks, weather risks, security risks, drilling and other operating risks, regulatory changes and regulatory risks;
•the uncertainty inherent in estimating oil and natural gas resources and in projecting future rates of production;
•reductions in cash flow and lack of access to capital;
•the timing of development expenditures, managing growth and integration of acquisitions, and failure to realize expected value creation from acquisitions;
•the ability to recognize the anticipated benefits of the Business Combination (as defined below), which may be affected by, among other things, our ability to grow and manage growth profitably, maintain relationships with customers and compete within our industry;
•our success in retaining or recruiting, or changes required in, our officers, directors or other key personnel;
•our officers and directors allocating their time to other businesses and potentially having conflicts of interest with our business;
•developments relating to our competitors and our industry;
•the possibility that we may be adversely impacted by other economic, business, and/or competitive factors;
•litigation, complaints and/or adverse publicity;
•privacy and data protection laws, privacy or data breaches, or the loss of data;
•our ability to maintain the listing of our Common Stock on the NYSE;
•our ability to comply with laws and regulations applicable to our business;
•changes in applicable laws or regulations; and
•other risks and uncertainties described in this annual report, including those under the section titled “Risk Factors.”
The forward-looking statements contained in this annual report are based on our current expectations and beliefs concerning future developments and their potential effects on us. There can be no assurance that future developments affecting us will be those that we have anticipated. These forward-looking statements involve a number of risks,
ii
uncertainties (some of which are beyond our control) or other assumptions that may cause actual results or performance to be materially different from those expressed or implied by these forward-looking statements. These risks and uncertainties include, but are not limited to, those factors described under the section of this annual report entitled “Risk Factors.” Should one or more of these risks or uncertainties materialize, or should any of our assumptions prove incorrect, actual results may vary in material respects from those projected in these forward-looking statements. We undertake no obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required under applicable securities laws.
iii
PART I
Item 1. Business
References in this section to “we,” “our” and “us” generally refer to Legacy Sable prior to the Business Combination and Sable after the Business Combination.
Overview
Sable Offshore Corp. (“Sable”) (formerly known as Flame Acquisition Corp. or “Flame”) was a blank check company originally incorporated on October 16, 2020 as a Delaware corporation for the purpose of effecting a merger, share exchange, asset acquisition, share purchase, reorganization or other similar business combination with one or more businesses or entities. On March 1, 2021, Flame consummated an initial public offering (the “Flame IPO”), after which its securities began trading on the New York Stock Exchange (“NYSE”). On November 2, 2022, Flame entered into that certain Agreement and Plan of Merger (the “Merger Agreement”), dated November 2, 2022 (amended on December 22, 2022 and June 30, 2023), by and among Flame, Sable Offshore Holdings LLC, a Delaware limited liability company (“Holdco”), and Sable Offshore Corp., a Texas corporation and a wholly owned subsidiary of Holdco (“Legacy Sable”).
Legacy Sable entered into a Purchase and Sale Agreement (as amended, the “Sable-EM Purchase Agreement”) on November 1, 2022 with Exxon Mobil Corporation (“Exxon”) and Mobil Pacific Pipeline Company (“MPPC,” and together with Exxon, “EM”) pursuant to which Legacy Sable agreed to acquire from EM certain assets constituting the Santa Ynez field in Federal waters offshore California and associated onshore processing and pipeline assets (such “Assets,” as defined in the Sable-EM Purchase Agreement, the “SYU Assets”).
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
1
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.
2
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
3
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
4
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.
5
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
6
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
7
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
8
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.
9
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
10
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.
11
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
12
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.
13
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
14
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
15
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.
16
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
17
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
18
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.
19
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.
20
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
21
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.
22
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.
Item 1A. Risk Factors
You should carefully consider the following risks as well as the other information included in this annual report, including the section titled “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our financial statements and related notes thereto. Any of the following risks could materially and adversely affect our business, financial condition or results of operations. However, the selected risks described below are not the only risks facing us. Additional risks and uncertainties not currently known to us or those we currently view to be immaterial may also materially and adversely affect our business, financial condition or results of operations.
Risk Factors Summary
The following is a summary of the principal risks and uncertainties described in more detail in this annual report:
•The requirements to resume petroleum transportation through Pipeline Segments 324 and 325 include those set forth in a Consent Decree with federal and state agencies. While the operator of the Pipeline Segments believes it has satisfied all of the conditions to resuming petroleum transportation included under the Consent Decree, there is no assurance that we will be successful in resuming petroleum transportation through Pipeline Segments 324 and 325 and recommence oil sales in a timely manner.
•In order to commence operations pursuant to the OS&T Strategy, we will require clearances and permitting, including from BOEM.
•The timing of returning wells to production is subject to risks that may cause delays and initial production rates are expected to decline.
•Our assumptions and estimates regarding the total costs associated with recommencing oil sales may be inaccurate.
•There is no guarantee that we will have sufficient cash to recommence oil sales.
•Oil, natural gas and natural gas liquids, or “NGL(s)”, prices are volatile, due to factors beyond our control, and greatly affect our business, results of operations and financial condition. Any decline in, or sustained low levels of, oil, natural gas and NGL prices will cause a decline in our cash flow from operations, which could materially and adversely affect our business, results of operations and financial condition.
•If commodity prices decline and remain depressed for a prolonged period, our business may become uneconomical and result in additional write downs of the value of our properties, which may adversely affect our financial condition and our ability to fund operations.
•An increase in the differential between the NYMEX or other benchmark prices of oil and natural gas and the wellhead price we expect to receive for our future oil sales could significantly reduce our cash flow and adversely affect our financial condition.
•The estimated quantities of petroleum contained in the SYU Assets are classified as “contingent resources” 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.”
•Developing and producing oil, natural gas and NGLs are costly and high-risk activities with many uncertainties that may result in a total loss of investment or otherwise adversely affect our business, financial condition, results of operations and cash flows. Many of these risks are heightened for us due to the fact that some of our equipment has not been used for petroleum production or transportation for more than ten years.
•The enactment of derivatives legislation could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.
•Development and production of oil, natural gas and NGLs in offshore waters have inherent and historically higher risk than similar activities onshore.
23
•Oil and natural gas producers’ operations are substantially dependent on the availability of water and the disposal of waste, including produced water and drilling fluids. Restrictions on the ability to obtain water or dispose of waste may impact our operations.
•The unavailability or high cost of rigs, equipment, supplies and crews could delay our operations, increase our costs and delay forecasted revenue.
•The third parties on whom we rely for transportation services are subject to complex federal, state and other laws that could adversely affect the cost, manner or feasibility of conducting our business.
•Our business depends in part on pipelines, gathering systems and processing facilities owned by us or others. Any limitation in the availability of those facilities could interfere with our ability to market our oil, natural gas and NGL production.
•We may incur losses as a result of title defects or deficiencies in our properties.
•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.
•Under the terms of the Senior Secured Term Loan, the loans thereunder will mature on the earlier of (i) March 31, 2027 or (ii) the date falling 90 days after first sales of Hydrocarbons, and the terms on which we will be able to refinance the Senior Secured Term Loan will depend on then-prevalent market conditions.
•Restrictive covenants in the Senior Secured Term Loan or any future agreements governing our indebtedness could limit our growth and our ability to finance our operations, fund our capital needs, respond to changing conditions and engage in other business activities that may be in our best interests.
•Our business plans require a significant amount of capital. In addition, our future capital needs may require us to issue additional equity or debt securities that may dilute our stockholders or introduce covenants that may restrict our operations or ability to pay dividends.
•We are subject to complex federal, state, local and other laws, regulations and permits that could adversely affect the cost, manner, ability or feasibility of conducting our operations.
•Climate change legislation or regulations restricting emissions of “greenhouse gases,” or GHGs, could result in increased operating costs and reduced demand for the oil, natural gas and NGLs we expect to produce.
•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.
•Our assets are located exclusively onshore and offshore in California, making us vulnerable to risks associated with having operations concentrated in this geographic area.
•All of our operations are conducted in areas that may be at risk of damage from fire, mudslides, earthquakes or other natural disasters.
•We may be required to post cash collateral pursuant to our agreements with sureties, letter of credit providers or regulators under our existing or future bonding or other arrangements, which may have a material adverse effect on our liquidity and our ability to execute our capital expenditure plan and our asset retirement obligation plan and comply with the agreements governing our existing or future indebtedness.
•Our business could be negatively affected by security threats, including cybersecurity threats, destructive forms of protest and opposition by activists and other disruptions.
•The market prices of our securities could be highly volatile or may decline regardless of our operating performance. You may lose some or all of your investment.
24
Risks Related to Recommencing Oil Sales
The requirements to resume petroleum transportation through Pipeline Segments 324 and 325 include those set forth in a Consent Decree with federal and state agencies. While the operator of the Pipeline Segments believes it has satisfied all of the conditions to resuming petroleum transportation included under the Consent Decree, there is no assurance that we will be successful in resuming petroleum transportation through Pipeline Segments 324 and 325 and recommence oil sales in a timely manner.
Production from the SYU Assets was suspended as a result of the Line 901 incident and consequent suspension of service. In May 2025 we restarted production from the SYU Assets and resumed petroleum transportation through the Santa Ynez Pipeline System. However, absent OS&T offtake, our business depends on resuming petroleum transportation through Pipeline Segments 324 and 325. We are required to satisfy certain requirements related to Pipeline Segments 324 and 325 before we can recommence oil sales. Such requirements include conditions set forth in a U.S. federal district court Consent Decree executed by Plains and relevant U.S. and State of California government agencies. Sable believes all such requirements have been satisfied. However, there is no guarantee that the State of California government agencies will agree that such requirements have been met, which may delay or interrupt our operations and limit our growth and revenue, or may impact our ability to repay or refinance the Senior Secured Term Loan. On January 14, 2026, both Plains and the Company submitted letters 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, however, there is no guarantee these parties will agree the prerequisites have been satisfied and terminate the Consent Decree. See “Risk Factors—Under the terms of the Senior Secured Term Loan, the loans thereunder will mature on the earlier of (i) March 31, 2027 or (ii) the date falling 90 days after first sales of Hydrocarbons, and the terms on which we will be able to refinance the Senior Secured Term Loan will depend on then-prevalent market conditions.”
In order to commence operations pursuant to the OS&T Strategy, we will require clearances and permitting, including from BOEM.
We may experience delays in obtaining or be unable to obtain required permits, including authorizations necessary to recommence oil sales pursuant to the OS&T Strategy, which may delay or interrupt our operations and limit our growth and revenue, or may impact our ability to repay or refinance the Senior Secured Term Loan. In particular, prior to implementation of the OS&T Strategy, regulatory authorizations are required, including clearance from BOEM. If we do not receive regulatory clearances in connection with the OS&T Strategy in a timely manner, we may not be able to reach commercial sales on our estimated timeline of the fourth quarter of 2026.
While the previous operator of the SYU was able to utilize the OS&T Strategy to process SYU production in federal waters from 1981 to 1994 under previously issued permits, there is no assurance that we will be able to successfully obtain the agency clearance or permits required to recommence oil sales pursuant to the OS&T Strategy or that no additional state or federal clearances or permits will be required in the future.
The timing of returning wells to production is subject to risks that may cause delays and initial production rates are expected to decline.
We returned a number of wells to production on Platform Harmony beginning in May 2025, and we expect to return a number of additional wells to production on Platforms Harmony, Heritage and Hondo. Operations on offshore platforms are subject to numerous risks and potential delays.
In addition, oil and natural gas wells typically exhibit a decline in production over time. Accordingly, initial production rates as our wells are brought back into production are expected to be higher than the rate of sustained production at such wells. There is substantial uncertainty regarding the amount and timing of production decline from recently reopened wells.
Our assumptions and estimates regarding the total costs associated with recommencing oil sales may be inaccurate.
We currently estimate no remaining start-up expenses to recommence oil sales via the Santa Ynez Pipeline System, other than applicable legal expenses. If we instead pursue the OS&T Strategy, we currently estimate remaining start-up expenses of approximately $475.0 million to recommence offshore oil sales, excluding corporate working capital. The expenditures will primarily be directed towards preparing for the implementation of the OS&T Strategy, including the procurement of a suitable vessel and necessary upgrade and installation costs with respect to such vessel and our platforms, obtaining necessary regulatory approvals and recommencing oil sales in the fourth quarter of 2026. This estimate of costs to recommence oil sales considers currently available facts and presently enacted laws and regulations, but it is subject to uncertainties associated with the assumptions that we have made. For example, because the markets for OS&T vessels and
25
vessel refurbishment and upgrading are competitive, and our estimates for the cost of procurement and planned upgrades are based on our understanding of the relevant markets and current supply of suitable vessels and contracts, the actual cost of such a vessel and the related upgrades may exceed our expectations. In addition, the costs of equipment, repairs and maintenance, the costs of operating personnel, the costs to obtain governmental approvals, and legal, consulting and other professional expenses could turn out to be higher than we have estimated. In addition, commencement of sales pursuant to the OS&T Strategy may be delayed if additional financing is not procured in a timely fashion and therefore our capital expenditure plan is delayed. We may experience increases in costs and delays.
We are currently evaluating and pursuing the OS&T Strategy and have curtailed certain capital expenditures relating to the Santa Ynez Pipeline System. If in the future we are permitted to conduct commercial sales using such assets, we intend to do so and would incur such curtailed Santa Ynez Pipeline System costs, in addition to the costs related to the pursuit of the OS&T Strategy. Accordingly, our assumptions and estimates may change in future periods based on future events and total costs may materially increase. Therefore, we can provide no assurance that we will not have to incur additional costs in future periods that are significantly higher than our estimated costs to recommence oil sales.
There is no guarantee that we will have sufficient cash to recommence oil sales.
Until we recommence oil sales, either via the Santa Ynez Pipeline System or the OS&T Strategy, we will not generate any revenue or cash flows from operations and will rely on cash on hand to fund the operations necessary to recommence oil sales. If we do not have sufficient cash on hand to recommence oil sales, we may need to raise additional capital to continue our operations, and this capital may not be available on acceptable terms or at all. If we do not have sufficient cash on hand or are unable to obtain additional funding on a timely basis, we may be unable to recommence oil sale, which could materially affect our business, financial condition and results of operations.
Risks Related to the Business of the Company
Oil, natural gas and natural gas liquids, or “NGL(s)”, prices are volatile, due to factors beyond our control, and greatly affect our business, results of operations and financial condition. Any decline in, or sustained low levels of, oil, natural gas and NGL prices will cause a decline in our cash flow from operations, which could materially and adversely affect our business, results of operations and financial condition.
Our revenues, operating results, profitability, liquidity, future growth and the value of our assets depend primarily on prevailing commodity prices. Historically, oil and natural gas prices have been volatile and fluctuate in response to changes in supply and demand, market uncertainty, and other factors that are beyond our control, including:
•the regional, domestic and foreign supply of oil, natural gas and NGLs;
•the level of commodity prices and expectations about future commodity prices;
•the level of global oil and natural gas exploration and production;
•localized supply and demand fundamentals, including the proximity and capacity of pipelines and other transportation facilities, and other factors that result in differentials to benchmark prices from time to time;
•the cost of exploring for, developing, producing and transporting oil, natural gas and NGLs;
•the price and quantity of foreign imports;
•political and economic conditions in oil producing countries, including conflicts in or among the Middle East, Africa, South America and Russia;
•the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;
•speculative trading in crude oil and natural gas derivative contracts;
•the level of consumer product demand;
•weather conditions and other natural disasters;
•risks associated with operating drilling rigs;
•technological advances affecting exploration and production operations and overall energy consumption;
26
•domestic and foreign governmental regulations and taxes;
•the impact of energy conservation efforts;
•the continued threat of terrorism and the impact of military and other action, including the Russia-Ukraine war and its destabilizing effect on the European continent and the global oil and natural gas markets;
•the price and availability of competitors’ supplies of oil and natural gas and alternative fuels; and
•overall domestic and global economic conditions.
These factors and the volatility of the energy markets make it extremely difficult to predict future oil, natural gas and NGL price movements with any certainty. For example, for the five years ended December 31, 2025, the NYMEX-Brent oil futures price ranged from a high of $127.98 per Bbl on March 8, 2022 to a low of $51.09 per Bbl January 4, 2021, while the NYMEX-Henry Hub natural gas futures price ranged from a high of $9.68 per MMBtu on August 22, 2022 to a low of $1.58 per MMBtu on March 26, 2024. For the year ended December 31, 2025, the NYMEX-Brent oil futures price ranged from a high of $82.03 per Bbl on January 15, 2025 to a low of $58.92 per Bbl on December 16, 2025 and the NYMEX-Henry Hub natural gas futures price ranged from a high of $5.29 per MMBtu on December 5, 2025 to a low of $2.70 per MMBtu on August 25, 2025. Likewise, NGLs, which are made up of ethane, propane, isobutane, normal butane and natural gasoline, each of which has different uses and different pricing characteristics, have sustained depressed realized prices during this period and are generally correlated with the price of oil. While recent events have led to elevated oil, natural gas and NGL prices, an extended decline in commodity prices could materially and adversely affect our business, results of operations and financial condition.
If commodity prices decline and remain depressed for a prolonged period, our business may become uneconomical and result in additional write downs of the value of our properties, which may adversely affect our financial condition and our ability to fund operations.
Oil, natural gas and NGL prices have experienced significant volatility over the past few years. An extended decline in commodity prices could render our business uneconomical and result in a downward adjustment of our assets, which would reduce our ability to fund our operations. An extended decline, or sustained marked uncertainty, in commodity prices may cause us to write down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties for impairments. We may in the future incur impairment charges that could have a material adverse effect on our results of operations in the period taken. Sustained declines or uncertainty in commodities prices may adversely affect our financial condition, results of operations, ability to reduce debt, ability to pay dividends and the timing of our capital projects.
An increase in the differential between the NYMEX or other benchmark prices of oil and natural gas and the wellhead price we expect to receive for our future oil sales could significantly reduce our cash flow and adversely affect our financial condition.
The prices that we expect to receive for our future sales will often reflect a regional discount, based on the location of production, to the relevant benchmark prices, such as NYMEX or ICE, that are used for calculating hedge positions. The prices we expect to receive for our future sales are also affected by the specific characteristics of the production relative to production sold at benchmark prices. For example, California oil typically has a lower gravity, and a portion typically has higher sulfur content, than oil sold at certain benchmark prices. Therefore, because our oil will likely require more complex refining equipment to convert it into high value products, it may sell at a discount to those prices. These discounts, if significant, could reduce our cash flows and adversely affect our results of operations and financial condition.
The estimated quantities of petroleum contained in the SYU Assets are classified as “contingent resources” 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) approval and/or inspection from federal, state and local regulators to recommence oil sales, (2) reestablishment of oil transportation systems to deliver production to market and (3) commitment to restart the 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.
27
Our hedging strategy in the future may not effectively mitigate the impact of commodity price volatility from our cash flows, and our hedging activities could result in cash losses and may limit potential gains.
We expect that we will develop and maintain a portfolio of commodity derivative contracts covering a specified percentage or range of our estimated production from proved developed producing reserves over a one-to-three-year period at any given point in time. These commodity derivative contracts may include natural gas, oil and NGL financial swaps. The prices and quantities at which we enter into commodity derivative contracts covering our production in the future will be dependent upon oil and natural gas prices and price expectations at the time we enter into these transactions, which may be substantially higher or lower than current or future oil and natural gas prices. Accordingly, our price hedging strategy may not protect us from significant declines in oil, natural gas and NGL prices received for our future production. Many of the derivative contracts to which we will be a party will require us to make cash payments to the extent the applicable index exceeds a predetermined price, thereby limiting our ability to realize the benefit of increases in oil, natural gas and NGL prices. If our actual production and sales for any period are less than our hedged production and sales for that period (including reductions in production due to operational delays) or if we are unable to perform our drilling activities as planned, we might be forced to satisfy all or a portion of our hedging obligations without the benefit of the cash flow from our sale of the underlying physical commodity, which may materially impact our liquidity.
Developing and producing oil, natural gas and NGLs are costly and high-risk activities with many uncertainties that may result in a total loss of investment or otherwise adversely affect our business, financial condition, results of operations and cash flows. Many of these risks are heightened for us due to the fact that some of our equipment has not been used for petroleum production or transportation for more than ten years.
Our development and production operations may be curtailed, delayed, canceled or otherwise negatively impacted as a result of many factors, including:
•high costs, shortages or delivery delays of rigs, equipment, labor, electrical power or other services;
•unusual or unexpected geological formations;
•composition of sour natural gas, including sulfur, carbon dioxide and other diluent content;
•unexpected operational events and conditions;
•failure of down hole equipment and tubulars;
•loss of wellbore mechanical integrity;
•failure, unavailability or shortage of capacity of gathering and transportation pipelines, or other transportation facilities;
•human errors, facility or equipment malfunctions and equipment failures or accidents, including acceleration of deterioration of our facilities and equipment due to the highly corrosive nature of sour natural gas;
•excessive wall loss or other loss of pipeline integrity;
•title problems;
•litigation, including landowner lawsuits;
•loss of drilling fluid circulation;
•hydrocarbon or oilfield chemical spills;
•fires, blowouts, surface craterings and explosions;
•surface spills or underground migration due to uncontrollable flows of oil, natural gas, formation water or well fluids;
•delays imposed by or resulting from compliance with environmental and other governmental or regulatory requirements;
•delays due to operations in environmentally sensitive areas; and
28
•adverse weather conditions and natural disasters.
Many of these risks are heightened for us due to the fact that some of our equipment has not been used for petroleum production or transportation for more than ten years. Any of these risks can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination or loss of wells and other regulatory penalties. In the event that planned operations are delayed or canceled, or existing wells or development wells have lower than anticipated production due to one or more of the factors above or for any other reason, our financial condition and results of operations may be adversely affected. If any of these factors were to occur with respect to a particular field, we could lose all or a part of our investment in the field or we could fail to realize the expected benefits from the field, either of which could materially and adversely affect our business, financial condition, results of operations and cash flows.
The enactment of derivatives legislation could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.
The Dodd-Frank Wall Street Reform and Consumer Protection Act (“Dodd-Frank Act”), enacted in 2010, establishes federal oversight and regulation of, among other things, the over-the-counter derivatives market and certain participants in that market, including us. Rules and regulations applicable to over-the-counter derivatives transactions may affect both the size of positions that we may hold and the ability or willingness of counterparties to trade opposite us, potentially increasing costs for transactions. Moreover, such changes could materially reduce our hedging opportunities which could adversely affect our revenues and cash flow during periods of low commodity prices. While many Dodd-Frank Act regulations are already in effect, the rulemaking and implementation process is ongoing, and the ultimate effect of the adopted rules and regulations and any future rules and regulations on our business remains uncertain. See “Business—Other Regulation of the Oil and Natural Gas Industry-Derivatives Regulation” for additional information.
Development and production of oil, natural gas and NGLs in offshore waters have inherent and historically higher risk than similar activities onshore.
Our offshore operations are subject to a variety of operating risks specific to the marine environment, such as a dependence on a limited number of electrical transmission lines, as well as capsizing, collisions and damage or loss from adverse weather conditions. Offshore activities are subject to more extensive governmental regulation than onshore oil and natural gas activities. We are vulnerable to the risks associated with operating offshore California, including risks relating to:
•impacts of climate change and natural disasters such as earthquakes, tidal waves, mudslides, fires and floods;
•oil field service costs and availability;
•compliance with environmental and other laws and regulations;
•third-party marine vessels;
•response capabilities for personnel, equipment and environmental incidents;
•remediation and other costs resulting from oil spills, releases of hazardous materials and other environmental and natural resource damages; and
•failure of equipment or facilities.
In addition to lost production and increased costs, these hazards could cause serious injuries, fatalities, contamination or property damage for which we could be held responsible. The potential consequences of these hazards are particularly severe for us because significant portions of our offshore operations are conducted in environmentally sensitive areas, including areas with significant residential populations and public and commercial infrastructure. An accidental oil spill or release on or related to offshore properties and operations could expose us to joint and several strict liability, without regard to fault, under applicable law for all containment and oil removal costs and a variety of public and private damages including, but not limited to, the costs of remediating a release of oil, natural resource damages, and economic damages suffered by persons adversely affected by an oil spill. If an oil discharge or substantial threat of discharge were to occur, we may be subject to regulatory scrutiny and liable for costs and damages, which costs and damages could be material to our business, financial condition or results of operations and could subject us to criminal and civil penalties. Finally, maintenance activities undertaken to reduce operational risks can be costly and can require exploration, exploitation and development operations to be curtailed while those activities are being completed.
29
Oil and natural gas producers’ operations are substantially dependent on the availability of water and the disposal of waste, including produced water and drilling fluids. Restrictions on the ability to obtain water or dispose of waste may impact our operations.
Water is an essential component of oil and natural gas production during the drilling and production process. Our inability to locate sufficient amounts of water, or dispose of or recycle water used in our development and production operations, could adversely impact our operations. Moreover, the imposition of new environmental initiatives and regulations could include restrictions on our ability to conduct certain operations such as disposal of waste, including, but not limited to, produced water, drilling fluids and other wastes associated with the exploration, development or production of oil and natural gas. The Clean Water Act imposes restrictions and strict controls regarding the discharge of produced waters and other natural gas and oil waste into “waters of the United States.” Permits must be obtained to discharge pollutants to such waters and to conduct construction activities in such waters, which include certain wetlands. The Clean Water Act and similar state laws provide for civil, criminal and administrative penalties for any unauthorized discharges of pollutants and unauthorized discharges of reportable quantities of oil and other hazardous substances. State and federal discharge regulations prohibit the discharge of produced water and sand, drilling fluids, drill cuttings and certain other substances related to the natural gas and oil industry into coastal waters. Compliance with current and future environmental regulations and permit requirements governing the withdrawal, storage and use of surface water or groundwater necessary for the disposal and recycling of produced water, drilling fluids and other wastes may increase our operating costs and cause delays, interruptions or termination of our operations, the extent of which cannot be predicted. In addition, in some instances, the operation of underground injection wells for the disposal of waste has been alleged to cause earthquakes. In some jurisdictions, such issues have led to orders prohibiting continued injection or the suspension of drilling in certain wells identified as possible sources of seismic activity or resulted in stricter regulatory requirements relating to the location and operation of underground injection wells. Any orders or regulations addressing concerns about seismic activity from well injection in jurisdictions where we operate could affect our operations. See “Business—Environmental, Occupational Safety and Health Matters and Regulations-Water Discharges” for an additional description of the laws and regulations relating to the discharge of water and other wastes that affect us.
The unavailability or high cost of rigs, equipment, supplies and crews could delay our operations, increase our costs and delay forecasted revenue.
Our industry is cyclical, and historically there have been periodic shortages of rigs, equipment, supplies and crew. Sustained declines in oil and natural gas prices may reduce the number of service providers for such rigs, equipment, supplies and crews, contributing to or resulting in shortages. Alternatively, during periods of higher oil and natural gas prices, the demand for rigs, equipment, supplies and crews is increased and can lead to shortages of, and increasing costs for, development equipment, supplies, services and personnel. While we have mitigated some of these issues with our dedicated rig, shortages of, or increasing costs for, experienced development crews and oil field equipment and services could restrict our ability to drill the wells and conduct the operations that we currently have planned relating to the fields where our properties are located. In addition, some of our operations require supply materials for production, such as CO2, which could become subject to shortages and increased costs. Any delay in the development of new wells or a significant increase in development costs could reduce our revenues and impact our development plan, which would thus affect our financial conduction, results of operations and our cash flows.
The third parties on whom we rely for transportation services are subject to complex federal, state and other laws that could adversely affect the cost, manner or feasibility of conducting our business.
The operations of the third parties on whom we rely for transportation services are subject to complex and stringent laws and regulations that require obtaining and maintaining numerous permits, approvals and certifications from various federal, state and local government authorities. These third parties may incur substantial costs in order to comply with existing laws and regulations. If existing laws and regulations governing such third-party services are revised or reinterpreted, or if new laws and regulations become applicable to their operations, these changes may affect the costs that we pay for such services. Similarly, a failure to comply with such laws and regulations by the third parties on whom we rely for transportation services could impact the availability of those services. Any potential impact to the availability of transportation services could impact our ability to market and sell our production, which could have a material adverse effect on our business, financial condition and results of operations. See “Business—Environmental, Occupational Safety and Health Matters and Regulations” and “Business-Other Regulation of the Oil and Natural Gas Industry” for a description of the laws and regulations that affect the third parties on whom we rely for transportation services.
30
Our business depends in part on pipelines, gathering systems and processing facilities owned by us or others. Any limitation in the availability of those facilities could interfere with our ability to market our oil, natural gas and NGL production.
The marketability of our oil, natural gas and NGL production depends in part on the availability, proximity and capacity of pipelines and other transportation methods, gathering systems and processing facilities owned by us or third parties. The amount of oil, natural gas and NGLs that can be produced and sold is subject to curtailment in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, physical damage or lack of contracted capacity on such systems. For example, our ability to produce and sell oil from SYU will depend on the continued availability of the pipeline infrastructure between platforms, for delivery of that oil to shore, and for further delivery to market, and any unavailability of that pipeline infrastructure could cause us to shut in all or a portion of the production from the SYU Assets for the length of such unavailability. Our access to transportation options can also be affected by U.S. federal and state regulation of oil and natural gas production and transportation, general economic conditions and changes in supply and demand. The curtailments arising from these and similar circumstances may last from a few days to several months or more. In many cases, we are provided with only limited, if any, notice as to when these circumstances will arise and their duration. Any significant curtailment in gathering system or transportation or processing facility capacity could reduce our ability to market our oil and natural gas production and harm our business, financial condition, results of operations and cash flows. Additionally, recent petroleum refinery conversions and announcements of potential refinery closures in California could further impact our ability to market and transport our products efficiently.
Loss of our key executive officers or other key personnel, or an inability to attract and retain such officers and personnel, could negatively affect our business and, in one instance, could cause a default under the primary agreement governing our existing indebtedness.
Our future success depends on the skills, experience and efforts of our executive officers. The sudden loss of any of these executives’ services or our failure to appropriately plan for any expected executive succession could materially and adversely affect our business and prospects, as we may not be able to find suitable individuals to replace them on a timely basis, if at all. Additionally, we also depend on our ability to attract and retain qualified personnel to operate and expand our business. If we fail to attract or retain talented new employees, our business and results of operations could be negatively affected. Workers may choose to pursue employment with our competitors or in other fields. Additionally, the Senior Secured Term Loan requires that James C. Flores, our Chairman and Chief Executive Officer, remains directly and actively involved in the day-to-day management of our business, subject to the right of the holder of such indebtedness to approve his replacement, such approval not to be unreasonably withheld.
We may incur losses as a result of title defects or deficiencies in our properties.
The existence of a material title deficiency can render a lease worthless and can adversely affect our results of operations and financial condition. While we have done extensive title diligence in advance of the Business Combination and typically obtain title opinions prior to commencing drilling operations on a lease or in a unit, the failure of title or other defects or deficiencies may not be discovered until after a well is drilled, in which case we may lose the lease and the right to produce all or a portion of the minerals under the property.
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.
We do not own in fee 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. Rather, many of the properties or rights are derived from leases, surface use agreements, rights-of-way or other easement rights and, therefore, we will be subject to the possibility of more onerous terms or increased costs to retain necessary land access if we do not have valid rights-of-way or if such rights-of-way lapse or terminate. Some of the rights to land owned by third parties and governmental agencies are obtained for a specific period of time and under certain conditions. We believe that we will have obtained sufficient right-of-way grants from public authorities (subject to receipt of certain governmental permits and consents) and private parties for us to operate our business, and obtained court approval of a settlement expressly confirming those rights with the overwhelming majority of the private landowners in September 2024 (see Grey Fox Settlement, infra). However, at least one private landowner along sectors of Pipeline Segment 324 has continued to make claims that the easement agreements with it is no longer effective. Further, on May 8, 2025, 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 Pipeline Segment 325 within Gaviota State Park. Sable is also working with State Parks on the terms of a long-term easement agreement Our loss of any of these surface use agreements, rights-of-way or other
31
easement rights through lapse or failure to satisfy or maintain certain conditions could require us to cease operations on the affected land or find alternative locations for our operations at increased costs, any of which could have a material adverse effect on our business, financial condition and results of operations.
Under the terms of the Senior Secured Term Loan, the loans thereunder will mature on the earlier of (i) March 31, 2027 or (ii) the date falling 90 days after first sales of Hydrocarbons, and the terms on which we will be able to refinance the Senior Secured Term Loan will depend on then-prevalent market conditions.
The Senior Secured Term Loan will mature on the earlier of (i) March 31, 2027 or (ii) the date falling 90 days after first sales of Hydrocarbons (as defined in the Senior Secured Term Loan). Our ability to obtain any refinancing of the Senior Secured Term Loan, and the terms of any such refinancing, will depend on market conditions at the time of any such refinancing. There can be no assurance that we will be able to obtain such refinancing on terms commercially acceptable to us, or at all.
Restrictive covenants in the Senior Secured Term Loan or any future agreements governing our indebtedness could limit our growth and our ability to finance our operations, fund our capital needs, respond to changing conditions and engage in other business activities that may be in our best interests.
Restrictive covenants in the Senior Secured Term Loan impose significant operating and financial restrictions on us and our subsidiaries and we may be prevented from taking advantage of business opportunities that arise because of the limitations imposed on us by the Senior Secured Term Loan unless we gain EM’s consent. These restrictions limit our ability to, among other things:
•engage in mergers, consolidations, liquidations, or dissolutions;
•create or incur debt or liens;
•make certain debt prepayments;
•pay dividends, distributions, management fees or certain other restricted payments;
•make investments, acquisitions, loans, or purchase oil and gas properties;
•sell, assign, farm-out or dispose of any property;
•enter into transactions with affiliates;
•enter into, subject to certain exceptions, any agreement that prohibits or restricts liens securing the Senior Secured Term Loan, payments of dividends to us, or payment of debt owed to us and our subsidiaries; and
•change the nature of our business.
The Senior Secured Term Loan also contains representations and warranties, affirmative covenants, additional negative covenants and events of default (including a change of control), including a financial liquidity covenant that requires us to have not less than $25 million in unrestricted cash, measured at the end of each month. In addition, during the pendency of the Senior Secured Term Loan and in case of an event of default thereunder, EM may exercise all remedies at law or equity, and may foreclose upon substantially all of our assets and the assets of our subsidiaries, including, in the event of a deficiency, cash and any other assets not acquired from EM in the Business Combination to the extent constituting collateral under the applicable financing documents.
We may in the future refinance our existing indebtedness or incur new indebtedness at variable rates and without the option to pay interest in-kind, which would subject us to interest rate risk and could cause our debt service obligations to increase significantly.
The outstanding principal amount under our Senior Secured Term Loan bears interest at a fixed rate and we have the option of capitalizing the interest onto the principal rather than paying cash interest, but we may in the future refinance our existing indebtedness or incur new indebtedness with variable rates and mandatory cash interest payments, which would expose us to interest rate risk and additional liquidity burdens. If interest rates increase, our debt service obligations on the variable rate indebtedness would increase even if the principal amount remained the same, and our net income and cash available for servicing our indebtedness would decrease.
32
Our business plans require a significant amount of capital. In addition, our future capital needs may require us to issue additional equity or debt securities that may dilute our stockholders or introduce covenants that may restrict our operations or ability to pay dividends.
Our business and operations may consume resources faster than we anticipate. In the future, we may need to raise additional funds through the issuance of new equity or debt securities, or a combination thereof. Additional financing may not be available on favorable terms or at all. If adequate funds are not available on acceptable terms, we may be unable to fund our capital requirements. If we issue new debt, the debt holders would have rights senior to holders of our Common Stock to make claims on our assets and the terms of any debt could restrict our operations, including our ability to pay dividends on our Common Stock. If we issue additional equity securities or securities convertible into equity securities, existing stockholders will experience dilution and the new equity securities could have rights senior to those of our Common Stock. Because our decision to issue securities in any future offering will depend on market conditions and other factors beyond our control, we cannot predict or estimate the amount, timing or nature of our future offerings and their impact on the market price of our Common Stock.
We are exposed to trade credit risk in the ordinary course of our business activities.
We are exposed to risks of loss in the event of nonperformance by our vendors and other counterparties. Some of our vendors and other counterparties may be highly leveraged and subject to their own operating and regulatory risks. Many of our vendors and other counterparties finance their activities through cash flow from operations, the incurrence of debt or the issuance of equity. The combination of reduction of cash flow resulting from declines in commodity prices and the lack of availability of debt or equity financing may result in a significant reduction in our vendors’ and other counterparties’ liquidity and ability to make payments or perform on their obligations to us. Even if our credit review and analysis mechanisms work properly, we may experience financial losses in our dealings with other parties. Any increase in the nonpayment or nonperformance by our vendors or other counterparties could adversely affect our business, financial condition, results of operations and cash flows.
We may incur substantial losses and be subject to substantial liability claims as a result of catastrophic events. We may not be insured for, or our insurance may be inadequate to protect us against, these risks. Expenses not covered by our insurance could have a material adverse effect on our financial position and results of operations.
Our operations are subject to all of the hazards and operating risks associated with drilling for and production of oil and natural gas, including natural disasters, the risk of fire, explosions, blowouts, surface cratering, uncontrollable flows of natural gas, oil and formation water, pipe or pipeline failures, abnormally pressured formations, casing collapses and environmental hazards such as oil spills, natural gas leaks, ruptures or discharges of toxic gases, all of which could cause substantial financial losses. The location of any properties and other assets near environmentally sensitive areas or near populated areas, including residential areas, commercial business centers and industrial sites, could significantly increase the level of potential damages resulting from these risks. Other catastrophic events such as earthquakes, floods, mudslides, fires, droughts, contagious diseases, terrorist attacks and other events that cause operations to cease or be curtailed may adversely affect our business and the communities in which we operate. For example, utilities have begun to suspend electric services to avoid wildfires during windy periods in California, a business disruption risk that is not insured. We may be unable to obtain, or may elect not to obtain, insurance for certain risks if we believe that the cost of available insurance is excessive relative to the risks presented. The occurrence of any of these or other similar events could result in substantial losses to us due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, cleanup responsibilities, regulatory investigation and penalties, suspension or disruption of operations, substantial revenue losses and repairs to resume operations.
We maintain insurance coverage against potential losses that we believe is customary in the industry. However, insurance against all operational risk is not available to us. These insurance policies may not cover all liabilities, claims, fines, penalties or costs and expenses that we may incur in connection with our business and operations, including those related to environmental claims. Pollution and environmental risks generally are not fully insurable. In addition, we cannot assure you that we will be able to maintain adequate insurance at rates we consider reasonable. We may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. A liability, claim or other loss not fully covered by insurance could have a material adverse effect on our business, financial position, results of operations and cash flows.
We may be unable to compete effectively with larger companies.
The oil and natural gas industry is intensely competitive with respect to marketing oil and natural gas and securing equipment and trained personnel. Many of our larger competitors not only drill for and produce oil and natural gas but also
33
carry on refining operations and market petroleum and other products on a regional, national or worldwide basis, which offers them greater access and economies of scale. In addition, there is substantial competition for investment capital in the oil and natural gas industry and many of our competitors have access to capital at a lower cost than that available to us. These larger companies may have a greater ability to continue development activities during periods of low oil and natural gas prices and to absorb the burden of present and future federal, state, local and other laws and regulations. Furthermore, we may not be able to aggregate sufficient quantities of production to compete with larger companies that are able to sell greater volumes of production to intermediaries, thereby reducing the realized prices attributable to our production. Any inability to compete effectively with larger companies could have a material adverse impact on our business activities, financial condition, results of operations and cash flows.
We are subject to complex federal, state, local and other laws, regulations and permits that could adversely affect the cost, manner, ability or feasibility of conducting our operations.
Our oil and natural gas development and production operations are subject to complex and stringent laws and regulations administered by governmental authorities vested with broad authority relating to the exploration for and the development, production and transportation of oil, natural gas, and NGLs. To conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities. In order to recommence oil sales via the Santa Ynez Pipeline System, we must comply with a number of requirements related to Pipeline Segments 324 and 325, including conditions set forth in a U.S. federal district court Consent Decree executed by Plains and relevant U.S. and State of California government agencies. In order to commence operations pursuant to the OS&T Strategy, we will require regulatory authorizations, including clearance from BOEM. We may incur substantial costs in order to maintain compliance with these existing laws and regulations, and we may experience delays in procuring required approvals, which may increase our costs or delay our ability to produce revenue. Failure to comply with laws and regulations applicable to our operations, including any evolving interpretation and enforcement by governmental authorities, could have a material adverse effect on our business, financial condition, results of operations and cash flows.
Our oil, natural gas, and NGLs development and production operations are also subject to stringent and complex federal, state and local laws and regulations governing the release or discharge of materials into or through the environment, worker health and safety aspects of our operations, or otherwise relating to property rights, environmental protection, resource protection, and damage to natural resources. These laws and regulations may impose numerous obligations applicable to our operations, including regulated drilling activities; operation of the Santa Ynez Pipeline System; installation and use of an OS&T; the restriction of types, quantities and concentrations of materials that can be released or discharged into or through the environment; required authorizations for, or the limitation or prohibition of, drilling, production and transportation activities on certain lands lying within wilderness, wetlands, seismically active, park and recreation areas and other 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 our operations. The EPA, BOEM, BSEE, PHMSA, OSFM, CalGEM, Coastal Commission, CDFW, Regional Board, the SLC, State Parks and numerous other governmental authorities have the authority to enforce compliance with these laws and regulations and the permits or other authorizations issued by them, often requiring difficult and costly compliance measures 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 and mitigation 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 our operations. We may also experience delays in obtaining or be unable to obtain required permits, including authorizations necessary to recommence oil sales, which may delay or interrupt our operations and limit our growth and revenue, or may impact our ability to repay or refinance the Senior Secured Term Loan, which will mature on the earlier of (i) March 31, 2027 or (ii) the date falling 90 days after first sales of Hydrocarbons (as defined in the Senior Secured Term Loan).
Under certain environmental laws that impose strict as well as joint and several liability, we may be required to remediate or conduct other response actions at or in relation to contaminated properties currently owned or operated by us or facilities of third parties that received waste generated by our operations regardless of whether such contamination resulted from the conduct of others or from the consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. In addition, claims for damages to persons or property, including natural resources, may result from the environmental, health and safety impacts of our 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 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. Additionally, any changes in environmental regulations related to biodiversity protection could impose further operational constraints and costs. To the extent laws are
34
enacted, or other governmental action is taken that restricts drilling, production and transportation activities, 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.
See “Business—Environmental, Occupational Safety and Health Matters and Regulations” and “Business-Other Regulation of the Oil and Natural Gas Industry” for a description of the more significant laws and regulations that affect us.
Changes in tax law may materially adversely affect our financial condition, results of operations and cash flows.
New income, sales, use or other tax laws, statutes, rules, regulations or ordinances are continuously being enacted, proposed, interpreted, changed, or modified, any of which could adversely affect our business operations and financial performance. For example, on July 4, 2025, the One Big Beautiful Bill Act (the “OBBBA”), was signed into law in the United States, which includes revisions to key business tax provisions such as the reinstatement of bonus depreciation deductions for qualified property, the restoration of an EBITDA-based business interest expense limitation, the revision and expansion of certain renewable energy tax credits that were previously available under the IRA and the implementation of changes relating to the computation of certain taxes in respect of non-US activities. Since future changes to tax legislation and regulations are unknown, we cannot predict the ultimate impact such changes may have on our business. To the extent that these or other changes have a negative impact on us or our consumers, including as a result of related uncertainty, these changes may materially and adversely impact us, our business, financial condition, results of operations and cash flow.
The listing of a species as either “threatened” or “endangered” under the U.S. Endangered Species Act and/or the California Endangered Species Act could result in increased costs, new operating restrictions, or delays in our operations, which could adversely affect our results of operations and financial condition.
The U.S. Endangered Species Act (the “ESA”) and analogous state laws regulate activities that could have an adverse effect on threatened and endangered species. Operations in areas where threatened or endangered species or their habitat are known to exist may require us to incur increased costs to implement mitigation or protective measures and also may restrict or preclude our activities in those areas or during certain seasons, such as breeding and nesting seasons. The listing of species in areas where we operate or, alternatively, entry into certain range-wide conservation planning agreements could result in increased costs to us from species protection measures, time delays or limitations on our activities, which costs, delays or limitations may be significant and could adversely affect our results of operations and financial position.
Conservation measures, technological advances and increasing public attention and activism with respect to climate change and environmental matters could reduce demand for oil, natural gas and NGLs and have an adverse effect on our business, financial condition and reputation.
Fuel conservation measures, alternative fuel requirements, incentives to conserve energy or use alternative energy sources, increasing consumer demand for alternatives to oil, natural gas and NGLs, and technological advances in fuel economy and energy generation devices could reduce demand for oil, natural gas and NGLs. Such initiatives or related activism aimed at limiting climate change and reducing air pollution, as well as negative investor sentiment toward our industry and the impact of the changing demand for oil and natural gas services and products may have a material adverse effect on our business, financial condition, results of operations, cash flows, and ability to access capital. Negative public perception regarding us and/or our industry resulting from, among other things, concerns raised by advocacy groups about climate change, may also lead to increased litigation risk, and regulatory, legislative and judicial scrutiny, which may, in turn, lead to new state and federal safety and environmental laws, regulations, guidelines and enforcement interpretations. Governmental authorities exercise considerable discretion in the timing and scope of permit issuance and the public may engage in the permitting process, including through intervention in the courts. Negative public perception could cause the permits we need to conduct our operations to be withheld, delayed, or burdened by requirements that restrict our ability to profitably conduct our 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, 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.
35
Climate change legislation or regulations restricting emissions of “greenhouse gases,” or GHGs, could result in increased operating costs and reduced demand for the oil, natural gas and NGLs we expect to produce.
In December 2009, the EPA published its findings that emissions of GHGs present a danger to public health and the environment because emissions of such gases are contributing to the warming of the Earth’s atmosphere and other climatic changes. Based on these findings, the EPA has adopted and implemented regulations to restrict emissions of GHGs under existing provisions of the Clean Air Act. In addition, the EPA has also adopted rules requiring the monitoring and reporting of GHG emissions from specified sources on an annual basis in the United States, including, among others, certain oil and natural gas production facilities, which includes certain of our operations. The adoption or revision 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 associated with our operations or could adversely affect demand for the oil, natural gas and NGLs we produce. Such climate change regulatory and legislative initiatives could have a material adverse effect on our business, financial condition and results of operations.
On August 16, 2022, President Biden signed into law the IRA, which targets methane from oil and gas sources by imposing an applicable “waste emissions charge” on petroleum and natural gas production facilities that exceed a specified waste emissions threshold and requiring the reporting of emissions that exceed 25,000 metric tons of carbon dioxide equivalent per year. On November 18, 2024, the EPA published a final rule to implement this waste emissions charge as required by the IRA. However, on March 14, 2025, Congress 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 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.
In addition to the IRA, almost one-half of the states have taken legal measures to reduce emissions of GHGs, including through the planned development of GHG emission inventories and/or regional GHGs cap and trade programs. On an international level, the United States was one of nearly 200 countries to sign an international climate change agreement in Paris, France that requires member countries to set their own GHG emissions reduction goals beginning in 2020. However, the United States formally announced its intent to withdraw from the Paris Agreement in November 2019, which became effective in November 2020. 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. On January 20, 2025, President Trump signed an executive order initiating the re-withdraw 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.
On February 12, 2026, EPA rescinded its 2009 “Endangerment Finding” under Clean Air Act Section 202(a). 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. It is expected that this rescission rule will be challenged in federal court.
Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations that require additional reporting of GHGs or otherwise limit emissions of GHGs from our equipment and operations could require us to incur costs to monitor and report on GHG emissions or reduce emissions of GHGs associated with our operations, and such requirements also could adversely affect demand for the oil, natural gas and NGL that we produce. Finally, it should be noted that numerous 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, droughts and 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 financial condition and results of operations. For example, such effects could adversely affect or delay demand for the oil or natural gas produced or cause us to incur significant costs in preparing for or responding to the effects of climatic events themselves. Potential adverse effects could include disruption of our production activities, increases in our costs of operation or reductions in the efficiency of our operations, impacts on our personnel, supply chain, or distribution chain, as well as potentially increased costs for insurance coverages in the aftermath of such effects. Our ability to mitigate the adverse physical impacts of climate change depends in part upon our disaster preparedness and response and business continuity planning. See “Business—Environmental, Occupational Safety and Health Matters and Regulations-Regulation of ‘Greenhouse Gas’ Emissions” for a description of the climate change laws and regulations that affect us. Also see “Risk Factors—Risks Related to the Business of the Company-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.”
36
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.
California, where portions of the Santa Ynez Pipeline System are located, is heavily regulated with respect to oil and gas operations. Federal, state and local laws and regulations govern most aspects of exploration, production, processing and transportation of hydrocarbons in California. The regulatory burden on the industry increases our costs and consequently may have an adverse effect upon capital expenditures, earnings or competitive position. Violations and liabilities with respect to these laws and regulations could result in significant administrative, civil, or criminal penalties, remedial clean-ups, natural resource damages, permit modifications or revocations, operational interruptions or shutdowns and other liabilities. The costs of remedying such conditions may be significant, and remediation obligations could adversely affect our financial condition, results of operations and prospects.
Additionally, the California state government recently has taken several actions that could adversely impact future oil and gas production and other activities in the state. For example:
•In September 2020, the California Governor issued an executive order that seeks to reduce both the supply of and demand for fossil fuels in the state. The executive order established several goals and directed several state agencies to take certain actions with respect to reducing emissions of greenhouse gases, including, but not limited to: (1) phasing out the sale of emissions-producing vehicles; (2) developing strategies for the closure and repurposing of oil and gas facilities in California; and (3) calling on the California State Legislature to enact new laws prohibiting hydraulic fracturing in the state by 2024. The executive order also directed CalGEM to finish its review of public health and safety concerns from the impacts of oil extraction activities and propose significantly strengthened regulations.
•In October 2020, the California Governor issued an executive order that established a state goal to conserve at least 30% of California’s land and coastal waters by 2030 and directed state agencies to implement other measures to mitigate climate change and strengthen biodiversity.
•On July 1, 2025, amendments to the Low Carbon Fuel Standard (“LCFS”) Regulation took effect. The LCFS Program is a market-based compliance measure that is designed to create economic value from low-carbon and renewable fuel technologies, with a stated goal of reducing greenhouse gas emissions in California. The recent amendments increase both the pre- and post-2030 stringency of carbon intensity benchmarks. Specifically, they increase the carbon intensity reduction targets from 20% to 30% by 2030, and aim for a 90% reduction by 2045, based on a 2010 baseline.
•On September 19, 2025, California Governor Gavin Newsom signed Assembly Bill 1207 and Senate Bill 840 into law. Together, the new laws re-authorize and extend California’s cap-and-trade program – now renamed the “cap-and-invest” program – through December 31, 2045. This program sets a price on greenhouse emissions that over time may reduce demand for oil and gas. On January 20, 2026, CARB commenced a rulemaking to amend the cap-and-invest regulations, which CARB anticipates to approve at its May 28, 2026 Board Hearing.
At this time, we cannot predict the potential future actions that may result from these orders or how such actions might potentially impact our operations.
On September 19, 2025, Governor Gavin Newsom signed SB 237 into law, which became effective on January 1, 2026. SB 237 added requirements to the California Government Code that provide that an existing oil pipeline that has been idle, inactive, or out of service for five years or more, cannot be restarted without passing a spike hydrostatic testing program. SB 237 also amended the California Coastal Act to provide that the repair, reactivation, or maintenance of an oil pipeline that has been idled, inactive or out of service for five years or more must obtain a new coastal development permit. On September 29, 2025, Sable filed a Complaint for Declaratory Relief against the State of California in Kern County Superior Court seeking a declaratory judgment that Pipeline Segments 324 and 325 are not subject to SB 237 because the Santa Ynez Pipeline System is not “idle, inactive, or out of service,” and because the Legislature did not give SB 237 retroactive effect. On January 21, 2026, the Company filed its First Amended Complaint adding a claim that the application of SB 237 to the Santa Ynez Pipeline System is preempted by federal law. On February 20, 2026, the State of California removed the case to the U.S. District Court for the Eastern District of California. Sable intends to continue to vigorously prosecute the action.
On June 3, 2022, the U.S. Court of Appeals for the Ninth Circuit prohibited the federal government from issuing new permits or plans for the use of well stimulation treatments, including hydraulic fracturing and acidizing of wells, in federal
37
waters on the Pacific Outer Continental Shelf until a full environmental review is completed by federal agencies, including an environmental impact statement. The injunction was the result of lawsuits filed by the State of California, the California Coastal Commission and environmental groups alleging that federal agencies violated environmental laws when they authorized unconventional drilling methods from offshore California platforms. The court further found that the agencies violated the Endangered Species Act and Coastal Zone Management Act by not undertaking the appropriate consultations pursuant to those statutes.
While currently none of our Pacific Outer Continental Shelf operations rely on hydraulic fracturing stimulation or acidizing of wells as discussed in the Ninth Circuit decision, any restrictions on the future use of those well stimulation treatments or other forms of injection may adversely impact our operations, including causing operational delays, increased costs, and reduced production, which could adversely affect our revenues, results of operations and net cash provided by operating activities.
In December 2023, the State Lands Commission granted authority to the Executive Officer to solicit and execute agreements for consultant services to prepare an “Analysis of Public Trust Resources and Values” (“APTR”), which will assess the risks and impacts to Public Trust resources of all 12 leases for offshore oil and gas pipelines under the Commission’s jurisdiction. The APTR will include technical evaluations, environmental assessments, climate change considerations, public needs analysis, and alternatives to pipelines. The Commission expects to finalize the APTR by December 31, 2026. The Commission has also authorized a temporary moratorium on new lease applications and issuances for offshore oil and gas pipelines until the APTR is completed and its findings are reviewed. The outcome of the APTR could adversely affect our ability to renew or extend our State Lands Commission leases beyond the current expirations in 2028 and 2029.
On January 13, 2026, in response to the federal Department of the Interior’s proposed 11th (2026-2031) National Outer Continental Shelf Oil and Gas Leasing Program, California State Senate Member John Laird introduced Senate Joint Resolution 12 (“SJR 12”) to the California State Legislature. If passed as proposed, SJR 12 would state the California Legislature’s opposition to new offshore drilling, and support for the current federal prohibition on new oil or gas drilling, in federal waters offshore of the Pacific coast. SJR 12 also would request, on behalf of the California Legislature, that BOEM hold public hearings and prepare a programmatic environmental impact statement pursuant to the National Environmental Policy Act with respect to the proposed National Continental Shelf Oil and Gas Leasing Program. Although our existing offshore leases in federal waters would not directly be affected by the 11th National Outer Continent Shelf Oil and Gas Leasing Program or SJR 12, SJR 12 could be indicative of the Legislature’s general opposition to oil and gas leases off the California coast.
Our assets are located exclusively onshore and offshore in California, making us vulnerable to risks associated with having operations concentrated in this geographic area.
We operate exclusively in California and in the federally-administered waters off the coast of California. This geographic concentration disproportionately affects the success and profitability of our operations, exposing us to local price fluctuations, changes in state or regional laws and regulations, political risks, limited acquisition opportunities where we have the most operating experience and infrastructure, limited storage options, drought conditions, and other regional supply and demand factors, including gathering, pipeline and transportation capacity constraints, limited potential customers, infrastructure capacity and availability of rigs, equipment, oil field services, supplies and labor. We discuss such specific risks to our operations in more detail elsewhere in this section. In addition, we may not have the resources to effectively diversify our operations or benefit from the possible spreading of risks or offsetting of losses.
All of our operations are conducted in areas that may be at risk of damage from fire, mudslides, earthquakes or other natural disasters.
We currently conduct operations in California and adjacent offshore areas near known wildfire and mudslide areas and earthquake fault zones. A future natural disaster, such as a fire, mudslide or an earthquake, could cause substantial interruption and delays in our operations, damage or destroy equipment, prevent or delay transport of our products and cause us to incur additional expenses, which would adversely affect our business, financial condition and results of operations. In addition, our facilities would be difficult to replace and would require substantial lead time to repair or replace. These events could occur with greater frequency as a result of the potential impacts from climate change. The insurance we maintain against earthquakes, mudslides, fires and other natural disasters would not be adequate to cover a total loss of our facilities, may not be adequate to cover our losses in any particular case and may not continue to be available to us on acceptable terms, or at all.
38
Increasing attention to environmental, social and governance (“ESG”) matters may impact our business.
Increasing attention to, and social expectations on companies to address, climate change and other environmental and social impacts, investor and societal explanations regarding voluntary ESG disclosures, and increased consumer demand for alternative forms of energy may result in increased costs, reduced demand for our products, reduced profits, increased investigations and litigation, and negative impacts on our stock price and access to capital markets. Increasing attention to climate change and environmental conservation, for example, may result in demand shifts for oil and natural gas products and additional governmental investigations and private litigation against us. To the extent that societal pressures or political or other factors are involved, it is possible that such liability could be imposed without regard to our causation of or contribution to the asserted damage, or to other mitigating factors. While we may participate in various voluntary frameworks and certification programs to improve the ESG profile of our operations and products, we cannot guarantee that such participation or certification will have the intended results on our or our products’ ESG profile.
Moreover, while we may create and publish voluntary disclosures regarding ESG matters from time to time, many of the statements in those voluntary disclosures will be based on hypothetical expectations and assumptions that may or may not be representative of current or actual risks or events or forecasts of expected risks or events, including the costs associated therewith. Such expectations and assumptions are necessarily uncertain and may be prone to error or subject to misinterpretation given the long timelines involved and the lack of an established single approach to identifying, measuring, and reporting on many ESG matters. Additionally, while we may also announce various voluntary ESG targets in the future, such targets are aspirational. We may not be able to meet such targets in the manner or on such a timeline as initially contemplated, including, but not limited to as a result of unforeseen costs or technical difficulties associated with achieving such results. To the extent we do meet such targets through operational changes, they may be achieved through various contractual arrangements, including the purchase of various credits or offsets that may be deemed to mitigate our ESG impact. Also, despite these aspirational goals, we may receive pressure from investors, lenders, or other groups to adopt more aggressive climate or other ESG-related goals, but we cannot guarantee that we will be able to implement such goals because of potential costs or technical or operational obstacles.
In addition, organizations that provide information to investors on corporate governance and related matters have developed ratings processes for evaluating companies on their approach to ESG matters. Such ratings are used by some investors to inform their investment and voting decisions. Unfavorable ESG ratings may lead to increased negative investor sentiment toward us or our customers and to the diversion of investment to other industries which could have a negative impact on our stock price and/or our access to and costs of capital. Moreover, to the extent ESG matters negatively impact our reputation, we may not be able to compete as effectively or recruit or retain employees, which may adversely affect our operations.
Such ESG matters may also impact our customers or suppliers, which may adversely impact our business, financial condition, or results of operations.
Environmental groups may initiate litigation and take other actions to delay or prevent us from obtaining or maintaining required approvals to recommence oil sales.
Environmental groups have had increasing success in limiting oil and gas production by appealing to regulatory agencies, filing lawsuits and applying political pressure. In order to recommence oil sales we are required to obtain and maintain a series of permits or regulatory approvals from, among other agencies, PHMSA and BOEM. The laws and procedures governing these and other permits and regulatory approvals often allow third parties, including environmental groups, to challenge the draft permits and/or permit approvals through the relevant agencies and other administrative appeal processes. These groups may also file lawsuits that delay or prevent the issuance of the approvals through an injunction and/or prevailing on the legal merits or a ruling that additional approval is required. See “Item 1. Business” and Note 8—Commitments and Contingencies for recent events. In addition, these groups may leverage the increased public attention and concern with respect to climate change and other environmental and social impacts in order to encourage government officials to withhold or delay the necessary approvals or require additional approvals. There is no assurance that these groups will not be successful in delaying or preventing us from obtaining or maintaining the required approvals through litigation or other actions.
The Inflation Reduction Act of 2022 could accelerate the transition to a low carbon economy and will impose new costs on our operations.
On August 16, 2022, President Biden signed into law the IRA. The IRA contains hundreds of billions of dollars in incentives for the development of renewable energy, clean hydrogen, clean fuels, electric vehicles and supporting
39
infrastructure and carbon capture and sequestration, amongst other provisions. These incentives could further accelerate the transition of the U.S. economy away from the use of fossil fuels towards lower-or zero-carbon emissions alternatives, which could decrease demand for the oil and gas we produce and consequently materially and adversely affect our business and results of operations. In addition, the IRA imposes the first ever federal fee on the emission of GHGs through a methane emissions charge. The IRA amends the Clean Air Act to impose a fee on the emission of methane from sources required to report their 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, has increased 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 IRA. On November 18, 2024, the EPA published a final rule to implement this waste emissions charge as required by the IRA. However, on March 14, 2025, Congress through a joint resolution 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 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. The methane emissions charge could increase our capital expenditures to limit methane releases and further increase our costs to the extent we exceed the limits, which may adversely affect our business and results of operations.
The cost of decommissioning and the cost of financial assurance to satisfy decommissioning obligations are uncertain.
We are required to maintain reserve funds to provide for the payment of decommissioning costs associated with our properties. The estimates of decommissioning costs are inherently imprecise and subject to change due to changing cost estimates, oil and natural gas prices and other factors. If actual decommissioning costs exceed such estimates, or we are required to provide a significant amount of collateral in cash or other security as a result of a revision to such estimates, our financial condition, results of operations and cash flows may be materially adversely affected.
We may be required to post cash collateral pursuant to our agreements with sureties, letter of credit providers or regulators under our existing or future bonding or other arrangements, which may have a material adverse effect on our liquidity and our ability to execute our capital expenditure plan and our asset retirement obligation plan and comply with the agreements governing our existing or future indebtedness.
Pursuant to the terms of our existing bonding arrangements with various sureties in connection with the decommissioning obligations and government-mandated financial assurance obligations related to our properties, or under any future bonding arrangements we may enter into, we may be required to post collateral at any time, on demand, at the sureties’ sole discretion. If additional collateral is required to support surety bond obligations, this collateral would probably be in the form of cash or letters of credit, certificates of deposit or other similar forms of liquid collateral. Letter of credit providers would also in turn likely expect collateral to support such obligations, primarily in the form of cash or other liquid collateral.
If sureties become unwilling to enter into or continue bonding arrangements with us, regulators would likely require us to post additional collateral or fully fund our obligations with cash or other forms of liquid collateral. We cannot provide any assurance that we will be able to satisfy collateral demands for current or future bonds or letters of credit, or that we will be able to satisfy funding requirements for other arrangements with regulators. If we are required to provide additional collateral or fully fund these obligations and we cannot obtain alternative financing, our liquidity position may be negatively impacted and we may be forced to reduce our capital expenditures in the current year or future years, may be unable to execute our asset retirement obligation plan or may be unable to comply with the agreements governing our existing or future indebtedness.
Our business could be negatively affected by security threats, including cybersecurity threats, destructive forms of protest and opposition by activists and other disruptions.
As an oil and natural gas producer, we face various security threats, including cybersecurity threats to gain unauthorized access to sensitive information, to misappropriate financial assets or to render data or systems unusable; threats to the security of our facilities and infrastructure or third-party facilities and infrastructure, such as processing plants and pipelines; and threats from terrorist acts. The potential for such security threats has subjected our operations to increased risks that could have a material adverse effect on our business. In particular, our implementation of various procedures and controls to monitor and mitigate security threats and to increase security for our information, facilities and infrastructure may result in increased capital and operating costs. There can be no assurance that our cybersecurity risk management program and processes, including our policies, controls or procedures, will be fully implemented, complied with or effective in protecting our systems and information. Moreover, there can be no assurance that such procedures and controls will be sufficient to prevent security breaches from occurring. If any of these security breaches were to occur, they could
40
lead to losses of financial assets, sensitive information, critical infrastructure or capabilities essential to our operations and could have a material adverse effect on our reputation, financial position, results of operations or cash flows.
Cybersecurity attacks in particular are becoming more sophisticated and include, but are not limited to, malicious software, attempts to gain unauthorized access to data and systems, and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information, and corruption of data. These events could lead to financial losses from remedial actions, loss of business or potential liability. In addition, destructive forms of protest and opposition by activists and other disruptions, including acts of sabotage or eco-terrorism, against oil and gas production and activities could potentially result in damage or injury to people, property or the environment or lead to extended interruptions of our operations, adversely affecting our financial condition and results of operations.
Risks Related to Being a Public Company
The market prices of our securities could be highly volatile or may decline regardless of our operating performance. You may lose some or all of your investment.
The trading price of our Common Stock is likely to be volatile and subject to significant fluctuations. The trading price of our Common Stock will depend on many factors, including those described in this “Risk Factors” section, many of which are beyond our control and may not be related to our operating performance. You may not be able to resell your shares at an attractive price due to a number of factors, such as the following:
•actual or anticipated fluctuations in our annual or quarterly financial results or the financial results of companies perceived to be similar to ours;
•changes in the market’s expectations about our operating results;
•the public’s reaction to our press releases, other public announcements and filings with the SEC;
•speculation in the press or investment community;
•actual or anticipated developments in our business, competitors’ businesses or the competitive landscape generally;
•our success in satisfying permitting and other regulatory requirements to resume full production;
•our success in satisfying permitting and other regulatory requirements to resume petroleum transportation through Pipeline Segments 324 and 325 of the Santa Ynez Pipeline System or obtain alternate transportation;
•our ability to obtain water, drilling fluids and other critical resources;
•the accuracy of our assumptions and estimates regarding the total costs associated with resuming and maintaining production and the Santa Ynez Pipeline System;
•the market prices of oil, natural gas and NGL;
•the success of our hedging strategy;
•our ability to manage the safety risks associated with offshore development and production;
•our success in retaining or recruiting, or changes required in, our officers, key employees or directors;
•future laws and regulations related to climate change, GHGs and ESG and administrative interpretations thereof;
•changes in the future operating results of the Company;
•operating and stock price performance of other companies that investors deem comparable to ours;
•changes in laws and regulations affecting our business;
•commencement of, or involvement in, litigation involving the Company;
•changes in our capital structure, such as future issuances of securities or the incurrence of additional debt;
41
•the volume of our Common Stock available for public sale;
•any major change in our Board or management;
•sales of substantial amounts of our Common Stock by our directors, officers or significant stockholders or the perception that such sales could occur; and
•other risk factors and other matters described or referenced under the sections “Risk Factors” and “Cautionary Note Regarding Forward‑Looking Statements.”
Broad market and industry factors may materially harm the market price of our securities irrespective of our operating performance. The stock market in general and the NYSE have experienced extreme price and volume fluctuations that have often been unrelated or disproportionate to the operating performance of the particular companies affected. The trading prices and valuations of these stocks, and of our securities, may not be predictable. A loss of investor confidence in the market for the stocks of other companies which investors perceive to be similar to ours could depress our Common Stock price regardless of our business, prospects, financial conditions or results of operations.
In addition, in the past, following periods of volatility in the overall market and the market prices of particular companies’ securities, securities class action litigations have often been instituted against these companies. Litigation of this type, if instituted against us, could result in substantial costs and a diversion of our management’s attention and resources. Any adverse determination in any such litigation or any amounts paid to settle any such actual or threatened litigation could require that we make significant payments.
Our stock price may be exposed to additional risks because we became a public company through a “de‑SPAC” transaction. There has been increased focus by government agencies on such transactions, and we expect that increased focus to continue, and we may be subject to increased scrutiny by the SEC and other government agencies on holders of our securities as a result, which could adversely affect the price of our Common Stock.
We are, and may continue to be, subject to short selling strategies and related public allegations, which could lead to a decline in the price of our Common Stock and have a material adverse effect on our reputation and results of operations.
Short selling is the practice of selling securities that the seller does not own but rather has borrowed from a third party with the intention of buying identical securities back at a later date to return to the lender. The short seller hopes to profit from a decline in the value of the securities between the sale of the borrowed securities and the purchase of the replacement shares, as the short seller expects to pay less in that purchase than it received in the sale. To facilitate the decline in stock price, short sellers may engage in strategies to publish, or arrange for the publication of, opinions regarding the relevant issuer and its business prospects to create negative market momentum and generate profits for themselves after selling a stock short. Such short selling strategies have resulted in considerable selling of the targeted issuer’s shares in the market.
We are, and may in the future may be, the subject of unfavorable allegations made by short sellers. For example, on October 31, 2025, Hunterbrook Media issued a report to short sellers that contained certain allegations against us. In response, our Board of Directors formed a special committee to oversee an independent investigation of the matters referenced in the report. The investigation is ongoing and we may or may not uncover additional material information as the investigation moves forward. As a result, we are unable to predict the outcome or to reasonably estimate the time or expense it may take to resolve these matters.
We may, in the future, become subject to additional unfavorable reports. Any such allegations may be followed by periods of instability in the market price of our shares of Common Stock and negative publicity. Any related inquiry or formal investigation from a governmental organization or other regulatory body, or resulting litigation from private claimants, could result in a material diversion of our management’s time and could have a material adverse effect on our business and results of operations. Such a situation could be costly and time-consuming and could distract our management from operating our business.
We are subject to an ongoing investigation by a Special Committee of the Board and have received subpoenas for documents from the SDNY and SEC, and may be named in future governmental or other regulatory investigations and proceedings, each of which could have a material adverse impact on our business, financial condition, results of operation, cash flows and reputation.
As announced on November 3, 2025, the members of the Board formed a special committee of independent directors (the “Special Committee”) to undertake an independent investigation of the allegations contained in the Hunterbrook Report.
42
The Special Committee’s investigation remains underway. In addition, the Company has received subpoenas for documents from the SDNY and SEC (the “Government Requests”).
The Special Committee investigation and Government Requests could each have an adverse impact on the Company. We cannot predict or provide any assurance as to the timing, outcome or consequences of the Special Committee investigation or the Government Requests. If the SEC or SDNY were to conclude that an enforcement action is appropriate, the SEC could impose civil penalties and fines, and other sanctions against us or against our current and former officers and directors, and the SDNY could impose criminal penalties. We may incur significant expenses related to legal and other professional services in connection with matters relating to or arising from the Special Committee investigation or the Government Requests. These cash outflows may negatively impact our cash position and profitability. We cannot predict if the government will impose any penalty or fine and, if it does, the magnitude or timing of such penalty or fine; however, any penalty or fine would also negatively impact our cash position, profitability, and liquidity.
In addition, our Board, management and employees have expended, and may continue to expend, a substantial amount of time on the Special Committee investigation and the Government Requests, diverting resources and attention that would otherwise be directed toward our operations and implementation of our business strategy, all of which could materially adversely affect our business, financial condition and results of operations. Publicity surrounding the foregoing, or any enforcement action or settlement as a result of the Government Requests, even if ultimately resolved favorably for us, could have an adverse impact on our reputation, business, financial condition, and results of operations.
In addition, we could be subject to future claims, investigations, or proceedings. Any future inquiries from regulatory authorities, or future claims or proceedings as a result of the Special Committee investigation, the Government Requests or related regulatory investigations, will, regardless of the outcome, consume a significant amount of our internal resources and result in additional legal and accounting costs.
The NYSE may not continue to list our securities, which could limit investors’ ability to make transactions in our securities and subject us to additional trading restrictions.
We cannot assure you that our securities will continue to be listed on the NYSE in the future. In order for our securities to remain listed on the NYSE, we must maintain certain financial, distribution and stock price levels.
If the NYSE delists our securities from trading on its exchange and we are not able to list our securities on another national securities exchange, we expect our securities could be quoted on an over‑the‑counter market. If this were to occur, we could face significant material adverse consequences, including:
•a limited availability of market quotations for our securities;
•reduced liquidity for our securities;
•a determination that our Common Stock is a “penny stock,” which would require brokers trading in such securities to adhere to more stringent rules, could adversely impact the value of our securities and/ or possibly result in a reduced level of trading activity in the secondary trading market for our securities;
•a limited amount of news and analyst coverage; and
•a decreased ability to issue additional securities or obtain additional financing in the future.
If we fail to implement and maintain proper and effective internal controls over financial reporting, our ability to produce accurate financial statements on a timely basis could be impaired, which could cause investors to lose confidence in our reported financial information and have a negative effect on our stock price.
Ensuring that we have adequate internal financial and accounting controls and procedures in place to produce accurate financial statements on a timely basis is a costly and time-consuming effort that needs to be reevaluated frequently. Our management is responsible for establishing and maintaining adequate internal control over financial reporting to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of financial statements for external purposes in accordance with U.S. generally accepted accounting principles (“U.S. GAAP”). A control, no matter how well designed and operated, can provide only reasonable, not absolute, assurance that the control’s objectives will be met. Because of the inherent limitations in all controls, no evaluation of controls can provide absolute assurance that misstatements due to error or fraud will not occur or that all control issues and instances of fraud, if any, within our company will have been detected. Effective internal controls are necessary for us to produce reliable financial reports and are important to prevent fraud. Any failure to maintain or implement new or improved controls over financial reporting
43
could result in material weaknesses or result in the failure to detect or prevent material misstatements in our financial statements, which could cause investors to lose confidence in our reported financial information and harm our stock price.
Future sales, or the perception of future sales, of our Common Stock by us or our existing stockholders in the public market could cause the market price for our Common Stock to decline.
The sale of substantial amounts of shares of our Common Stock in the public market, or the perception that such sales could occur, could harm the prevailing market price of shares of our Common Stock. These sales, or the possibility that these sales may occur, also might make it more difficult for us to sell equity securities in the future at a time and at a price that we deem appropriate.
Shares held by certain of our stockholders will be eligible for resale, subject to, in the case of certain stockholders, volume, manner of sale and other limitations under Rule 144. In addition, pursuant to the Registration Rights Agreement entered into by and among Sable and certain stockholders party thereto, such stockholders will be entitled to customary registration rights for 3,000,000 shares of our Common Stock following their respective lock-up periods. The sale or possibility of sale of these securities could have the effect of increasing the volatility in our share price or putting significant downward pressure on the price of our Common Stock.
Our issuance of additional shares of Common Stock or convertible securities may dilute your ownership of us and could adversely affect our stock price.
We filed a registration statement on Form S-8 on April 19, 2024 providing for the registration of shares of our Common Stock issued or reserved for issuance under the Sable Offshore Corp. 2023 Incentive Award Plan (the “Incentive Plan”). The Incentive Plan provides for automatic increases in the shares reserved for grant or issuance under the plan which could result in additional dilution to our stockholders. Subject to the satisfaction of vesting conditions and the expiration of any applicable lockup restrictions, shares registered under the registration statement on Form S-8 will generally be available for resale immediately in the public market without restriction. From time to time in the future, we may also issue additional shares of our Common Stock or securities convertible into our Common Stock pursuant to a variety of transactions, including acquisitions. The issuance by us of additional shares of our Common Stock or securities convertible into our Common Stock would dilute your ownership of us and the sale of a significant amount of such shares in the public market could adversely affect prevailing market prices of our Common Stock.
In the future, we may seek to obtain financing or to further increase our capital resources by issuing additional shares of our capital stock or offering debt or other equity securities, including senior or subordinated notes, debt securities convertible into equity, or shares of preferred stock. Issuing additional shares of our capital stock, other equity securities, or securities convertible into equity may dilute the economic and voting rights of our existing stockholders, reduce the market price of our Common Stock, or both. Debt securities convertible into equity could be subject to adjustments in the conversion ratio pursuant to which certain events may increase the number of equity securities issuable upon conversion. Preferred stock, if issued, could have a preference with respect to liquidating distributions or a preference with respect to dividend payments that could limit our ability to pay dividends to the holders of our Common Stock. Our decision to issue securities in any future offering will depend on market conditions and other factors beyond our control, which may adversely affect the amount, timing or nature of our future offerings. As a result, holders of our Common Stock bear the risk that our future offerings may reduce the market price of our Common Stock and dilute their percentage ownership.
Our warrant agreement designates the courts of the State of New York or the United States District Court for the Southern District of New York as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by holders of our warrants, which could limit the ability of Warrant Holders to obtain a favorable judicial forum for disputes with our company.
Our warrant agreement provides that, subject to applicable law, (i) any action, proceeding or claim against us arising out of or relating in any way to the warrant agreement, including under the Securities Act, will be brought and enforced in the courts of the State of New York or the United States District Court for the Southern District of New York, and (ii) that we irrevocably submit to such jurisdiction, which jurisdiction will be the exclusive forum for any such action, proceeding or claim. Under our warrant agreement, we also agree that we will waive any objection to such exclusive jurisdiction and that such courts represent an inconvenient forum.
Notwithstanding the foregoing, these provisions of the warrant agreement do not apply to suits brought to enforce any liability or duty created by the Exchange Act or any other claim for which the federal district courts of the United States of America are the sole and exclusive forum. Any person or entity purchasing or otherwise acquiring any interest in any of our warrants will be deemed to have notice of and to have consented to the forum provisions in our warrant agreement.
44
If any action, the subject matter of which is within the scope of the forum provisions of the warrant agreement, is filed in a court other than a court of the State of New York or the United States District Court for the Southern District of New York (a “foreign action”) in the name of any holder of our warrants, such holder will be deemed to have consented to: (x) the personal jurisdiction of the state and federal courts located in the State of New York in connection with any action brought in any such court to enforce the forum provisions (an “enforcement action”), and (y) having service of process made upon such Warrant Holder in any such enforcement action by service upon such Warrant Holder’s counsel in the foreign action as agent for such Warrant Holder.
This choice-of-forum provision may limit a Warrant Holder’s ability to bring a claim in a judicial forum that it finds favorable for disputes with our company, which may discourage such lawsuits. Alternatively, if a court were to find this provision of our warrant agreement inapplicable or unenforceable with respect to one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could materially and adversely affect our business, financial condition and results of operations and result in a diversion of the time and resources of our management and board of directors.
Members of our management team and our Board and their respective affiliated companies have been, and may from time to time be, involved in legal proceedings or governmental investigations unrelated to our business.
Members of our management team and our Board have been involved in a wide variety of businesses. Such involvement has, and may lead to, media coverage and public awareness. As a result of such involvement, members of our management team and our Board and their respective affiliated companies have been, and may from time to time be, involved in legal proceedings or governmental investigations unrelated to our business. Any such proceedings or investigations may be detrimental to our reputation and could negatively affect our ability to identify and complete an initial business combination and may have an adverse effect on the price of our securities.
If securities or industry analysts do not publish research or reports about us, or publish negative reports, our stock price and trading volume could decline.
The trading market for our Common Stock will depend, in part, on the research and reports that securities or industry analysts publish about us. We will not have any control over these analysts. If our financial performance fails to meet analyst estimates or one or more of the analysts who cover us downgrade our Common Stock or change their opinion, our stock price would likely decline. If one or more of these analysts cease coverage of us or fail to regularly publish reports on us, we could lose visibility in the financial markets, which could cause our stock price or trading volume to decline.
Our operating results may fluctuate significantly, which makes our future operating results difficult to predict and could cause our operating results to fall below expectations or any guidance it may provide.
Our quarterly and annual operating results may fluctuate significantly, which makes it difficult for us to predict our future operating results. These fluctuations may occur due to a variety of factors, many of which are outside of our control, including, but not limited to:
•the costs associated with maintaining production and the Santa Ynez Pipeline System;
•the market prices of oil, natural gas and NGL;
•the success of our hedging strategy;
•future accounting pronouncements or changes in our accounting policies;
•macroeconomic conditions, both nationally and locally; and
•any other change in the competitive landscape of our industry, including consolidation among our competitors or partners.
The cumulative effects of these factors could result in large fluctuations and unpredictability in our quarterly and annual operating results. As a result, comparing our operating results on a period‑to‑period basis may not be meaningful. Investors should not rely on past results as an indication of future performance. This variability and unpredictability could also result in us failing to meet the expectations of industry or financial analysts or investors for any period. If our revenue or operating results fall below the expectations of analysts or investors or below any forecasts we may provide to the market, or if the forecasts we provide to the market are below the expectations of analysts or investors, the price of our Common
45
Stock could decline substantially. Such a stock price decline could occur even when we have met any previously publicly stated revenue or earnings guidance we may provide.
Changes in laws, regulations or rules, or a failure to comply with any laws, regulations or rules, may adversely affect our business, investments and results of operations.
We are subject to laws, regulations and rules enacted by national, regional and local governments and the NYSE. In particular, We are required to comply with certain SEC, NYSE and other legal or regulatory requirements. Compliance with, and monitoring of, applicable laws, regulations and rules may be difficult, time consuming and costly. Such laws, regulations or rules and their interpretation and application may also change from time to time and such changes could have a material adverse effect on our business, investments and results of operations. In addition, any failure by us to comply with applicable laws, regulations or rules, as interpreted and applied, could have a material adverse effect on our business and results of operations.
We no longer qualify as an “emerging growth company” and will be required to comply with certain provisions of the Sarbanes-Oxley Act. We can no longer take advantage of reduced disclosure requirements applicable to emerging growth companies.
Based on the market value of our common stock held by non-affiliates as of June 30, 2025, we no longer qualify as an “emerging growth company” as defined in the Jumpstart Our Business Startups Act (the “JOBS Act”), as of December 31, 2025. As a result, we may incur additional and increasing costs to comply with our reporting and other obligations that we had not historically incurred due to our status as an emerging growth company or as a smaller reporting company. These costs include (i) being required to comply with the auditor attestation requirements of Section 404, (ii) increased disclosure obligations regarding executive compensation in our periodic reports and proxy statements, and (iii) requirements of holding a nonbinding advisory vote on executive compensation and stockholder approval of any golden parachute payments not previously approved. These additional obligations will require us to dedicate internal resources, engage outside consultants, and adopt a detailed work plan to assess and document the adequacy of internal controls over financial reporting, continue steps to improve control processes, as appropriate, validate through testing that controls are functioning as documented, and implement a continuous reporting and improvement process for internal controls over financial reporting.
Because there are no current plans to pay cash dividends on our Common Stock in the foreseeable future, you may not receive any return on investment unless you sell your shares of our Common Stock at a price greater than what you paid for it.
We intend to retain future earnings, if any, for future operations, expansion and debt repayment and there are no current plans (at least until the resumption of full production at SYU and the repayment or refinancing of the Senior Secured Term Loan) to pay any cash dividends in the near term. The declaration, amount and payment of any future dividends on shares of our Common Stock will be at the sole discretion of our Board and subject to restrictions and limitations in the Senior Secured Term Loan or any other then‑existing indebtedness of the Company. Our Board may take into account general and economic conditions, our financial condition and results of operations, our available cash and current and anticipated cash needs, capital requirements, contractual, legal, tax and regulatory restrictions, implications of the payment of dividends by us to our stockholders or by our subsidiaries to us and such other factors as our Board may deem relevant. As a result, you may not receive any return on an investment in our Common Stock unless you sell your shares of our Common Stock for a price greater than that which you paid for it.
Item 1B. Unresolved Staff Comments
Not applicable.
Item 1C. Cybersecurity
Processes for Assessing, Identifying, and Managing Cybersecurity Risks
Since the completion of the Business Combination on February 14, 2024, Sable management has been working to create a defined cybersecurity risk management program, through the addition of enhanced applications to identify and mitigate risks. During 2025, the Company engaged an experienced third-party vendor, specializing in cybersecurity, to conduct a Company-wide cybersecurity risk assessment. The assessment included a multi-phase approach consisting of open-source intelligence gathering, network system penetration testing of the Company’s internal, external, and wireless networks, and targeted social engineering through strategic phishing, vishing, and smishing campaigns. Action items and preventative recommendations were identified by Sable management and are being incorporated into the Company’s information
46
security incident response plan, which is designed to follow the National Institute of Standards and Technology Cybersecurity Framework 2.0 standards and practices for identifying and mitigating cybersecurity incidents. Sable management implemented phase one of the action items during 2025 and expects to complete implementation of the remaining action items during 2026. Sable management intends to test and further refine our cyber risk management program periodically for effectiveness.
No Previous Material Cybersecurity Threats
As of the date of this report, we are not aware of any previous cybersecurity threats that have materially affected or are reasonably likely to materially affect the Company. However, we acknowledge that cybersecurity threats are continually evolving, and the possibility of future cybersecurity incidents remains. Despite the security and risk management measures that we have implemented and any additional measures we may implement or adopt in the future, our facilities and systems, and those of our third-party service providers, have been and are vulnerable to security breaches, computer viruses, lost or misplaced data, programming errors, scams, burglary, human errors, acts of vandalism, misdirected wire transfers, or other malicious or criminal activities. A successful attack on our information or operational technology systems could have material consequences for the Company. While we intend to devote resources to our security measures to protect our systems and information during 2026, these measures cannot provide absolute security. See “Item 1A. Risk Factors” for additional information about the risks to our business associated with a breach or compromise to our information technology systems.
Board of Directors’ Oversight of Cybersecurity Risks
The audit committee of our Board is responsible for the oversight of risks from cybersecurity threats. As part of its oversight, our audit committee and certain members of the Company’s management will meet periodically to discuss ongoing initiatives and to facilitate coordination between Company stakeholders. Annually, our Vice President of Information Technology will review the Company’s cybersecurity risk management program with our audit committee and Board.
Management’s Role in Assessing and Managing Cybersecurity Risks
Our Vice President of Information Technology is primarily responsible for assessing and managing the Company’s material cybersecurity risks, monitoring the effectiveness of our cybersecurity detection and response processes and providing updates on cybersecurity to our executive team. Our Vice President of Information Technology has more than 25 years of experience working in the field of information technology, including significant experience directing enterprise-level cybersecurity programs.
Item 2. Properties
Our assets consist of three offshore platforms, Hondo, Heritage and Harmony, an onshore oil and natural gas processing facility in Goleta, California and pipeline assets. The platforms are located from five to nine miles offshore Santa Barbara County, California in federal waters. We own and operate 16 federal leases and the Santa Ynez Pipeline System, which includes subsea pipelines, which transport crude oil, natural gas and produced water from the platforms to the onshore processing facilities along with the pipeline assets, Pipeline Segments 324 and 325. Pipeline Segment 324 is a 24-inch, approximately 10.8 mile long crude oil pipeline that extends from the Los Flores Station on the California Coast to the Gaviota Pump Station in Santa Barbara County, California. Pipeline Segment 325 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 Louis Obispo, California. For further information, see “Business—Operations.”
Our principal executive office is located at 845 Texas Avenue, Suite 2800, Houston, Texas 77002. We consider our current office space adequate for our current operations.
Item 3. Legal Proceedings
See Part II, Item 8 “Financial Statements and Supplementary Data—Notes to Consolidated Financial Statements,” Note 8—Commitments and Contingencies for additional information regarding our legal proceedings.
47
Other Legal Proceedings
As part of Sable’s normal business activities, it may be named as a defendant in litigation and other legal proceedings, including those arising from regulatory and environmental matters. If Sable determines that a negative outcome is probable and the amount of loss is reasonably estimable, we will accrue the estimated amount.
Item 4. Mine Safety Disclosures
Not applicable.
48
PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters, and Issuer Purchases of
Equity Securities.
Our Common Stock trades on the NYSE under the symbol “SOC”.
Holders
On February 26, 2026, there were 41 holders of record of our Common Stock, and eight holders of record of our private placement warrants.
Dividend Policy
We have not paid any cash dividends on our Common Stock to date, and have no plans to do so until sometime after SYU sales of production resume. The payment of cash dividends is subject to the discretion of our board of directors and may be affected by various factors, including our future earnings, financial condition, capital requirements, share repurchase activity, current and future planned strategic growth initiatives, levels of indebtedness, and other considerations our board of directors deem relevant.
Stock Performance Graph
The following performance graph compares the cumulative total stockholder return of the Company with the cumulative total returns of the Standard & Poor’s 500 Total Return Index (“S&P 500”) and the SPDR S&P Oil & Gas Exploration and Production ETF (“XOP”). Data for Flame is not included in the performance comparison below, as Flame was a special purpose acquisition company and did not have operating results prior to the closing of the Business Combination. Accordingly, Sable’s stock performance is presented only for periods subsequent to the closing of the Business Combination. The graph assumes an investment of $100 on December 31, 2020 for the S&P 500 and XOP, and December 31, 2023 for Sable.
Item 6. [Reserved]
49
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion and analysis should be read in conjunction with our consolidated financial statements and notes thereto in Item 8. Financial Statements and Supplementary Data of this report. In addition to historical data, this discussion contains forward-looking statements about our business, operations and financial performance based on current expectations that involve risks, uncertainties and assumptions. Our actual results may differ materially from those discussed in the forward-looking statements as a result of various factors, including but not limited to those discussed in “Cautionary Note Regarding Forward-Looking Statements” and Part I, Item 1A. “Risk Factors.”
A discussion of the year ended December 31, 2024, compared to the year ended December 31, 2023, has been reported previously under “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report on Form 10-K for the year ended December 31, 2024, filed with the SEC on March 17, 2025.
Overview
We are a Houston-based independent upstream company focused on responsibly developing the Santa Ynez Unit in federal waters offshore California. Our team has decades of experience safely operating in California and creating value for stakeholders. We have one reportable segment, the oil and gas segment, refer to Note 1—Organization, and Business Operations and Going Concern and Note 2—Significant Accounting Policies in Item 8. Financial Statements and Supplementary Data of this report for further discussion.
For the purposes of this discussion, periods on or before February 13, 2024 reflect the financial position, results of operations and cash flows of SYU prior to the Business Combination, referred to herein as the “Predecessor,” and periods beginning on or after February 14, 2024 reflect the financial position, results of operations and cash flows of the Company as a result of the Business Combination, referred to herein as the “Successor.”
2025 Operational and Financial Highlights
•On May 19, 2025, we announced that (i) as of May 15, 2025, we had restarted production at the Santa Ynez Unit and begun flowing oil production to Las Flores Canyon and (ii) we completed our anomaly repair program on Pipeline Segments 324 and 325 of the Santa Ynez Pipeline System as specified by the Consent Decree.
•On May 23, 2025, we closed an upsized underwritten public offering of 10,000,000 shares of Common Stock at a public offering price of $29.50 per share. The gross proceeds from the offering, before deducting discounts and commissions and estimated expenses, were approximately $295.0 million.
•On May 28, 2025, we announced that we successfully completed hydrotests of all segments of the Santa Ynez Pipeline System, satisfying the final operational condition to resume petroleum transportation through Pipeline Segments 324 and 325 as outlined in the Consent Decree.
•As an alternative to the Santa Ynez Pipeline System, we announced that we are also pursuing an OS&T strategy to provide access to domestic and global markets via shuttle tankers for federal crude oil produced from the Santa Ynez Unit in the Pacific Outer Continental Shelf Area.
•On November 10, 2025, we entered into subscription agreements to issue 45,454,546 shares of Common Stock in a private placement to institutional investors at a purchase price of $5.50 per share, raising $250.0 million in gross proceeds.
•On November 24, 2025, we satisfied all conditions to effectiveness of the Second Amendment to the Senior Secured Term Loan, thereby extending the maturity date of the Senior Secured Term Loan to the earlier of (i) March 31, 2027 or (ii) the date falling 90 days after first sales of hydrocarbons. The Second Amendment increased the interest rate from ten percent (10%) per annum to fifteen percent (15%) per annum, compounded annually.
•On December 17, 2025, PHMSA notified us that it concurred with our determination that the Santa Ynez Pipeline System is an interstate pipeline facility under the Pipeline Safety Act, pursuant to which PHMSA is vested with exclusive regulatory authority over interstate pipelines. In its notification, PHMSA additionally states that it considers the Santa Ynez Pipeline System to be an “active” pipeline according to PHMSA regulations.
50
•On December 23, 2025, PHMSA issued an emergency special permit for segments of the interstate Santa Ynez Pipeline System (specifically Pipeline Segments 324 and 325), related to cathodic protection and seam weld corrosion along Pipeline Segments 324 and 325.
•We reported a net loss of $410.2 million, primarily attributable to production restart related operating expenses, general & administrative expenses, and non-cash interest expense, partially offset by a non-cash change in fair value of warrant liabilities.
•We ended the year with short-term outstanding debt of $921.6 million, inclusive of paid-in-kind interest, and a cash and cash equivalents balance of $97.7 million.
SYU Assets
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. 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 regularly monitored.
The discussion of the results of operations for the Predecessor periods below do not include the results from the Pipeline Segments 324 and 325, and the Pipeline Segments 324 and 325 are not included in the combined financial statements of the Predecessor included in the financial statements and related notes thereto included elsewhere in this Annual Report. Financial statements of the Pipeline Segments 324 and 325 have not been included because SEC guidance provides that the financial statements of recently acquired businesses such as the Pipeline Segments 324 and 325 need not be filed unless their omission would render Predecessors combined financial statements misleading or substantially incomplete. Based upon our quantitative and qualitative analysis, we do not believe omitting the financial statements of the Pipeline Segments 324 and 325 renders the Predecessor combined financial statements misleading or substantially incomplete. The Successor financial statements include the results from the Pipeline Segments 324 and 325 and the Pipeline Segments 324 and 325 are included in the consolidated financial statements.
Outlook
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.
Recommencing Oil Sales
Our near-term outlook is highly dependent on our ability to recommence oil transportation through the Santa Ynez Pipeline System. As previously noted, PHMSA confirmed that the Santa Ynez Pipeline System is classified as active interstate pipeline subject to federal jurisdiction under the Pipeline Safety Act. Additionally, we received an Emergency Special Permit from PHMSA related to cathodic protection and seam weld corrosion along Pipeline Segments 324 and 325. This permit is conditional in nature and 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.
51
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.
We 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 commissioning Pipeline Segments 324 and 325, could materially delay the resumption of commercial oil sales and adversely affect future revenues and cash flows. “Risk Factors—We are subject to complex federal, state, local and other laws, regulations and permits that could adversely affect the cost, manner, ability or feasibility of conducting our operations.”
Offshore Storage and Treating Vessel (OS&T) Alternative
In parallel with pursuing oil sales via Santa Ynez Pipeline System, we continue to evaluate an OS&T vessel as a potential alternative pathway to market crude oil. Under this concept, produced fluids would be processed offshore, stored on a floating vessel, and periodically offloaded to shuttle tankers for delivery to third-party purchasers.
The OS&T Strategy is significantly more capital-intensive than the Santa Ynez Pipeline System, requiring an estimated capital investment of approximately $475.0 million, inclusive of vessel acquisition, configuration, offshore integration, regulatory compliance, and related infrastructure. Based on current assessments, we do not expect to commence commercial oil sales under an OS&T Strategy until approximately the fourth quarter of 2026, assuming timely execution, regulatory approvals, and availability of capital.
While the OS&T Strategy could reduce reliance on the Santa Ynez Pipeline System, which may enhance our marketing strategy going forward by providing flexibility to sell production to additional purchasers through the OS&T rather than being limited to a purchaser under a pipeline-only sales configuration, it presents substantial execution, financing, regulatory, and operational risks. These risks include vessel availability, permitting complexity, higher operating costs, exposure to marine operational risks, and uncertainty regarding the economic returns relative to pipeline transportation. We have not made a final investment decision with respect to an OS&T vessel, and there can be no assurance that such a project would be pursued, financed, or completed on acceptable terms, if at all. See “Risk Factors—Risks Associated with Our Operations—In order to commence operations pursuant to an OS&T offtake strategy, we will require clearances and permitting, including from BOEM” and “Risk Factors—Risks Associated with Our Operations—Our assumptions and estimates regarding the total costs associated with recommencing oil sales may be inaccurate.”
Legal and Regulatory Environment
The Company’s assets are located in California, a jurisdiction with a complex regulatory framework and heightened environmental oversight. PHMSA’s approvals related to the Santa Ynez Pipeline System have been challenged by third parties through litigation, and the outcome of such proceedings is uncertain. Adverse court rulings, including the issuance of injunctions or stays, could delay or prevent pipeline operations regardless of the Company’s technical readiness.
In addition to federal oversight, the Company remains subject to state and local regulatory agencies, including the California Geologic Energy Management Division and other environmental and land-use authorities. While these agencies do not directly regulate interstate pipeline safety, their actions may affect related permits, inspections, or operational approvals, which could influence the timing, cost, or feasibility of both pipeline and OS&T-based solutions.
We are involved in various legal and regulatory proceedings, including matters related to our pipeline operations and permitting activities, which are at various stages of resolution; while these matters are subject to inherent uncertainty, we currently believe that the outcomes are not probable of resulting in a material loss and, accordingly, no litigation-related accruals have been recorded as of the reporting date. Refer to Part II, Item 8, “Financial Statements and Supplementary Data – Notes to the Consolidated Financial Statements, Note 8—Commitments and Contingencies” for further information regarding ongoing litigation.
Production Ramp-Up and Operational Execution
Assuming a transportation solution is established, our future performance will depend on our ability to safely ramp up offshore production, manage operating costs, and maintain asset integrity following an extended period of curtailed operations. Restarting production from offshore facilities involves inherent operational risks, including mechanical failures, unplanned downtime, and higher-than-expected maintenance or remediation costs, any of which could adversely affect production volumes and operating margins.
52
Capital and Financing Requirements
Until sustained commercial oil sales are achieved, our liquidity will depend on available cash balances, access to raise additional capital from investors, and the timing of expenditures related to regulatory compliance, litigation, offshore facility maintenance, and potential alternative transportation solutions. The OS&T vessel alternative, in particular, would require substantial external financing or strategic arrangements and could materially increase our leverage or dilution. There can be no assurance that such financing would be available on acceptable terms, or at all.
Capital Expenditures. During 2025, we funded $417.6 million in development and other property, plant and equipment expenditures primarily by utilizing net cash provided by our financing activities and cash on hand.
We currently estimate no remaining start-up expenses to recommence oil sales via the Santa Ynez Pipeline System, other than applicable legal expenses. Upon resuming petroleum transportation through the Santa Ynez Pipeline System, we anticipate approximately $100.0 million to $200.0 million in additional post-sales capital expenditures for 2026, primarily related to facilities, pipeline ramp-up activities, and other property, plant and equipment, depending on timing and excluding any OS&T-related capital expenditures. Alternatively, if we elect to pursue the OS&T Strategy, total anticipated 2026 capital expenditures are estimated to be approximately $475.0 million, including costs to acquire and purchase the vessel in addition to incremental investments associated with related infrastructure. Depending on the timing and outcome of regulatory approvals and the execution of commercial arrangements, we could incur capital expenditures beyond these ranges. We cannot provide any assurances that our assumptions used to estimate our liquidity requirements, our anticipated cost savings or reductions, or the costs required to achieve operations under the OS&T Strategy will be correct, as we have not previously undertaken such actions and as a consequence, our ability to predict such amounts is uncertain and may be impacted by factors outside of our control.
Debt Financing. As of December 31, 2025, we had gross indebtedness of $921.6 million outstanding under the Senior Secured Term Loan, (refer to Note 6—Debt to the consolidated financial statements). On November 3, 2025, we entered into the Second Debt Amendment, which became effective on November 24, 2025 following the completion of the Third PIPE Investment and satisfaction of all conditions to effectiveness. Pursuant to the Second Debt Amendment, the maturity date of the Senior Secured Term Loan was extended to the earlier of (i) March 31, 2027 or (ii) 90 days after the Company’s first sales of hydrocarbons. In connection with the Second Debt Amendment, the interest rate on the Senior Secured Term Loan increased from ten percent (10.0%) per annum to fifteen percent (15.0%) per annum, computed on a 360-day year, compounded annually, and payable in arrears on January 1 of each year. Notwithstanding the maturity extension, the Senior Secured Term Loan is classified as a current liability on the Company’s consolidated balance sheet as of December 31, 2025 due to management’s expected maturity date based on anticipated first sales from SYU.
After we are able to recommence oil sales and improve our operating cash flows, we expect to pursue a refinancing of the Senior Secured Term Loan, which may include a new credit facility, term notes, or other debt capital market transactions. We believe that demonstrating sustained oil sales and cash flow generation in the future could improve our access to financing and potentially reduce our overall cost of capital. Any refinancing would be subject to market conditions, lender requirements, regulatory developments, and other factors outside our control. There can be no assurance that such a refinancing will be completed on favorable terms, or at all.
Components of Results of Operations
Revenue
The Company has not had any substantial revenues since its inception. The Company’s various operating expenses are the principal metrics used to assess its performance.
Operating Expenses
•Operations and maintenance. The Company’s most significant costs to operate and maintain its assets are direct labor and supervision, power, repair and maintenance expenses, and equipment rentals. Fluctuations in commodity prices impact operating cost elements both directly and indirectly. For example, commodity prices directly impact costs such as power and fuel, which are expenses that increase (or decrease) in line with changes in commodity prices. Commodity prices also affect industry activity and demand, thus indirectly impacting the cost of items such as labor and equipment rentals.
•Depreciation, depletion, amortization, and accretion. Depreciation, depletion and amortization are primarily determined under either the unit-of-production method or the straight-line method, which is based on estimated asset service life taking obsolescence into consideration. Since 2015 when production temporarily ceased, no depletion has been expensed for the Successor periods presented. However, depletion associated
53
with the current production has been capitalized to Inventory for produced barrels in storage at SYU (see further discussion in Note 2—Significant Accounting Policies to the consolidated financial statements). An immaterial amount of depreciation was reflected for idle plants in the historical Predecessor financial statements. Also included in the Successor and Predecessor financial statements is the accretion associated with the Company’s estimated asset retirement obligations (“ARO”). The ARO liabilities are initially recorded at their fair value and then are accreted using the Company’s applicable discount rate over the period for the change in their present value until the estimated retirement of the asset.
•General and administrative. General and administrative (“G&A”) costs are comprised of overhead expenditures directly and indirectly associated with operating the assets. These support services include information technology, risk management, corporate planning, accounting, cash management, human resources, and other general corporate services. For the Predecessor period, any general and administrative expenses that were not specifically identifiable to SYU were allocated to SYU for the period from January 1, 2024 to February 13, 2024. To calculate a reasonable allocation, aggregated historical benchmarking data from comparable companies with similar operated upstream assets was used to identify general and administrative expenses as a proportion of operating expenses. Increased general and administrative services may be required in the future, commensurate with planned operations activity levels.
•Taxes other than income. Management anticipates future increases in ad valorem taxes, in line with the projected restarting sales of production volumes.
Results of Operations
This section discusses certain year-to-year comparisons between year ended December 31, 2025 (Successor) vs. the periods from January 1, 2024 through February 13, 2024 (Predecessor) and February 14, 2024 through December 31, 2024 (Successor), which should be read in conjunction with the consolidated financial statements and notes thereto in Item 8. Financial Statements and Supplementary Data of this report.
The following table presents selected consolidated financial results of operations for the Successor and Predecessor periods presented.
54
Year Ended December 31, 2025 (Successor) vs. the periods from January 1, 2024 through February 13, 2024 (Predecessor) and February 14, 2024 through December 31, 2024 (Successor).
The following table presents selected consolidated financial results of operations for the Successor and Predecessor periods presented.
| Successor | Predecessor | Increase (Decrease) | ||||||||||||||||||||||||||||||
| (in thousands) | Year Ended December 31, 2025 | February 14—December 31, 2024 | January 1—February 13, 2024 | $ | % | |||||||||||||||||||||||||||
| Revenue | ||||||||||||||||||||||||||||||||
| Oil and gas sales | $ | — | $ | — | $ | — | $ | — | — | |||||||||||||||||||||||
| Total Revenue | — | — | — | — | — | |||||||||||||||||||||||||||
| Operating Expenses | ||||||||||||||||||||||||||||||||
| Operations and maintenance expenses | 219,198 | 87,877 | 7,320 | 124,001 | 130 | % | ||||||||||||||||||||||||||
| Depletion, depreciation, amortization and accretion | 12,888 | 9,734 | 2,627 | 527 | 4 | % | ||||||||||||||||||||||||||
| General and administrative expenses | 176,197 | 229,140 | 1,714 | (54,657) | (24) | % | ||||||||||||||||||||||||||
| Total operating expenses | 408,283 | 326,751 | 11,661 | 69,871 | 21 | % | ||||||||||||||||||||||||||
| Loss from operations | (408,283) | (326,751) | (11,661) | (69,871) | 21 | % | ||||||||||||||||||||||||||
| Other (income) expenses: | ||||||||||||||||||||||||||||||||
| Change in fair value of warrant liabilities | (89,203) | 227,454 | — | (316,657) | nm | |||||||||||||||||||||||||||
| Other (income) expense | (8,834) | (4,193) | 128 | (4,769) | nm | |||||||||||||||||||||||||||
| Interest expense | 88,245 | 67,314 | — | 20,931 | nm | |||||||||||||||||||||||||||
| Total other (income) expense, net | (9,792) | 290,575 | 128 | (300,495) | nm | |||||||||||||||||||||||||||
| Loss before income taxes | (398,491) | (617,326) | (11,789) | 230,624 | (37) | % | ||||||||||||||||||||||||||
| Income tax expense (benefit) | 11,671 | (48) | — | 11,719 | nm | |||||||||||||||||||||||||||
| Net loss | $ | (410,162) | $ | (617,278) | $ | (11,789) | $ | 218,905 | (35) | % | ||||||||||||||||||||||
nm: not meaningful | ||||||||||||||||||||||||||||||||
Operating and maintenance expenses. Operating and maintenance expenses were $219.2 million for the year ended December 31, 2025, representing an increase of $124.0 million, or 130%, compared to $7.3 million for the period from January 1, 2024 through February 13, 2024 (Predecessor) and $87.9 million for the period February 14, 2024 through December 31, 2024 (Successor), respectively, or a combined $95.2 million. The increase in operating and maintenance expenses is primarily attributable to additional maintenance expenses incurred in connection with restart efforts, which includes a 37% increase in operations employee headcount since the prior year, $28.0 million related to operator rights expenditures, and $6.6 million related to restart incentive compensation, partially offset by $6.1 million of operating expense capitalized as Inventory on the consolidated balance sheet as of December 31, 2025. Operations and maintenance expenses are expected to remain elevated prior to our commencement of sales of production.
Depletion, depreciation, amortization and accretion. Depletion, depreciation, amortization and accretion was $12.9 million for the year ended December 31, 2025, representing an increase of $0.5 million, or 4%, compared to $2.6 million for the period January 1, 2024 through February 13, 2024 (Predecessor) and $9.7 million for the period February 14, 2024 through December 31, 2024 (Successor), respectively, or a combined $12.4 million. The increase between comparative periods is attributable to ARO accretion and its compounding effect year over year. Depletion, depreciation and amortization of $6.0 million associated with the SYU Assets was recognized during the year ended December 31, 2025; however, as the associated production remained in the Company’s storage tanks as of December 31, 2025, the entire amount has been capitalized as Inventory on the consolidated balance sheet. Recognition of depletion expense will resume once sales volumes are achieved. Depletion, depreciation, amortization and accretion expense is expected to increase prior to our commencement of sales of production.
General and administrative expenses. G&A expenses were $176.2 million for the year ended December 31, 2025, representing a decrease of $54.7 million compared to $1.7 million for the period January 1, 2024 through February 13, 2024 (Predecessor) and $229.1 million for the period February 14, 2024 through December 31, 2024 (Successor), respectively, or a combined $230.9 million. This decrease is primarily attributable to higher non-recurring G&A expenses recognized for the period February 14, 2024 through December 31, 2024 (Successor) such as the $70.0 million accrued
55
settlement of the Grey Fox Matter (Refer to Note 8—Commitments and Contingencies) and $16.8 million in legal expenses and professional fees related to the Business Combination. Also contributing to the decrease in G&A expenses was a $49.0 million decrease in share-based compensation expense between reporting periods. These decreases were partially offset by $35.7 million in higher compensation related to restart incentive compensation costs, $29.7 million in higher legal expenses and professional fees attributable to our continued pursuit of achieving first sales, and the recognition of salaries and wages for the full year ended December 31, 2025, compared to the Successor period February 14, 2024 through December 31, 2024. Predecessor G&A expenses were allocated to SYU as a portion of certain other operating costs based on aggregated historical benchmarking data as previously noted (Refer to Note 2—Significant Accounting Policies).
Total other (income) expense, net. Total other income, net was $9.8 million for the year ended December 31, 2025 compared to other expense, net of $0.1 million for the period January 1, 2024 through February 13, 2024 (Predecessor) and other expense of $290.6 million for the period February 14, 2024 through December 31, 2024 (Successor), respectively, or a combined expense of $290.7 million, representing a favorable year-over-year change of $300.5 million. The change in total other (income) expense, net was primarily attributable to a decrease of $316.7 million in the fair value of the warrants, due to fewer warrants outstanding for the year ended December 31, 2025 after all public warrants were redeemed during the year ended December 31, 2024, an increase in the market price of the Common Stock in the prior period compared to a decrease in the market price of the Common Stock in the current year, and a $4.8 million decrease in other (income) expense attributable to $5.0 million of other expense recognized during the period February 14, 2024 through December 31, 2024 (Successor) related to the First Amendment to the Senior Secured Term Loan (Refer to Note 6—Debt for additional details regarding the First Amendment to the Senior Secured Term Loan), partially offset by $20.9 million in higher interest expense for the year ended December 31, 2025 due to higher debt balance over the comparative periods and the increased interest rate following the Second Debt Amendment (Refer to Note 6—Debt for additional details regarding the Second Debt Amendment). The Predecessor did not have any debt or associated interest expense, warrants, or interest income.
Income tax expense (benefit). Income tax expense for the year ended December 31, 2025 was $11.7 million, representing an increase of $11.7 million compared to zero for the period January 1, 2024 through February 13, 2024 (Predecessor) and less than $0.1 million for the period February 14, 2024 through December 31, 2024 (Successor), respectively, or a combined less than $0.1 million. Utilizing provisions of ASC 740, the Company’s effective tax rate was negative 2.9%, and less than negative 0.01% for the year ended December 31, 2025 and the period February 14, 2024 through December 31, 2024 (Successor) respectively. The negative tax rates were due to our ongoing assessment of our ability to recover our deferred tax assets, in which we concluded that it was more likely than not that our deferred tax assets in excess of deferred tax liabilities would not be realized. The negative income tax rate was greater for the year ended December 31, 2025 due to an increase in the valuation allowance primarily associated with net operating losses not expected to be realized in future periods.
Liquidity and Capital Resources
Overview. Our plans for recommencing sales of production volumes, including restarting the remainder of the existing wells and facilities that have not been restarted and recommencing oil transportation through the Santa Ynez Pipeline System or via OS&T, will require significant capital expenditures in excess of current operational cash flow. Historically, SYU’s primary source of liquidity has been its operational cash flow and, since 2015 when production temporarily ceased, capital contributions from its parent. While production has restarted, prior to generating sales and positive cash flow from production, our capital expenditure needs have been and will continue to be substantial.
As of December 31, 2025, we had unrestricted cash and cash equivalents of $97.7 million. Our total debt as of December 31, 2025 was $921.6 million, comprised of principal and paid-in-kind accrued interest on the Senior Secured Term Loan, which matures on the earlier of (i) March 31, 2027 or (ii) the date falling 90 days after first sales of Hydrocarbons (as defined in the Senior Secured Term Loan, refer to further discussion of the Second Debt Amendment at Note 6—Debt in the consolidated financial statements).
Capital Raising Activities. Prior to the Business Combination, Flame had approximately $62.2 million in its trust account, which consisted of proceeds from the public stockholders and the private placement investors in connection with the Company’s initial public offering, less redemptions. On the Closing Date, the Company issued 44,024,910 shares of Common Stock of the Company, at a price of $10.00 per share for aggregate gross proceeds of $440.2 million (the “First PIPE Investment”). On September 26, 2024, the Company issued 7,500,000 shares of Common Stock of the Company, at a price of $20.00 per share for aggregate gross proceeds of approximately $150.0 million (“Second PIPE Investment”).
56
Additionally, the Company received approximately $183.5 million in gross proceeds from the exercise of 15,957,820 warrants for 15,957,820 shares of Common Stock.
In May 2025, the Company raised an additional $295.0 million in gross proceeds from the sale of 10,000,000 shares of Common Stock in the 2025 Offering. On November 12, 2025, the Company issued 45,454,546 shares of Common Stock of the Company, at a price of $5.50 per share for aggregate gross proceeds of approximately $250.0 million (“Third PIPE Investment”). Further, more than $600 million of the Purchase Price (as defined in the Senior Secured Term Loan) was seller-financed through the Senior Secured Term Loan.
On February 2, 2026, the Company established an “at-the-market” equity offering program pursuant to a sales agreement with TD Securities (USA) LLC and Jefferies LLC (collectively, the “Sales Agents”) under which the Company may offer and sell, at its discretion, shares of its Common Stock from time to time. The aggregate offering size under the program is up to $250.0 million of Common Stock, and any sales completed by the Sales Agents thereunder will be made pursuant to the Company’s effective shelf registration statement on Form S-3 and an accompanying prospectus supplement. The Company expects to use the net proceeds from any sales under the program for general corporate purposes, and restart-related capital expenditures.
Liquidity Requirements and Capital Expenditures. We currently estimate no remaining start-up expenses to recommence oil sales via the Santa Ynez Pipeline System, other than applicable legal expenses. Upon resuming petroleum transportation through the Santa Ynez Pipeline System, we anticipate approximately $100.0 million to $200.0 million in additional post-sales capital expenditures for 2026, primarily related to facilities, pipeline ramp-up activities, and other property, plant and equipment, depending on timing and excluding any OS&T-related capital expenditures. Alternatively, if we elect to pursue the OS&T Strategy, total anticipated 2026 capital expenditures are estimated to be approximately $475.0 million, including costs to acquire and purchase the vessel in addition to incremental investments associated with related infrastructure. Depending on the timing and outcome of regulatory approvals and the execution of commercial arrangements, we could incur capital expenditures beyond these ranges. We cannot provide any assurances that our assumptions used to estimate our liquidity requirements, our anticipated cost savings or reductions, or the costs required to achieve operations under the OS&T Strategy will be correct, as we have not previously undertaken such actions and as a consequence, our ability to predict such amounts is uncertain and may be impacted by factors outside of our control.
After either (i) resumption of oil sales through the Santa Ynez Pipeline System, or (ii) continued receipt of clearance from regulators with respect to the OS&T Strategy, we expect to pursue additional debt financing options, which may include the issuance of public or private debt securities, bank financing or a combination thereof. However, there can be no assurance that we will be able to obtain such additional debt financing on commercially agreeable terms, or at all. After sales of production commences, we expect an increase in operating cash flows that should allow us to fund further capital expenditures. If we are unable to obtain funds or provide funds as needed for the planned capital expenditure program, we may not be able to finance the capital expenditures necessary to restart production sales or sustain production thereafter.
Going Concern
Since the Business Combination the Company has been strictly focused on recommencing oil sales from the SYU Assets, including capital expenditures to repair and maintain the SYU Assets. Much like other pre-revenue companies, the Company has experienced losses from operations and has negative cash flows from operations since inception. We have addressed near-term capital funding needs with proceeds from the First PIPE Investment, the Second PIPE Investment, the exercise of Warrants (refer to Note 7—Warrants for additional details regarding the warrant exercises), the 2025 Offering, and the Third PIPE Investment. However, our plans for recommencement of sales of production are contingent upon approvals from federal, state and local regulators.
As of December 31, 2025, the Company reported unrestricted cash of $97.7 million, total debt of $921.6 million, and an accumulated deficit of $1.1 billion. On November 20, 2025 the maturity date was successfully extended upon the effectiveness of the Second Debt Amendment to the earlier of (i) March 31, 2027 or (ii) the date falling 90 days after first sales of Hydrocarbons (as defined in the Senior Secured Term Loan, refer to Note 6—Debt for additional details regarding the Second Debt Amendment).
If our estimates of the costs to reach first sales via the Santa Ynez Pipeline System or the OS&T are less than the actual amounts necessary to do so, we may have insufficient funds available to operate our business prior to first sales of production and will need to raise additional capital. If we are unable to raise additional capital, we may be required to take additional measures to conserve liquidity, which could include, among other things, reducing overhead expenses.
Due to the uncertainty regarding our resumption of sales of production volumes, and lack of assurance that new financing, or refinancing of the Senior Secured Term Loan, will be available to us on commercially acceptable terms, if at all,
57
substantial doubt exists about the Company’s ability to continue as a going concern. The financial statements included in this annual report do not include any adjustments relating to the recovery of the recorded assets or the classification of the liabilities that could be necessary if the Company is unable to continue as a going concern.
Cash Flows
The following table summarizes cash flows from Operating, Investing and Financing activities:
| Successor | Predecessor | Change | ||||||||||||||||||||||||||||||
| (dollars in thousands) | Year Ended December 31, 2025 | February 14—December 31, 2024 | January 1—February 13, 2024 | $ | % | |||||||||||||||||||||||||||
| Cash flows (used in) provided by: | ||||||||||||||||||||||||||||||||
| Operating activities | $ | (351,702) | $ | (162,968) | $ | (22,474) | $ | (166,260) | (90) | % | ||||||||||||||||||||||
| Investing activities | (417,624) | (276,247) | — | (141,377) | (51) | % | ||||||||||||||||||||||||||
| Financing activities | 531,238 | 721,653 | 22,474 | (212,889) | (29) | % | ||||||||||||||||||||||||||
| Net change in cash and cash equivalents | $ | (238,088) | $ | 282,438 | $ | — | ||||||||||||||||||||||||||
Cash Flows from Operating Activities. Since petroleum has not been transported through Pipeline Segments 324 and 325, no operating revenues have been recognized for the comparative periods. The net cash used in operating activities for the Company was $351.7 million for the year ended December 31, 2025, representing an increase in cash used in operating activities of $166.3 million, or 90%, compared to net cash used in operating activities of $22.5 million for the period January 1, 2024 through February 13, 2024 (Predecessor) and $163.0 million net cash used in operating activities from February 14, 2024 through December 31, 2024 (Successor), respectively, or a combined $185.4 million. The primary use of cash can be attributed to maintenance and operational readiness activities in the Predecessor and Successor periods, with additional general and administrative costs incurred post the Business Combination in the Successor period.
For the year ended December 31, 2025, we had a net loss of $410.2 million, which consists of a non-cash decrease of $89.2 million in fair value of the warrants, non-cash paid-in-kind interest of $87.7 million, non-cash stock-based compensation of $42.7 million, non-cash tax expense of $11.7 million, and non-cash depreciation, depletion, amortization and accretion of $12.9 million. Changes in Inventory for the period of $6.1 million is attributable to the cash paid for expenses capitalized as Inventory on the consolidated balance sheet as of December 31, 2025 and changes of Prepaid expenses and other assets for the period of $7.5 million is attributable to the cash paid for future period expenses, net of non-cash amortization of such payments. For the period January 1, 2024 through February 13, 2024 (Predecessor), SYU incurred a net loss of $11.8 million and for the period February 14, 2024 through December 31, 2024 (Successor) the Company incurred a net loss of $617.3 million, respectively, or a combined $629.1 million. Our combined net loss was partially offset by a non-cash increase in the fair value of our warrant liabilities of $227.5 million, non-cash stock based compensation of $91.6 million, and non-cash paid-in-kind interest $66.3 million. Changes in accounts payable of $46.0 million is primarily attributable to the Grey Fox Matter settlement, with $35.0 million in accounts payable and accrued liabilities as of December 31, 2024 (Refer to Note 2—Significant Accounting Policies). Future cash flow from operations will depend on our ability to recognize sales of production volumes, as well as the prices of oil, natural gas and NGLs.
Cash Flows from Investing Activities. Net cash used in investing activities was $417.6 million for the year ended December 31, 2025, representing an increase in cash used in investing activities of $141.4 million, or 51%, compared to the net cash used investing activities of zero for the period January 1, 2024 through February 13, 2024 (Predecessor) and $276.2 million for the period February 14, 2024 through December 31, 2024 (Successor), or a combined $276.2 million. Investing cash flow for the year ended December 31, 2025 consists of cash paid for capital expenditures associated with restart efforts and for the period February 14, 2024 through December 31, 2024 (Successor) is comprised of $203.9 million paid to EM at Closing per settlement statement and $72.3 million paid for capital expenditures associated with restart efforts. There was no net cash used in investing activities for the Predecessor period since production from the SYU Assets temporarily ceased in 2015 and had no investing activities.
Cash Flows from Financing Activities. Net cash provided by financing activities was $531.2 million for the year ended December 31, 2025, consisting of $545.0 million in aggregate gross proceeds from our 2025 offerings, net of related fees paid of $13.8 million. Net cash provided by financing activities for the period January 1, 2024 through February 13, 2024 (Predecessor) was $22.5 million and net cash provided by financing activities for the period February 14, 2024 through December 31, 2024 (Successor) was $721.7 million, respectively, or a combined $744.1 million.
58
Financing activities for the period January 1, 2024 through February 13, 2024 (Predecessor) consists of EM capital contributions financing the maintenance and operational readiness activities. Financing activities for the period February 14, 2024 through December 31, 2024 (Successor) are comprised of $440.2 million of gross proceeds from the First PIPE Investment, $150.0 million of gross proceeds from the Second PIPE Investment, or $590.2 million in aggregate gross private offering proceeds, net of $30.6 million of capitalized transaction expenses, or $559.7 million net, plus $183.5 million net cash received from warrant exercises, less deposit paid to EM for the Term Loan of $18.8 million, payment of debt issuance costs of $1.6 million, and repayment of Flame non-convertible promissory notes — related parties for $1.1 million.
Contractual Obligations
Pursuant to the Senior Secured Term Loan, which financed most of the Purchase Price (as defined in the Senior Secured Term Loan), Sable incurred interest for the period prior to the effectiveness of the Second Debt Amendment of ten percent (10%) per annum, and fifteen percent (15%) per annum subsequent to the Second Debt Amendment, compounded annually (refer to Note 6—Debt for additional details regarding the Second Debt Amendment). Interest on the Senior Secured Term Loan is payable in arrears on January 1st of each year but, at Sable’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. On December 13, 2024, the Company entered into the Fourth Amendment to the Sable-EM Purchase Agreement, pursuant to which the following definitions were amended. “Restart Production” was redefined as 150 days after first production, extending the maturity date of the EM Term Loan by 60 days. “Restart Failure Date” was extended an additional 60 days to March 1, 2026.
On May 15, 2025, the Company restarted production at SYU and as a result, required the Senior Secured Term Loan to be refinanced or otherwise paid in full within 240 days following such first production date, or January 9, 2026. On November 24, 2025 the Second Debt Amendment became effective and extended the maturity date to the earlier of (i) March 31, 2027 or (ii) the date falling 90 days after first sales of Hydrocarbons (as defined in the Senior Secured Term Loan).
Additional obligations include the performance of ARO as referenced under “Critical Accounting Policies and Estimates—Asset Retirement Obligations” below.
Off Balance Sheet Arrangements
As of December 31, 2025, the Company had no off-balance sheet arrangements.
Critical Accounting Estimates
The preparation of consolidated financial statements and related disclosures in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the combined financial statements, and income and expenses during the periods reported. Actual results could materially differ from those estimates.
Property, Plant and Equipment.
Cost Basis. Oil and gas producing activities are accounted for under the successful efforts method of accounting. Under this method, costs are accumulated on a field-by-field basis. Costs incurred to purchase, lease, or otherwise acquire a property (whether unproved or proved) are capitalized when incurred. Exploratory well costs are carried as an asset when the well has found a sufficient quantity of resources to justify its completion as a producing well and where sufficient progress assessing the resources and the economic and operating viability of the project is being made. Exploratory well costs not meeting these criteria are charged to expense. Other exploratory expenditures, including geophysical costs and annual lease rentals, are expensed as incurred. Development costs, including costs of productive wells and development dry holes, are capitalized.
Other Property and Equipment. Other property and equipment primarily consist of onshore midstream facilities, transportation assets and assets related to the Company’s corporate office (the “Office Assets”). Due to the nature of such assets, the onshore midstream facilities are presented within oil and gas properties, while the transportation assets and the Office Assets are presented within other assets on the consolidated balance sheets.
Depreciation, Depletion and Amortization. Depreciation, depletion and amortization are primarily determined under the unit-of-production method, which is based on estimated asset service life taking obsolescence into consideration.
Acquisition costs of proved properties are amortized using a unit-of-production method, computed on the basis of total proved oil and natural gas reserve volumes. Capitalized exploratory drilling and development costs associated with
59
productive depletable extractive properties are amortized using the unit-of-production rates based on the amount of proved developed resources of oil and gas that are estimated to be recoverable from existing facilities using current operating methods. Under the unit-of-production method, oil and natural gas volumes are considered produced once they have been measured through meters at custody transfer or sales transaction points at the outlet valve on the lease or field storage tank. Maintenance and repairs, including planned major maintenance, are expensed as incurred. Major renewals and improvements are capitalized and the assets replaced are retired.
The SYU Assets had not produced oil and gas since 2015 due to a pipeline incident but had been maintained by EM to preserve it in an operation-ready state and thus no depletion had been recognized prior to achieving first production on May 15, 2025. Depletion, depreciation and amortization of $6.0 million associated with the SYU Assets was recognized during the year ended December 31, 2025; however, as the associated production remained in the Company’s storage tanks as of December 31, 2025, the entire amount has been capitalized as Inventory on the consolidated balance sheet. The recognition of depletion expense on the consolidated statement of operations will commence upon the commencement of sales of production.
Inventory. Production volumes for the period from May 15, 2025 through December 31, 2025 were retained within the Company’s storage tanks and recognized as short term oil inventory, and the associated depletion expense was capitalized, as noted above. ASC 330 dictates that inventory shall initially be valued at the price paid or consideration given to acquire an asset. By analogy, the Company capitalized the costs incurred that were directly attributable to producing and transporting the production to the onshore storage tanks, including associated depreciation, depletion, and amortization. Inventory is presented as its own line in the consolidated balance sheet.
The Company has oil inventory storage capacity of 540 MBbls onshore at LFC. The Company generally expects the inventory volumes to fluctuate over time to maintain optimal operational efficiencies. The ending volume of inventory that remains in the onshore storage tanks is measured at the current period’s cost, and a lower of cost or net realizable value assessment is performed for each reporting period.
Impairment Assessment. Assets are tested for recoverability on an ongoing basis whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable. Among the events or changes in circumstances which could indicate that the carrying value of an asset or asset group may not be recoverable are the following:
•a significant decrease in the market price of a long-lived asset;
•a significant adverse change in the extent or manner in which an asset is being used or in its physical condition, including a significant decrease in current and projected resource or reserve volumes;
•a significant adverse change in legal factors or in the business climate that could affect the value, including an adverse action or assessment by a regulator;
•an accumulation of project costs significantly in excess of the amount originally expected; and
•a current-period operating loss combined with a history and forecast of operating or cash flow losses.
We monitor for indicators of potential impairment throughout the year. This process is aligned with the requirements of ASC 360 and ASC 932. Asset valuation analysis, profitability reviews and other periodic control processes assist in assessing whether events or changes in circumstances indicate the carrying amounts of any of the assets may not be recoverable.
If events or changes in circumstances indicate that the carrying value of an asset may not be recoverable, management estimates the future undiscounted cash flows of the affected properties to judge the recoverability of carrying amounts. In performing this assessment, assets are grouped at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets. Cash flows used in recoverability assessments are based on assumptions which are developed by management and are consistent with the criteria management uses to evaluate investment opportunities. These evaluations make use of assumptions of future capital allocations, crude oil and natural gas commodity prices including price differentials, refining and chemical margins, volumes, and development and operating costs. Volumes are based on projected field and facility production profiles, throughput, or sales. Management’s estimate of upstream production volumes used for projected cash flows makes use of proved reserve quantities and may include risk-adjusted unproved reserve quantities.
An asset group is impaired if its estimated undiscounted cash flows are less than the asset group’s carrying value. Impairments are measured by the amount by which the carrying value exceeds fair value. The assessment of fair value is
60
based upon the views of a likely market participant. The principal parameters used to establish fair value include estimates of acreage values and flowing production metrics from comparable market transactions, market-based estimates of historical cash flow multiples, and discounted cash flows. Inputs and assumptions used in discounted cash flow models include estimates of future production volumes, throughput and product sales volumes, commodity prices which are consistent with the average of third-party industry experts and government agencies, refining and chemical margins, drilling and development costs, operating costs and discount rates which are reflective of the characteristics of the asset group.
Asset Retirement Obligations. The Company’s ARO primarily relate to the future plugging and abandonment of oil and gas properties and related facilities. The fair values of these obligations are recorded as liabilities on a discounted basis, which is typically at the time the assets are installed. In the estimation of fair value, the Company uses assumptions and judgments regarding such factors as the existence of a legal obligation for an asset retirement obligation, technical assessments of the assets, estimated amounts and timing of settlements, discount rates, and inflation rates.
Derivative Warrant Liabilities. We do not use derivative instruments to hedge exposures to cash flow, market, or foreign currency risks. We evaluate all of our financial instruments, including issued stock purchase warrants, to determine if such instruments are derivatives or contain features that qualify as embedded derivatives, pursuant to ASC 480 and ASC 815-15. The classification of derivative instruments, including whether such instruments should be recorded as liabilities or as equity, is re-assessed at the end of each reporting period.
All of our outstanding warrants are recognized as derivative liabilities in accordance with ASC 815-40. Accordingly, we recognize the warrant instruments as liabilities at fair value and adjust the instruments to fair value at each reporting period. The liabilities are subject to re-measurement at each balance sheet date until exercised, and any change in fair value is recognized in our statement of operations. The private placement warrants and the working capital warrants are measured at fair value using the Modified Black-Scholes Optional Pricing Model.
Recent Accounting Pronouncements
In November 2024, the FASB issued ASU 2024-03, Income Statement — Reporting Comprehensive Income — Expense Disaggregation Disclosures (Subtopic 220-40) — “Disaggregation of Income Statement Expenses.” The FASB issued this ASU to improve the disclosures about a public business entity’s expenses and address requests from investors for more detailed information about the types of expenses (including purchases of inventory, employee compensation, depreciation, amortization, and depletion) in commonly presented expenses captions (such as cost of sales, SG&A, and research and development). The amendments in this ASU are effective for annual periods beginning after December 15, 2026, and interim reporting periods beginning after December 15, 2027. Early adoption is permitted. The Company is currently reviewing what impact, if any, adoption will have on its disclosures.
Our management does not believe that any other recently issued, but not yet effective, accounting standards if currently adopted would have a material effect on our financial statements.
Item 7A. Quantitative and Qualitative Disclosures about Market Risk
Regulatory Risk
The Company’s operations are subject to extensive regulation by federal, state, and local authorities, including regulatory oversight by BOEM, BSEE, and PHMSA. Additionally, California maintains a complex regulatory framework governing offshore and onshore oil and gas operations, pipeline transportation, environmental compliance, and permitting. Regulatory approvals required to resume petroleum transportation through or modify infrastructure may be subject to additional conditions, delays, or legal challenge, which could increase costs or affect the timing of planned activities. Certain regulatory matters and related uncertainties are discussed in Note 8—Commitments and Contingencies to the consolidated financial statements. While the Company cannot reasonably quantify the financial impact of future regulatory actions, delays or changes in regulatory requirements could result in incremental capital expenditures, extended periods without revenue, or reduced cash flows once operations commence, which could adversely affect the Company’s liquidity as described in Item 7—Management’s Discussion and Analysis of Financial Condition and Results of Operations.
Debt Refinance and Liquidity Risk
The Company currently has no operating revenues, and its outstanding indebtedness consists of seller-financed debt incurred in connection with the acquisition of its assets. As a result, the Company does not currently generate cash flows to service or refinance its debt and is dependent on the successful restart of SYU operations, access to external capital, and prevailing market conditions. The Company’s ability to refinance or repay its debt will be influenced by factors including
61
the timing of regulatory approvals, the commencement of oil sales, commodity prices, and capital market conditions. In the absence of operating revenues, adverse developments could have a material effect on the Company’s liquidity and its ability to meet debt obligations as they become due.
Commodity Price Risk
Upon commencement of production and oil sales, the Company expects its financial performance to be sensitive to fluctuations in crude oil prices. Changes in oil prices could materially affect revenues, operating cash flows, capital investment decisions, and the Company’s ability to service debt. Crude oil prices are subject to significant volatility driven by global supply and demand, geopolitical events, regulatory actions, and regional market dynamics, including those specific to California. While the Company may consider risk management activities in the future, it does not currently have commodity price hedging arrangements in place. Accordingly, a sustained decline in oil prices following the commencement of sales could adversely affect the economics of production and the Company’s financial condition.
62
Item 8. Financial Statements and Supplementary Data
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Report of Independent Registered Public Accounting Firm (PCAOB ID Number 298) | |||||
| Consolidated Financial Statements: | |||||
63
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Stockholders and the Board of Directors of Sable Offshore Corp.
Opinion on the Financial Statements
We have audited the accompanying balance sheets of Sable Offshore Corp. (the “Company”) as of December 31, 2025 and 2024, the related statements of operations, changes in stockholders’ equity (deficit) / parent net investment and cash flows for the year ended December 31, 2025 (Successor), the period from February 14, 2024 to December 31, 2024 (Successor) the period from January 1, 2024 to February 13, 2024 (Predecessor) and the year ended December 31, 2023 (Predecessor), and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2025 and 2024, and the results of its operations and its cash flows for the year ended December 31, 2025 (Successor) and the period from February 14, 2024 to December 31, 2024 (Successor), the period from January 1, 2024 to February 13, 2024 (Predecessor) and the year ended December 31, 2023 (Predecessor), in conformity with accounting principles generally accepted in the United States of America.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the Company’s internal control over financial reporting as of December 31, 2025, based on criteria established in the 2013 Internal Control — Integrated framework issued by the Committee of Sponsoring Organization of the Treadway Commission (“COSO”) and our report dated February 27, 2026, expressed an unqualified opinion on the Company’s internal control over financial reporting.
Explanatory Paragraph – Going Concern
The accompanying financial statements have been prepared assuming that the Company will continue as a going concern. As described in Note 1, uncertainties related to obtaining the remaining regulatory approvals necessary to resume sales of production, along with the uncertainty of obtaining additional financing, or refinancing the Senior Secured Term Loan raise substantial doubt about the Company’s ability to continue as a going concern. The financial statements do not include any adjustments that may be necessary should the Company be unable to continue as a going concern.
Basis for Opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
64
Fair Value — Financial Instruments (Private Placement Warrants and Working Capital Warrants) – Refer to Note 1, Note 7 and Note 11 to the financial statements.
Critical Audit Matter Description
As described in Note 1, Note 7 and Note 11 to the financial statements, the Company has Private Placement Warrants and Working Capital Warrants outstanding. The Company utilized unobservable market data to determine the fair value of the Private Placement Warrants and Working Capital Warrants.
The principal consideration for our determination that the valuation of the Private Placement Warrants and Working Capital Warrants is a critical audit matter are the significant judgment necessary in the assumptions with significant unobservable market data to estimate the fair value. This required a high degree of auditor judgment and extensive audit effort, including the need to involve fair value specialists who possess significant quantitative expertise, to audit and evaluate the appropriateness of these inputs.
How We Addressed the Matter in Our Audit
Our audit procedures related to the valuation of the Private Placement Warrants and Working Capital Warrants included the following, among others:
•We obtained an understanding of the design of the Company’s controls over the valuation of the Private Placement Warrants and Working Capital Warrants, including controls over management’s review of the valuation model and the significant assumptions used in determining their fair values.
•With the assistance of a third-party valuation specialist, we audited the fair value of the equity volatility and key assumptions used in determining the fair value of the Private Placement Warrants and Working Capital Warrants by:
•Evaluating the appropriateness of the valuation model and techniques used in determining fair value;
•Assessing that the significant valuation assumption inputs of implied volatility and yield are consistent with those that would be used by market participants through the testing of source information, checking the mathematical accuracy of the calculation, and developing independent estimates and comparing to those selected by management, where applicable; and
•Recalculation of the fair value determined by management to verify its reasonableness.
•We audited the completeness and accuracy of the underlying data supporting the significant valuation assumption inputs.
/s/ Ham, Langston & Brezina, L.L.P.
We have served as the Company’s auditor since 2024.
Houston, Texas
February 27, 2026
65
SABLE OFFSHORE CORP.
CONSOLIDATED BALANCE SHEETS
(dollars in thousands, except par values)
| December 31, | |||||||||||
| 2025 | 2024 | ||||||||||
| Assets | |||||||||||
| Current assets: | |||||||||||
| Cash and cash equivalents | $ | 97,684 | $ | 300,384 | |||||||
| Restricted cash | — | 35,388 | |||||||||
| Inventory | 12,078 | — | |||||||||
| Materials and supplies | 14,658 | 15,337 | |||||||||
| Prepaid expenses and other current assets | 11,282 | 4,166 | |||||||||
| Total current assets | 135,702 | 355,275 | |||||||||
| Oil and gas properties (Successful efforts method) | |||||||||||
| Oil and gas properties | 1,567,029 | 1,194,447 | |||||||||
| Less: Accumulated depreciation, depletion and amortization | (5,977) | — | |||||||||
| Total oil and gas properties, net | 1,561,052 | 1,194,447 | |||||||||
| Other, net | 44,068 | 33,450 | |||||||||
| Total assets | $ | 1,740,822 | $ | 1,583,172 | |||||||
| Liabilities and Stockholders’ Equity | |||||||||||
| Accounts payable and accrued liabilities | $ | 99,353 | $ | 119,753 | |||||||
| Senior Secured Term Loan including paid-in-kind interest, net | 921,584 | — | |||||||||
| Other current liabilities | 2,488 | 918 | |||||||||
| Total current liabilities | 1,023,425 | 120,671 | |||||||||
| Warrant liabilities | 37,738 | 126,941 | |||||||||
| Asset retirement obligations | 113,181 | 99,683 | |||||||||
| Senior Secured Term Loan including paid-in-kind interest, net | — | 833,542 | |||||||||
| Deferred tax liability | 12,833 | 1,162 | |||||||||
| Other | 19,342 | 16,988 | |||||||||
| Total liabilities | 1,206,519 | 1,198,987 | |||||||||
| Stockholders’ Equity | |||||||||||
Preferred stock, $0.0001 par value; 1,000,000 shares authorized; none issued and outstanding at December 31, 2025 and 2024 | — | — | |||||||||
Common Stock, $0.0001 par value; 500,000,000 shares authorized; 144,961,796 and 89,310,996 issued and outstanding at December 31, 2025 and 2024, respectively | 15 | 8 | |||||||||
| Additional paid-in capital | 1,642,746 | 1,082,473 | |||||||||
| Accumulated deficit | (1,108,458) | (698,296) | |||||||||
| Total Stockholders’ Equity | 534,303 | 384,185 | |||||||||
| Total Liabilities and Stockholders’ Equity | $ | 1,740,822 | $ | 1,583,172 | |||||||
The accompanying notes are an integral part of these consolidated financial statements.
66
SABLE OFFSHORE CORP.
CONSOLIDATED STATEMENTS OF OPERATIONS
(dollars in thousands, except per share data)
| Successor | Predecessor | |||||||||||||||||||||||||
| Year Ended December 31, 2025 | February 14—December 31, 2024 | January 1—February 13, 2024 | Year Ended December 31, 2023 | |||||||||||||||||||||||
| Revenue | ||||||||||||||||||||||||||
| Oil and gas sales | $ | — | $ | — | $ | — | $ | — | ||||||||||||||||||
| Total revenue | — | — | — | — | ||||||||||||||||||||||
| Operating Expenses | ||||||||||||||||||||||||||
| Operations and maintenance expenses | 219,198 | 87,877 | 7,320 | 60,693 | ||||||||||||||||||||||
| Depletion, depreciation, amortization and accretion | 12,888 | 9,734 | 2,627 | 21,018 | ||||||||||||||||||||||
| General and administrative expenses | 176,197 | 229,140 | 1,714 | 12,763 | ||||||||||||||||||||||
| Total operating expenses | 408,283 | 326,751 | 11,661 | 94,474 | ||||||||||||||||||||||
| Loss from operations | (408,283) | (326,751) | (11,661) | (94,474) | ||||||||||||||||||||||
| Other (income) expenses: | ||||||||||||||||||||||||||
| Change in fair value of warrant liabilities | (89,203) | 227,454 | — | — | ||||||||||||||||||||||
| Other (income) expense, net | (8,834) | (4,193) | 128 | (801) | ||||||||||||||||||||||
| Interest expense | 88,245 | 67,314 | — | — | ||||||||||||||||||||||
| Total other (income) expense, net | (9,792) | 290,575 | 128 | (801) | ||||||||||||||||||||||
| Loss before income taxes | (398,491) | (617,326) | (11,789) | (93,673) | ||||||||||||||||||||||
| Income tax expense (benefit) | 11,671 | (48) | — | — | ||||||||||||||||||||||
| Net loss | $ | (410,162) | $ | (617,278) | $ | (11,789) | $ | (93,673) | ||||||||||||||||||
| Basic and diluted net loss per Common Stock | ||||||||||||||||||||||||||
| Weighted average Common Stock outstanding, basic and diluted | 98,179,703 | 67,015,860 | n/a | n/a | ||||||||||||||||||||||
| Basic and diluted net loss per Common Stock | $ | (4.18) | $ | (9.21) | n/a | n/a | ||||||||||||||||||||
The accompanying notes are an integral part of these consolidated financial statements.
67
SABLE OFFSHORE CORP.
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY (DEFICIT) / PARENT NET INVESTMENT
(dollars in thousands)
| Common Stock | Additional Paid-In Capital | Accumulated Deficit | Total Stockholders’ Equity (Deficit) | ||||||||||||||||||||||||||
| Shares | Amount | ||||||||||||||||||||||||||||
| Successor: | |||||||||||||||||||||||||||||
| BALANCE—February 14, 2024 (prior to Business Combination) | 7,187,500 | $ | 1 | $ | — | $ | (81,018) | $ | (81,017) | ||||||||||||||||||||
| Redeemable shares reclassified to Common Stock | 5,953,859 | 1 | 61,948 | — | 61,949 | ||||||||||||||||||||||||
| Net effect of Business Combination | 13,141,359 | 2 | 61,948 | (81,018) | (19,068) | ||||||||||||||||||||||||
| Issuance of Common Stock, net | 51,524,910 | 5 | 559,598 | — | 559,603 | ||||||||||||||||||||||||
| Issuance of Common Stock upon exercise of warrants | 16,170,457 | 1 | 354,084 | — | 354,085 | ||||||||||||||||||||||||
| Issuance of Common Stock for Transportation Assets | 600,000 | — | 15,234 | — | 15,234 | ||||||||||||||||||||||||
| Issuance of merger consideration shares | 3,000,000 | — | 36,300 | — | 36,300 | ||||||||||||||||||||||||
| Share based compensation | 4,874,270 | — | 55,309 | — | 55,309 | ||||||||||||||||||||||||
| Net loss | — | — | — | (617,278) | (617,278) | ||||||||||||||||||||||||
| BALANCE—December 31, 2024 | 89,310,996 | $ | 8 | $ | 1,082,473 | $ | (698,296) | $ | 384,185 | ||||||||||||||||||||
| Common Stock | Additional Paid-In Capital | Accumulated Deficit | Total Stockholders’ Equity (Deficit) | ||||||||||||||||||||||||||
| Shares | Amount | ||||||||||||||||||||||||||||
| Successor: | |||||||||||||||||||||||||||||
| BALANCE—December 31, 2024 | 89,310,996 | $ | 8 | $ | 1,082,473 | $ | (698,296) | $ | 384,185 | ||||||||||||||||||||
| Issuance of Common Stock, net | 55,454,546 | 6 | 518,314 | — | 518,320 | ||||||||||||||||||||||||
| Share based compensation | 196,254 | 1 | 41,959 | — | 41,960 | ||||||||||||||||||||||||
| Net loss | — | — | — | (410,162) | (410,162) | ||||||||||||||||||||||||
| BALANCE—December 31, 2025 | 144,961,796 | $ | 15 | $ | 1,642,746 | $ | (1,108,458) | $ | 534,303 | ||||||||||||||||||||
| Predecessor: | Parent Net Investment | |||||||
| BALANCE—January 1, 2023 | $ | 362,596 | ||||||
| Contributions from parent | 70,098 | |||||||
| Net loss | (93,673) | |||||||
| BALANCE—December 31, 2023 | $ | 339,021 | ||||||
| Contributions from parent | 22,474 | |||||||
| Net loss | (11,789) | |||||||
| BALANCE—February 13, 2024 | $ | 349,706 | ||||||
The accompanying notes are an integral part of these consolidated financial statements.
68
SABLE OFFSHORE CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
| Successor | Predecessor | |||||||||||||||||||||||||
(dollars in thousands) | Year Ended December 31, 2025 | February 14—December 31, 2024 | January 1—February 13, 2024 | Year Ended December 31, 2023 | ||||||||||||||||||||||
| Cash flows from operating activities: | ||||||||||||||||||||||||||
| Net loss | $ | (410,162) | $ | (617,278) | $ | (11,789) | $ | (93,673) | ||||||||||||||||||
| Adjustments to reconcile net loss to net cash used in operating activities: | ||||||||||||||||||||||||||
| Depreciation, depletion, amortization and accretion | 12,888 | 9,734 | 2,627 | 21,018 | ||||||||||||||||||||||
| Share based compensation expense | 42,679 | 91,609 | — | — | ||||||||||||||||||||||
| Amortization of operating lease right-of-use asset | 1,622 | 1,071 | — | — | ||||||||||||||||||||||
| Amortization of debt issuance costs | 542 | 1,012 | — | — | ||||||||||||||||||||||
| Paid-in-kind interest | 87,703 | 66,302 | — | — | ||||||||||||||||||||||
| Effect of amendment to the Senior Secured Term Loan | — | 4,957 | — | — | ||||||||||||||||||||||
| Deferred tax expense (benefit) | 11,671 | (48) | — | — | ||||||||||||||||||||||
| Change in fair value of warrant liabilities | (89,203) | 227,454 | — | — | ||||||||||||||||||||||
| Changes in current assets and current liabilities, net of effect of acquisition: | ||||||||||||||||||||||||||
| Inventory | (6,101) | — | — | — | ||||||||||||||||||||||
| Material and supplies | 428 | 1,275 | 5,980 | 2,198 | ||||||||||||||||||||||
| Prepaid expenses and other assets | (7,544) | (3,025) | — | — | ||||||||||||||||||||||
| Accounts payable and accrued liabilities | 3,775 | 53,969 | (7,922) | (4,430) | ||||||||||||||||||||||
| Due to related party | — | — | (11,370) | 4,789 | ||||||||||||||||||||||
| Net cash used in operating activities | (351,702) | (162,968) | (22,474) | (70,098) | ||||||||||||||||||||||
| Cash flows from investing activities: | ||||||||||||||||||||||||||
| Payments for capital expenditures | (417,624) | (72,302) | — | — | ||||||||||||||||||||||
| Cash paid for acquisition | — | (203,945) | — | — | ||||||||||||||||||||||
| Net cash used in investing activities | (417,624) | (276,247) | — | — | ||||||||||||||||||||||
| Cash flows from financing activities: | ||||||||||||||||||||||||||
| Capital contribution from parent | — | — | 22,474 | 70,098 | ||||||||||||||||||||||
| Offering proceeds | 545,000 | 590,249 | — | — | ||||||||||||||||||||||
| Payment of equity issuance costs | (13,762) | (30,596) | — | — | ||||||||||||||||||||||
| Cash received on warrant exercises, net | — | 183,514 | — | — | ||||||||||||||||||||||
| Payment on Senior Secured Term Loan | — | (18,750) | — | — | ||||||||||||||||||||||
| Payment of debt issuance costs | — | (1,635) | — | — | ||||||||||||||||||||||
| Payment of non-convertible promissory notes—related parties | — | (1,129) | — | — | ||||||||||||||||||||||
| Net cash provided by financing activities | 531,238 | 721,653 | 22,474 | 70,098 | ||||||||||||||||||||||
| Net change in cash | (238,088) | 282,438 | — | — | ||||||||||||||||||||||
| Cash, cash equivalents and restricted cash, beginning of the period | 335,772 | 53,334 | — | — | ||||||||||||||||||||||
| Cash, cash equivalents and restricted cash, end of the period | $ | 97,684 | $ | 335,772 | $ | — | $ | — | ||||||||||||||||||
| Reconciliation of cash, cash equivalents and restricted cash to the consolidated balance sheets | ||||||||||||||||||||||||||
| Cash and cash equivalents | $ | 97,684 | $ | 300,384 | $ | — | $ | — | ||||||||||||||||||
| Restricted cash | — | 35,388 | — | — | ||||||||||||||||||||||
| Total cash, cash equivalents and restricted cash | $ | 97,684 | $ | 335,772 | $ | — | $ | — | ||||||||||||||||||
The accompanying notes are an integral part of these consolidated financial statements.
69
SABLE OFFSHORE CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2025
Note 1 — Organization, Business Operations, and Going Concern
Organization and General
Sable Offshore Corp. (“Sable,” the “Company” or “we”) (formerly known as Flame Acquisition Corp. or “Flame”) is an independent oil and gas company headquartered in Houston, Texas. Flame was initially formed as a special purpose acquisition company for the purpose of entering into a merger, capital stock exchange, asset acquisition, stock purchase, reorganization or similar business combination with one or more businesses.
On November 2, 2022, the Company entered into an agreement and plan of merger, dated as of November 2, 2022 (as amended, supplemented, or otherwise modified from time to time, the “Merger Agreement”), with Sable Offshore Corp., a Texas corporation (“SOC”), and Sable Offshore Holdings, LLC, a Delaware limited liability company and the parent company of SOC (“Holdco” and, together with SOC, “Legacy Sable”). Pursuant to the Merger Agreement, on February 14, 2024, (i) Holdco merged with and into Flame, with Flame surviving such merger (the “Holdco Merger”) and (ii) Legacy Sable merged with and into Flame, with Flame surviving such merger (the “SOC Merger” and, together with the Holdco Merger, the “Mergers” and, along with the other transactions contemplated by the Merger Agreement, the “Merger”).
On November 1, 2022, SOC, entered into a purchase and sale agreement (as amended, the “Sable-EM Purchase Agreement”) with Exxon Mobil Corporation (“Exxon”) and Mobil Pacific Pipeline Company (“MPPC,” and together with Exxon, “EM”) pursuant to which SOC agreed to acquire from EM certain assets constituting the Santa Ynez field in Federal waters offshore California (“SYU”) and associated onshore processing and pipeline assets (such “Assets,” as defined in the Sable-EM Purchase Agreement, collectively the “SYU Assets”). The aggregate of the onshore processing and storage facilities and the offshore and onshore pipeline assets is considered the “Santa Ynez Pipeline System.”
On February 14, 2024 (the “Closing Date”), the Company consummated the Merger and related transactions (the “Business Combination”) contemplated by the Merger Agreement, 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 (“Sable-EM Closing Date”), immediately after the Business Combination, 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 (refer to Note 3—Acquisition for additional details).
On December 13, 2024, the Company entered into the Fourth Amendment to the Sable-EM Purchase Agreement, pursuant to which the following definitions were amended. “Restart Production” was redefined as 150 days after first production, extending the maturity date of the Senior Secured Term Loan by 60 days. “Restart Failure Date” was extended an additional 60 days to March 1, 2026.
On May 18, 2025, Sable completed anomaly repairs on Pipeline Segment 324 (formerly known as Line 901), which extends from the Las Flores Station 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 now completed its anomaly repair program on the Santa Ynez Pipeline System as specified by a Consent Decree that Plains entered into with various governmental agencies in 2020 (the “Consent Decree”), the governing document for resuming petroleum transportation through the Santa Ynez Pipeline System. On May 19, 2025, the Company announced that as of May 15, 2025, it had restarted production at SYU and begun flowing oil production from six wells at SYU’s Platform Harmony to the Company’s onshore processing facilities located at Las Flores Canyon (“LFC”).
On October 14, 2025, the Company entered into the Fifth Amendment to the Sable-EM Purchase Agreement, pursuant to which the Company agreed to purchase a performance bond in the amount of $350.0 million in favor of EM as the sole beneficiary as plug and abandonment financial security, which is due three days prior to the Senior Secured Term Loan maturity. In accordance with the Sable-EM Purchase Agreement, EM has the ability to request a performance bond increase to $500.0 million in favor of EM.
70
On October 14, 2025, the Company entered into a Letter Agreement Regarding Restart Production (the “Letter Agreement”) and the County of Santa Barbara’s Field Development Plan, with an effective date of June 1, 2025, whereby the Company agreed to provide EM additional consideration for lack of operatorship transfer. The Company will reimburse EM for costs associated with the Sable Offshore et al. v. County of Santa Barbara et al. litigation regarding operator permit transfer, and will compensate EM $4.0 million per month during the term of the agreement for operator related services. The term concludes at the earlier of (i) the completion of the transfer of operator or (ii) termination of the agreement by EM. Refer to Note 8—Commitments and Contingencies for details regarding this County Permit Transfer Matter.
On December 17, 2025, the U.S. Department of Transportation’s Pipeline and Hazardous Materials Safety Administration (“PHMSA”) notified the Company that it concurred with the Company’s November 26, 2025 determination that Santa Ynez Pipeline System, constitutes an interstate pipeline facility under the Pipeline Safety Act, pursuant to which PHMSA is vested with exclusive regulatory authority over interstate pipelines. In its notification, PHMSA additionally states that it considers the Santa Ynez Pipeline System to be an “active” pipeline according to PHMSA regulations.
On December 22, 2025, PHMSA notified the Company that it approved the Company’s Restart Plan for the Santa Ynez Pipeline System.
On December 23, 2025, PHMSA issued an emergency special permit for segments of the interstate Santa Ynez Pipeline System (specifically Pipeline Segments 324 and 325), related to cathodic protection and seam weld corrosion along Pipeline Segments 324 and 325.
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.
For the purposes of the consolidated financial statements, periods on or before February 13, 2024 reflect the financial position, results of operations and cash flows of the SYU Assets (excluding Pipeline Segments 324 and 325) prior to the Business Combination, referred to herein as the “Predecessor,” and periods beginning on or after February 14, 2024 reflect the financial position, results of operations and cash flows of the Company as a result of the Business Combination, referred to herein as the “Successor”.
Going Concern
The accompanying consolidated financial statements have been prepared on a basis that assumes the Company will continue as a going concern. Since the Business Combination the Company has been strictly focused on recommencing oil sales from the SYU Assets, including capital expenditures to repair and maintain the SYU Assets. Much like other pre-revenue companies, the Company has experienced losses from operations and has negative cash flows from operations since inception. The Company expects to continue to incur losses until it can recognize revenue in connection with the sale of production from the SYU Assets. As of December 31, 2025, the Company reported unrestricted cash of $97.7 million, total debt of $921.6 million, and an accumulated deficit of $1.1 billion.
Following the Closing Date and through December 31, 2025, management has addressed capital funding needs with the consummation of the Business Combination, proceeds from the issuance of the Company’s Common Stock, and proceeds from the exercise of warrants (refer to Note 7—Warrants for additional details regarding the warrant exercises).
Additionally, the maturity date of the Company’s Senior Secured Term Loan is the earlier of (i) March 31, 2027 or (ii) the date falling 90 days after first sales of Hydrocarbons (as defined in the Senior Secured Term Loan, refer to Note 6—Debt for additional details regarding the Second Debt Amendment). Notwithstanding the maturity extension, the Senior Secured Term Loan is classified as a current liability on the Company’s consolidated balance sheet as of December 31, 2025 due to management’s expected maturity date based on anticipated first sales from SYU.
On September 29, 2025, the Company 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”). Sable continues to work diligently with
71
PHMSA and the State of California to safely and responsibly resume petroleum transportation through the Santa Ynez Pipeline System in accordance with its federal Consent Decree, which was entered into by several state and federal agencies (the “Santa Ynez Pipeline Strategy”). However, continued regulatory delays related to the Santa Ynez Pipeline System have prompted the Company to evaluate and pursue the OS&T Strategy. Implementation of the OS&T Strategy will require regulatory authorizations along with additional debt financing.
If our estimates of the costs to reach first sales via the Santa Ynez Pipeline System or the OS&T are less than the actual amounts necessary to do so, we may have insufficient funds available to operate our business prior to first sales of production and will need to raise additional capital. If we are unable to raise additional capital, we may be required to take additional measures to conserve liquidity, which could include, among other things, reducing overhead expenses.
Due to the uncertainty regarding our resumption of sales of production volumes, and lack of assurance that new financing, or refinancing of the Senior Secured Term Loan, will be available to us on commercially acceptable terms, if at all, substantial doubt exists about the Company’s ability to continue as a going concern. The financial statements included in this annual report do not include any adjustments relating to the recovery of the recorded assets or the classification of the liabilities that could be necessary if the Company is unable to continue as a going concern.
Note 2 — Significant Accounting Policies
Basis of Presentation
Flame was initially formed as a special purpose acquisition company for the purpose of entering into a merger, capital stock exchange, asset acquisition, stock purchase, reorganization or similar business combination with one or more businesses. On February 14, 2024, Flame completed the transactions contemplated by the Merger Agreement and the Sable-EM Purchase Agreement, with Flame surviving the transactions and changing its name to Sable Offshore Corp. thereafter. The Company was deemed the accounting acquirer in the Business Combination based on an analysis of the criteria outlined in Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 805, Business Combinations, (“ASC 805”) with such transactions being accounted for as a forward merger, and SYU was deemed the Predecessor entity for accounting purposes. Refer to Note 3—Acquisition for disclosures related to the Business Combination.
As a result of the Business Combination, the results of operations, financial position and cash flows of the Predecessor and Successor are not directly comparable. Since SYU was deemed to be the Predecessor entity, the historical financial statements of SYU became the historical financial statements of the combined Company, upon the consummation of the Business Combination. As a result, the financial statements included in this report reflect (i) the historical operating results of SYU prior to the Business Combination and (ii) the consolidated results of the Company, including SYU, following the Closing Date. The accompanying financial statements include a Predecessor period, which includes the period January 1, 2023 through February 13, 2024 concurrent with the Business Combination, and a Successor period from February 14, 2024 through December 31, 2024, and thereafter. A black line between the Successor and Predecessor periods has been placed in the consolidated financial statements and in the tables to the notes to the consolidated financial statements to highlight the lack of comparability between these two periods.
The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) for annual financial information and in accordance with the instructions to Form 10-K and Regulation S-X of the U.S. Securities and Exchange Commission (“SEC”). Financial presentation in prior periods has been adjusted to conform with current period presentation.
The Predecessor financial statements reflect the carve-out assets, liabilities, parent net investment, revenues, expenses, and cash flows of SYU. SYU had not previously been separately accounted for as a stand-alone legal entity. The accounts are presented on a combined basis because SYU was under common control of EM.
The accompanying Predecessor financial statements also include a portion of indirect costs for general and administrative expenses. In addition to the allocation of indirect costs, the Predecessor financial statements reflect certain agreements executed by EM for the benefit of SYU. The allocations methodologies for significant allocated items include:
•General and administrative expenses that were not specifically identifiable to SYU were allocated to SYU as a portion of certain other operating costs based on aggregated historical benchmarking data for the period from January 1, 2022 to February 13, 2024. The total amounts allocated to SYU for the period from January 1, 2024 to February 13, 2024 and the year ended December 31, 2023, which are recorded in general and administrative expenses, are $1.7 million and $12.8 million, respectively.
72
•Long-term debt was not allocated to SYU as it was a legal obligation of EM, which was not directly impacted by the sale of SYU to Sable.
Management believes the allocation methodologies used in the Predecessor financial statements are reasonable and result in an allocation of EM’s indirect costs of operating SYU as a stand-alone entity. These Predecessor financial statements may not be indicative of the future performance of SYU and do not necessarily reflect what the results of operations, financial position and cash flows would have been had SYU been operated as an independent company during the periods presented.
Use of Estimates
The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of expenses during the reporting period. Significant estimates made by management include, among others, allocation assumptions and the carrying amount of asset retirement obligations, which are based on the timing and cost of future abandonments, inputs utilized to fair value warrant liabilities, and assumptions used to estimate deferred taxes.
While management believes these estimates are reasonable, changes in facts and assumptions or the discovery of new information may result in revised estimates. Actual results could differ from these estimates, and it is at least reasonably possible these estimates could be revised in the near term, and these revisions could be material.
Segment Reporting
As of December 31, 2025, the Company is managed as a single operating segment and a single reportable segment: oil and gas. The Company’s sole segment is engaged in the acquisition, development, exploration, and exploitation of oil and natural gas reserves in the Santa Ynez Unit in federal waters offshore California and consists of (i) the Company and its wholly owned subsidiaries, (ii) three offshore production platforms—Hondo, Harmony, and Heritage—and (iii) the Santa Ynez Pipeline System, which includes offshore and onshore infrastructure assets that transport production from the outer continental shelf to onshore customer delivery points. Revenue is anticipated to be generated through the sale of oil and natural gas to customers, which is dependent on the coordinated operation of the Company’s offshore and onshore infrastructure assets.
The Company’s Chief Operating Decision Maker (“CODM”) is its Chairman and Chief Executive Officer. The CODM uses the Company’s consolidated financial results to make key operating decisions, assess performance and to allocate resources. The measures of segment profit or loss and total assets utilized by the CODM are net income and total assets as reported on the consolidated statements of operations and the consolidated balance sheets, respectively. The significant expense categories, their amounts and other segment items that are regularly provided to the CODM are those that are reported in the Company’s consolidated statements of operations.
The CODM uses consolidated net income (loss) as a measure of profitability to evaluate segment performance and to make capital allocation decisions such as reinvestment in the business or reduction of capital expenditures.
Fair Value Measurements
Fair value is defined as the price that would be received for sale of an asset or paid for transfer of a liability, in an orderly transaction between market participants at the measurement date. GAAP establishes a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). These tiers include:
•Level 1, defined as observable inputs such as quoted prices (unadjusted) for identical instruments in active markets;
•Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable such as quoted prices for similar instruments in active markets or quoted prices for identical or similar instruments in markets that are not active; and
•Level 3, defined as unobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions, such as valuations derived from valuation techniques in which one or more significant inputs or significant value drivers are unobservable.
73
Cash and Cash Equivalents
The Company considers all short-term investments with an original maturity of three months or less when purchased to be cash equivalents.
Restricted Cash
The Company considers cash or cash equivalents that are legally restricted from use or withdrawal as restricted cash. In March of 2024, the Company entered into the Settlement Agreement (as defined below) in regards to the Grey Fox Matter (as defined below), refer to Note 8—Commitments and Contingencies for additional details regarding the Grey Fox Matter. Pursuant to the Settlement Agreement, the Company was required to deliver an irrevocable direct pay letter of credit (the “Letter of Credit”) in the amount of $35.0 million to the plaintiffs’ counsel (the “Plaintiffs”) in the Grey Fox Matter. The Letter of Credit was issued by JPMorgan Chase Bank, N.A. (“JPMorgan”) and required the Company to enter into a cash collateral agreement (the “Collateral Agreement”) with JPMorgan on May 7, 2024. Pursuant to the Collateral Agreement, the Company deposited $35.0 million into a collateral account (the “Collateral Account”), which was pledged as collateral to JPMorgan as the issuer of the Letter of Credit. Pursuant to the terms of the Settlement Agreement, the Plaintiffs in the Grey Fox Matter were able to draw upon the Letter of Credit upon satisfaction of certain conditions, and the funds held in the Collateral Account were legally restricted to reimburse JPMorgan for such draws, in addition to any related fees and expenses.
On July 7, 2025, in accordance with the Settlement Agreement, JPMorgan processed the $35.0 million draw statement and wired the funds to Plaintiffs pursuant to the Letter of Credit. JPMorgan subsequently accepted the $35.0 million restricted cash as settlement in full of the obligations created by the draw of the Letter of Credit, all as contemplated by the Settlement Agreement.
Concentration of Credit Risk
Financial instruments that potentially subject the Company to concentrations of credit risk consist of cash and restricted cash deposits with a financial institution, which, at times, may exceed the Federal Depository Insurance Coverage of $0.3 million. As of December 31, 2025 and 2024, the Company did not experience losses on these accounts.
Related Parties
Transactions between related parties are considered to be related party transactions even though they may not be given accounting recognition. FASB ASC Topic 850, Related Party Disclosures, requires transactions with related parties that would make a difference in decision making to be disclosed so that users of the consolidated financial statements can evaluate their significance.
During the period from January 1, 2024 through February 13, 2024 (Predecessor) and the year ended December 31, 2023 (Predecessor), there were no related party transactions, except for the management and administrative services. SYU previously received management and administrative services from EM, a portion of which was attributable to SYU. Additionally, cash that was received on behalf of SYU by EM created a receivable for SYU, while expenditures made by EM on behalf of SYU created a payable for SYU. The net receivable or payable from all cash activity attributable to SYU is reflected as Due to related party. Refer to Note 5—Related Party Transactions for related party disclosures.
Property, Plant and Equipment
Cost Basis. The Company’s oil, natural gas and NGL producing activities are accounted for under the successful efforts method of accounting. Under this method, costs are accumulated on a field-by-field basis. Costs incurred to purchase, lease, or otherwise acquire a property (whether unproved or proved) are capitalized when incurred. Exploratory well costs are carried as an asset when the well has found a sufficient quantity of reserves to justify its completion as a producing well and where sufficient progress assessing the reserves and the economic and operating viability of the project is being made. Exploratory well costs not meeting these criteria are charged to expense. Other exploratory expenditures, including geophysical costs and annual lease rentals, are expensed as incurred. Development costs, including costs of productive wells and development dry holes, are capitalized.
Other Property and Equipment. Other property and equipment primarily consist of onshore midstream facilities, transportation assets and assets related to the Company’s corporate office (the “Office Assets”). Due to the nature of such assets, the onshore midstream facilities are presented within oil and gas properties, while the transportation assets and the Office Assets are presented within other assets on the consolidated balance sheets.
74
Depreciation, Depletion and Amortization. Depreciation, depletion and amortization are primarily determined under the unit-of-production method, which is based on estimated asset service life taking obsolescence into consideration.
Acquisition costs of proved properties are to be amortized using a unit-of-production method, computed on the basis of total proved oil and natural gas reserve volumes. Capitalized exploratory drilling and development costs associated with productive depletable extractive properties are amortized using the unit-of-production rates based on the amount of proved developed reserves of oil and gas that are estimated to be recoverable from existing facilities using current operating methods. Under the unit-of-production method, oil and natural gas volumes are considered produced once they have been measured through meters at custody transfer or sales transaction points at the outlet valve on the lease or field storage tank.
Due to the nature of our investments in midstream equipment, the cost of such assets are also amortized using the unit-of-production rates based on the amount of proved developed reserves of oil and gas that are estimated to be recoverable from existing facilities using current operating methods. Maintenance and repairs, including planned major maintenance, are expensed as incurred. Major renewals and improvements are capitalized and the assets replaced are retired.
Production from the SYU temporarily was ceased beginning in 2015 due to a pipeline incident but was maintained in an operation-ready state. Thus, no depreciation, depletion, and amortization was recognized prior to achieving first production on May 15, 2025. The Company produced oil volumes during the year ended December 31, 2025 and accordingly recognized $6.0 million of depreciation, depletion, and amortization, which has been capitalized as Inventory on the consolidated balance sheet (see further discussion below of Inventory) as the produced oil volumes have been retained within the Company’s storage tanks as of December 31, 2025.
Depreciation, depletion, amortization, and accretion expense for oil and gas properties recognized on the consolidated statement of operations for the year ended December 31, 2025 and the period February 14, 2024 through December 31, 2024 (Successor) consisted of asset retirement obligation related accretion expense in the amount of $12.1 million and $9.6 million, respectively, and depreciation on other property and equipment of $0.8 million and $0.1 million, respectively.
Depreciation, depletion, amortization, and accretion expense for oil and gas properties and related equipment was $2.6 million and $21.0 million for the period from January 1, 2024 through February 13, 2024 (Predecessor) and the year ended December 31, 2023 (Predecessor), respectively.
The Company had net capitalized costs related to oil and gas properties and related equipment of $1.6 billion and $1.2 billion as of December 31, 2025 and 2024, respectively.
Impairment Assessment. Oil and gas properties are tested for recoverability on an ongoing basis whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable. Among the events or changes in circumstances which could indicate that the carrying value of an asset or asset group may not be recoverable are the following:
•a significant decrease in the market price of a long-lived asset;
•a significant adverse change in the extent or manner in which an asset is being used or in its physical condition including a significant decrease in current and projected reserve volumes;
•a significant adverse change in legal factors or in the business climate that could affect the value, including an adverse action or assessment by a regulator;
•an accumulation of project costs significantly in excess of the amount originally expected; and
•a current-period operating loss combined with a history and forecast of operating or cash flow losses.
Oil and gas properties undergo a process to monitor for indicators of potential impairment throughout the year. This process is aligned with the requirements of FASB ASC Topic 360, Property, Plant, and Equipment (“ASC 360”) and FASB ASC Topic 932, Extractive Industries—Oil and Gas (“ASC 932”). Asset valuation analysis, profitability reviews and other periodic control processes assist in assessing whether events or changes in circumstances indicate the carrying amounts of any of the assets may not be recoverable.
75
Because the lifespans of the oil and gas properties are measured in decades, the future cash flows of these assets are predominantly based on long-term oil and natural gas commodity prices, industry margins, and development and production costs. Significant reductions in management’s view of oil or natural gas commodity prices or margin ranges, especially the longer-term prices and margins, and changes in the development plans, including decisions to defer, reduce, or eliminate planned capital spending, can be an indicator of potential impairment. Other events or changes in circumstances, can be indicators of potential impairment as well.
In general, temporarily low prices or margins are not viewed as an indication of impairment. Management believes that prices over the long term must be sufficient to generate investments in energy supply to meet global demand. Although prices will occasionally drop significantly, industry prices over the long term will continue to be driven by market supply and demand fundamentals. On the supply side, industry production from mature fields is declining. This is being offset by investments to generate production from new discoveries, field developments and technology, and efficiency advancements. The Organization of the Petroleum Exporting Countries investment activities and production policies also have an impact on world oil supplies. The demand side is largely a function of general economic activities, alternative energy sources and levels of prosperity. During the lifespan of its major assets, management expects that oil and gas prices and industry margins will experience significant volatility, and consequently these assets will experience periods of higher earnings and periods of lower earnings. In assessing whether events or changes in circumstances indicate the carrying value of an asset may not be recoverable, management considers recent periods of operating losses in the context of its longer-term view of prices and margins.
Cash Flow Assessment. If events or changes in circumstances indicate that the carrying value of an asset may not be recoverable, management estimates the future undiscounted cash flows of the affected properties to judge the recoverability of carrying amounts. In performing this assessment, assets are grouped at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets. Cash flows used in recoverability assessments are based on assumptions which are developed by management and are consistent with the criteria management uses to evaluate investment opportunities. These evaluations make use of assumptions of future capital allocations, crude oil and natural gas commodity prices including price differentials, refining and chemical margins, volumes, and development and operating costs. Volumes are based on projected field and facility production profiles, throughput, or sales. Management’s estimate of upstream production volumes used for projected cash flows makes use of contingent resource quantities and may include risk-adjusted unproved reserve quantities.
Fair value of Impaired Assets. An asset group is impaired if its estimated undiscounted cash flows are less than the asset group’s carrying value. Impairments are measured by the amount by which the carrying value exceeds fair value. The assessment of fair value is based upon the views of a likely market participant. The principal parameters used to establish fair value include estimates of acreage values and flowing production metrics from comparable market transactions, market-based estimates of historical cash flow multiples, and discounted cash flows. Inputs and assumptions used in discounted cash flow models include estimates of future production volumes, throughput and product sales volumes, commodity prices which are consistent with the average of third-party industry experts and government agencies, refining and chemical margins, drilling and development costs, operating costs and discount rates which are reflective of the characteristics of the asset group. Impairments incurred are Level 3 fair value measurements.
There were no impairments recognized during the year ended December 31, 2025 (Successor), the periods February 14, 2024 through December 31, 2024 (Successor) and January 1, 2024 through February 13, 2024 (Predecessor), or the year ended December 31, 2023 (Predecessor).
Inventory
As referenced above, the Company restarted production in May 2025, and began flowing oil production to the Santa Ynez Pipeline System’s onshore processing and storage facilities at LFC. As a result, the Company recognized short term oil inventory as of December 31, 2025. FASB ASC Topic 330, Inventory (“ASC 330”) dictates that inventory shall initially be valued at the price paid or consideration given to acquire an asset. By analogy, the Company capitalized the costs incurred that were directly attributable to producing and transporting the production to the onshore storage tanks, including associated depreciation, depletion, and amortization. Oil inventory is presented as Inventory on the consolidated balance sheets.
The Company has oil inventory storage capacity of 540 MBbls onshore at LFC. The Company generally expects the inventory volumes to fluctuate over time to maintain optimal operational efficiencies. The ending volume of inventory that remains in the onshore storage tanks is measured at the current period’s cost, and a lower of cost or net realizable value assessment is performed for each reporting period.
76
Materials and Supplies
Materials and supplies are valued at the lower of cost or net realizable value on the consolidated balance sheets.
Accounts Payable and Accrued Liabilities
Accounts payable and accrued liabilities include obligations incurred in the ordinary operation of the business for services performed and products received, including capital expenditures that are capitalized as oil and gas properties. Accounts payable and accrued liabilities consisted of the following as of:
| December 31, | |||||||||||
| (in thousands) | 2025 | 2024 | |||||||||
| Accounts payable | $ | 25,239 | $ | 16,806 | |||||||
| Accrued operations expenditures | 23,929 | 62,002 | |||||||||
| Accrued general and administrative, and other | 50,185 | 5,907 | |||||||||
| Legal settlement payable | — | 35,038 | |||||||||
| Total accounts payable and accrued liabilities | $ | 99,353 | $ | 119,753 | |||||||
Accounting for Equity-Based Compensation
The Company has granted various types of stock-based awards to employees, officers and directors who perform services for the Company. These plans and related accounting policies for material awards are defined and described more fully in Note 10—Share Based Compensation. Equity compensation awards are measured at fair value on the date of grant and are expensed over the required service period. Forfeitures for these awards are recognized as they occur.
Asset Retirement Obligations
The Company’s asset retirement obligations (“ARO”) primarily relate to the future plugging and abandonment of oil and gas properties and related facilities. The Company uses assumptions and judgments to estimate the respective future plugging and abandonment costs, technical assessments of the assets and their ultimate productive life (timing of settlements), a risk-adjusted discount rate and an inflation factor in order to determine the current present value of this obligation. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligation liability, a corresponding adjustment is made to the oil and gas property balance.
The fair values of these obligations are recorded as liabilities on a discounted basis, which is typically at the time the assets are installed. Asset retirement obligations incurred in the current period are Level 3 fair value measurements. The costs associated with these liabilities are capitalized as part of the related assets and depreciated as the reserves are produced. Over time, the liabilities are accreted for the change in their present value. Refer to Note 4—Asset Retirement Obligations for additional disclosures.
Derivative Warrant Liabilities
The Company does not currently use derivative instruments to hedge exposures to cash flow, market, or foreign currency risks. The Company evaluates all of its financial instruments, including issued stock purchase warrants, to determine if such instruments are derivatives or contain features that qualify as embedded derivatives, pursuant to FASB ASC Topic 480, “Distinguishing Liabilities from Equity” and FASB ASC Topic 815, “Derivatives and Hedging” (“ASC 815”). The classification of derivative instruments, including whether such instruments should be recorded as liabilities or as equity, is re-assessed at the end of each reporting period.
The Company accounts for its warrants as derivative warrant liabilities in accordance with ASC 815-40. Accordingly, the Company recognizes the warrant instruments as liabilities at fair value and adjusts the instruments to fair value at each reporting period. The liabilities are subject to re-measurement at each balance sheet date until exercised, and any change in fair value is recognized in the Company’s consolidated statements of operations (Refer to Note 11—Fair Value Measurements for additional details).
77
Employee Benefit Plan
The Company provides retirement benefits to its employees through the use of a 401(k) savings plan. Participants may contribute up to 100% of their total eligible compensation, and the Company matches participant’s elective contribution up to 7%, consisting of a 6% safe harbor match and an additional 1% matching contribution. Additional matches could be made at the discretion of the Company. The amount of participant and Company matching contributions are limited by government-mandated restrictions.
Vesting in the Company’s contributions in the 401(k) savings plan occurs at a rate of 33.3% per year, and are fully vested upon completion of three years of active service. The Company contributed $3.4 million and $1.4 million matching contributions for the year ended December 31, 2025 (Successor) and for the period from February 14, 2024 through December 31, 2024 (Successor), respectively.
Income Taxes
The Company accounts for income taxes under FASB ASC Topic 740, “Income Taxes” (“ASC 740”). ASC 740 requires the recognition of deferred tax assets and liabilities for both the expected impact of differences between the financial statements and tax basis of assets and liabilities and for the expected future tax benefit to be derived from tax loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that included the enactment date. ASC 740 additionally requires a valuation allowance to be established when it is more likely than not that all or a portion of deferred tax assets will not be realized.
Deferred income taxes arise from temporary differences between the tax basis of assets and liabilities and their reported amounts in the financial statements, which will result in taxable or deductible amounts in the future. In evaluating our ability to recover our deferred tax assets, we consider all available positive and negative evidence, including scheduled reversals of deferred tax liabilities, projected future taxable income, tax-planning strategies, and results of recent operations. In projecting future taxable income, we begin with historical results and incorporate assumptions about the amount of future federal and state pretax operating income adjusted for items that do not have tax consequences. Based on our ongoing assessment of all available evidence, both positive and negative, we concluded that it was more likely than not that our U.S. deferred tax assets in excess of deferred tax liabilities would not be realized. Also, in scheduling the reversals of our existing timing differences for the Successor period, we concluded that certain deferred tax liabilities in future periods do not have deferred tax assets available to offset, which is primarily due to our net operating losses being limited to 80% of taxable income on an annual basis. Therefore, a further valuation allowance of our deferred tax assets in excess of our liabilities is necessary and results in deferred tax expenses for the Successor period. Our judgment regarding the likelihood of realization of these deferred tax assets could change in future periods, which could result in a material impact to our income tax provision in the period of change.
On July 4, 2025, the One Big Beautiful Bill Act (“OBBBA”) was enacted in the United States. The OBBBA makes permanent key elements of the Tax Cuts and Jobs Act of 2017, including 100% bonus depreciation on qualified property acquired and placed in service after January 19, 2025. Per ASC 740, the effects of changes in tax rates and laws on deferred tax balances to be recognized in the period in which the legislation is enacted is required. The financial reporting implications of the OBBBA were recorded in the income tax provision for the year ended December 31, 2025, in accordance with ASC 740.
Parent Net Investment (Predecessor)
Parent net investment reflects the financial reporting basis of SYU’s assets and liabilities and changes due to capital contributions and losses. All cash activity of SYU for the periods presented were concentrated in accounts retained by EM. Accordingly, net cash activity attributable to SYU is reflected in contributions from parent in the accompanying consolidated financial statements in the Predecessor periods.
78
Net Loss Per Share of Common Stock
The Company complies with accounting and disclosure requirements of FASB ASC Topic 260, “Earnings Per Share.” Net loss per share of Common Stock is computed by dividing net loss by the weighted average number of shares of Common Stock outstanding for the period.
The following table reflects the calculation of basic and diluted net loss per share of Common Stock.
| Predecessor | ||||||||||||||||||||||||||
(dollars in thousands, except per share amounts) | Year Ended December 31, 2025 | February 14—December 31, 2024 | January 1—February 13, 2024 | Year Ended December 31, 2023 | ||||||||||||||||||||||
| Net loss | $ | (410,162) | $ | (617,278) | $ | (11,789) | $ | (93,673) | ||||||||||||||||||
Weighted average shares outstanding—Basic and diluted | 98,179,703 | 67,015,860 | n/a | n/a | ||||||||||||||||||||||
Net loss per share—Basic and diluted | $ | (4.18) | $ | (9.21) | n/a | n/a | ||||||||||||||||||||
The diluted net loss per share calculation excludes the anti-dilutive effect of 8,987,062 warrants, 10,084,265 restricted share units and 2,619,000 restricted share awards for the year ended December 31, 2025 (Successor), and 8,987,062 warrants and 4,874,270 restricted share awards for the period from February 14, 2024 through December 31, 2024 (Successor).
Recent Accounting Pronouncements
In November 2024, the FASB issued ASU 2024-03, Income Statement — Reporting Comprehensive Income — Expense Disaggregation Disclosures (Subtopic 220-40) — “Disaggregation of Income Statement Expenses.” The FASB issued this ASU to improve the disclosures about a public business entity’s expenses and address requests from investors for more detailed information about the types of expenses (including purchases of inventory, employee compensation, depreciation, amortization, and depletion) in commonly presented expenses captions (such as cost of sales, SG&A, and research and development). The amendments in this ASU are effective for annual periods beginning after December 15, 2026, and interim reporting periods beginning after December 15, 2027. Early adoption is permitted. The Company is currently reviewing what impact, if any, adoption will have on its disclosures.
The Company’s management does not believe that any other recently issued, but not yet effective, accounting standards if currently adopted would have a material effect on the accompanying financial statements.
Note 3 — Acquisition
On the Sable-EM Closing Date, in connection with the consummation of the transactions contemplated by the Sable-EM Purchase Agreement, the Company entered into a $625.0 million five year Senior Secured Term Loan with Exxon (the “Senior Secured Term Loan”) and paid additional consideration of $203.9 million in cash to Exxon (which excludes an $18.8 million cash deposit on the Senior Secured Term Loan paid to Exxon on the Closing Date). Refer to Note 6—Debt for additional details regarding the Senior Secured Term Loan.
The following table presents the adjusted purchase consideration (in thousands):
The acquisition of the SYU Assets’ is accounted for in accordance with ASC 805, and pursuant to which Sable was determined to be the accounting acquirer. The allocation of the purchase price included in the consolidated balance sheets is based on the best estimate of management. To assist management in the allocation, the Company engaged valuation specialists.
79
The following table represents the allocation of the total purchase price for the acquisition of the identifiable assets acquired and the liabilities assumed at the acquisition date (in thousands):
| Total consideration | $ | 985,600 | |||
| Fair value of assets acquired: | |||||
| Oil and gas properties | $ | 1,060,374 | |||
| Materials and supplies | 16,637 | ||||
| Other assets | 4,621 | ||||
| Amount attributable to assets acquired | $ | 1,081,632 | |||
| Fair value of liabilities assumed: | |||||
| Asset retirement obligations | $ | 90,073 | |||
| Other current liabilities | 827 | ||||
| Deferred tax liability | 1,209 | ||||
| Other long term liabilities | 3,923 | ||||
| Amounts attributable to liabilities assumed | 96,032 | ||||
| Net assets acquired and liabilities assumed | $ | 985,600 | |||
The Company assumed contractual agreements for warehousing space and for surface use rights. For leases with a primary term of more than 12 months, a right-of-use (“ROU”) asset and the corresponding ROU lease liability was recorded. The Company recorded an initial asset and liability of $4.6 million associated with the assumed leases. The Company determines at inception if an arrangement is an operating or financing lease.
The Company also paid transaction costs in the Successor period in connection with the acquisition and the related Business Combination totaling $49.1 million, of which $24.7 million was recognized in Selling, general, and administrative expenses in the consolidated statement of operations as of the Closing Date, $22.9 million was recognized as a charge to Additional paid-in-capital, and $1.5 million was capitalized as debt issuance costs on the consolidated balance sheet as of the Closing Date.
Note 4 — Asset Retirement Obligations
The Company’s asset retirement obligations relate to the future plugging and abandonment of oil and gas properties and related facilities. The following table describes the changes to the Company’s asset retirement obligations liability as of:
| December 31, | |||||||||||
| (in thousands) | 2025 | 2024 | |||||||||
| Beginning balance | $ | 99,683 | $ | — | |||||||
| Acquisition of SYU | — | 90,073 | |||||||||
| Accretion | 12,062 | 9,610 | |||||||||
| Revision of previous estimate | 1,436 | — | |||||||||
| Ending balance | $ | 113,181 | $ | 99,683 | |||||||
80
Note 5 — Related Party Transactions
Convertible Promissory Notes
Flame entered into nine convertible promissory notes with Flame Acquisition Sponsor LLC (“Sponsor”) to provide working capital loans (the “Working Capital Loans”) totaling $3.3 million as of February 14, 2024. The Working Capital Loans were to be either repaid upon consummation of a Business Combination, without interest, or, at the lender’s discretion, such Working Capital Loans were convertible into warrants of the post-Business Combination entity at a price of $1.00 per warrant. At the Closing Date, all of the Working Capital Loans were converted into an aggregate of 3,306,370 Private Warrants at a price of $1.00 per Warrant. The warrants are identical to the Private Placement Warrants. See warrant discussion at Note 7—Warrants.
Promissory Note Loans
Flame entered into four non-convertible promissory notes (the “Promissory Note Loans”) with the Sponsor to provide Promissory Note Loans that were used to pay for expenditures of the acquisition target totaling $1.1 million as of February 14, 2024. At the Closing Date, each of the Promissory Note Loans were fully repaid in cash.
Founder Reimbursement
Under the terms of the Merger Agreement, James C. Flores, the Company’s Chairman and Chief Executive Officer, was entitled to reimbursement by Flame, on the Closing Date, of all of his reasonable, documented out-of-pocket fees and expenses for any agents, advisors, consultants, experts, independent contractors and financial advisors engaged on behalf of Holdco or Sable and incurred in connection with the transactions contemplated by the Merger Agreement and the Sable-EM Purchase Agreement, in each case, that were paid as of the Closing, subject to a cap equal to $3.0 million. On the Closing Date, Mr. Flores was reimbursed $2.9 million and the associated expense is included in general and administrative expenses on the consolidated statement of operations for the period from February 14, 2024 through December 31, 2024 (Successor).
Agreement of Purchase and Sale
On October 3, 2024, the Company entered into an Agreement of Purchase and Sale (“PSA”) with Sable Aviation, LLC (“Sable Aviation”), an entity controlled by the Company’s Chairman and Chief Executive Officer. Pursuant to the terms of the PSA, the Company purchased transportation assets and related equipment from Sable Aviation in exchange for 600,000 shares of the Company’s Common Stock, valued at $15.2 million.
Note 6 — Debt
Senior Secured Term Loan
Sable entered into the Senior Secured Term Loan with an initial principal of $625.0 million. The initial principal balance was increased by $16.6 million for material and supplies and $140.0 million for paid-in-kind interest from the effective date through the Closing Date less an $18.8 million cash deposit (which was paid on the Closing Date). The proceeds of the Senior Secured Term Loan were deemed funded on the Closing Date in connection with consummation of the Sable-EM Purchase Agreement. The Senior Secured Term Loan is secured by first-priority liens on substantially all assets of the Company.
On September 6, 2024 (the “First Amendment Closing Date”), the Company entered into an amendment to the Senior Secured Term Loan (the “First Debt Amendment”), pursuant to which, approximately $4.6 million of additional principal (the “Additional Principal”) was added to the outstanding principal amount of the Senior Secured Term Loan related to the termination of a vendor contract related to the SYU Assets that was not a liability assumed in the Business Combination. In accordance with the terms of the First Debt Amendment, the Additional Principal shall be deemed to have accrued interest as if such amount has been added to the outstanding principal amount of the Senior Secured Term Loan, on January 1, 2024 (the “Amendment Effective Date”). The Additional Principal and $0.4 million associated paid-in-kind interest accrued for the period from the First Amendment Effective Date through the First Amendment Closing Date (collectively, the “Effective Additional Principal”) was added to the outstanding principal amount of the Senior Secured Term Loan on the Amendment Closing Date and was accounted for as an exit cost under the scope of FASB ASC Topic 420, Exit or Disposal Cost Obligations (“ASC 420”). As a result, the Effective Additional Principal is included within Other (income)
81
expense, net on the Company’s consolidated statement of operations for the period from February 14, 2024 through December 31, 2024 (Successor).
On November 3, 2025, the Company and Exxon entered into an amendment (the “Second Debt Amendment”) to the Senior Secured Term Loan, the effectiveness of which was contingent upon the satisfaction of certain conditions, including the Company receiving equity contributions in an amount of no less than $225.0 million, net of underwriting fees and other transaction costs and expenses, and other customary closing conditions.
On November 24, 2025, following the Third PIPE Investment (refer to Note 9—Stockholders’ Equity (Successor)), the Second Debt Amendment became effective. The Second Debt Amendment 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 also increased the interest rate from ten percent (10%) per annum to fifteen percent (15%) per annum, compounded annually (computed on a 360-day year), payable in arrears on January 1st of each year following the effective date. 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 require the Company to have not less than $25.0 million in unrestricted cash, measured at the end of each month.
Unless Sable elects in writing prior to an applicable interest payment date to pay accrued but unpaid interest in cash, all such accrued and unpaid interest shall be compounded annually on January 1st of each year by adding the relevant amount to the then outstanding principal amount of the Senior Secured Term Loan (“paid-in-kind interest”).
Debt Covenants. The Senior Secured Term Loan, dated as of the Closing Date, by and among Sable, EM, as lender, and Alter Domus Products Corp., as the administrative agent for the benefit of the lender, requires that James C. Flores, our Chairman and Chief Executive Officer, remains directly and actively involved in the day-to-day management of our business, subject to the right of the holder of such indebtedness to approve his replacement, with such approval not to be unreasonably withheld.
Restrictive covenants in the Senior Secured Term Loan impose significant operating and financial restrictions on us and our subsidiaries and we may be prevented from taking advantage of business opportunities that arise because of the limitations imposed on us by the Senior Secured Term Loan unless we gain EM’s consent. These restrictions limit our ability to, among other things: engage in mergers, consolidations, liquidations, or dissolutions; create or incur debt or liens; make certain debt prepayments; pay dividends, distributions, management fees or certain other restricted payments; make investments, acquisitions, loans, or purchase oil and gas properties; sell, assign, farm-out or dispose of any property; enter into transactions with affiliates; enter into, subject to certain exceptions, any agreement that prohibits or restricts liens securing the Senior Secured Term Loan, payments of dividends to us, or payment of debt owed to us and our subsidiaries; and change the nature of our business.
The Senior Secured Term Loan also contains representations and warranties, affirmative covenants, additional negative covenants and events of default (including a change of control). During the pendency of the Senior Secured Term Loan and in case of an event of default thereunder, EM may exercise all remedies at law or equity, and may foreclose upon substantially all of our assets and the assets of our subsidiaries, including, in the event of a deficiency, cash and any other assets not acquired from EM in the Business Combination to the extent constituting collateral under the applicable financing documents. We may not be able to obtain amendments, waivers or consents for potential or actual breaches of such representations and warranties or covenants, or we may be unable to obtain such amendments waivers or consents on acceptable terms, all of which could limit management’s flexibility to operate the business. As of December 31, 2025, the Company was in compliance with all covenants under its Senior Secured Term Loan.
82
Debt consisted of the following as of:
| December 31, | |||||||||||
| (in thousands) | 2025 | 2024 | |||||||||
| Senior Secured Term Loan, including paid-in-kind interest | $ | 921,868 | $ | — | |||||||
| Less: Debt issuance costs, net | (284) | — | |||||||||
| Total short-term debt, net | 921,584 | — | |||||||||
| Senior Secured Term Loan, including paid-in-kind interest | — | 834,165 | |||||||||
| Less: Debt issuance costs, net | — | (623) | |||||||||
| Total long-term debt, net | $ | — | $ | 833,542 | |||||||
For the year ended December 31, 2025 (Successor) and the period from February 14, 2024 through December 31, 2024 (Successor), the Company incurred interest expense of $88.2 million, and $67.3 million, respectively, which is included as interest expense on the consolidated statements of operations and the paid-in-kind interest is accrued and included in the Senior Secured Term Loan on the consolidated balance sheets as of December 31, 2025 and 2024, respectively. For the year ended December 31, 2025 (Successor) and for the period from February 14, 2024 through December 31, 2024 (Successor), the Company’s effective interest rate on the Senior Secured Term Loan was approximately 10.5% and 10.0%, respectively.
Note 7 — Warrants
There were 8,987,062 warrants outstanding as of December 31, 2025 and 2024, respectively. There were no changes in the number of warrants outstanding for the year ended December 31, 2025. The table below reflects warrant activity since the Closing:
| Public Warrants | Private Placement Warrants | Working Capital Warrants | Total | ||||||||||||||||||||
| Outstanding Warrants as of February 14, 2024 | 14,374,971 | 7,750,000 | — | 22,124,971 | |||||||||||||||||||
| Issued | — | — | 3,306,370 | 3,306,370 | |||||||||||||||||||
| Transferred | 1,609,564 | (1,609,564) | — | — | |||||||||||||||||||
| Exercised | (15,957,820) | (459,744) | — | (16,417,564) | |||||||||||||||||||
| Redemptions | (26,715) | — | — | (26,715) | |||||||||||||||||||
| Outstanding Warrants as of December 31, 2025 and 2024 | — | 5,680,692 | 3,306,370 | 8,987,062 | |||||||||||||||||||
Public Warrants
As described in Note 1—Organization, Business Operations, and Going Concern, all of the Public Warrants were either exercised or redeemed during the period from February 14, 2024 through December 31, 2024 (Successor). The Public Warrants were only exercisable for a whole number of shares prior to their redemption and no fractional shares were issued upon exercise of the Public Warrants. The Public Warrants became exercisable 30 days after the completion of the Business Combination.
Redemption of Warrants For Cash—Prior to the Redemption Date (defined below), the Company was able to redeem the outstanding Public Warrants for cash:
•in whole and not in part;
•at a price of $0.01 per Public Warrant;
•upon not less than 30 days’ prior written notice of redemption to each warrant holder; and
•if, and only if, the last sale price of our Common Stock equals or exceeds $18.00 per share (as adjusted for stock splits, stock dividends, reorganizations, recapitalizations and the like) for any 20 trading days within a 30-trading day period ending on the third trading day prior to the date on which the Company sends the notice of redemption to the warrant holders.
83
On October 3, 2024, the conditions under which the Public Warrants could be redeemed for cash were satisfied and the Company announced that it would redeem all of the Public Warrants that remained outstanding after 5:00 p.m. New York City time on November 4, 2024 (the “Redemption Date”), for a redemption price of $0.01 per warrant (the “Redemption”).
On October 31, 2024, the Public Warrants ceased trading on the New York Stock Exchange following the Company’s announcement to redeem all remaining outstanding Public Warrants. During the period from February 14, 2024 through December 31, 2024 (Successor), approximately 99.8% of the Public Warrants were exercised by the holders thereof at an exercise price of $11.50 per share. As a result, holders of the Public Warrants received an aggregate 15,957,820 shares of the Company’s Common Stock in exchange for $183.5 million in cash proceeds to the Company. The remaining 26,715 Public Warrants that were not exercised were redeemed by the Company for $0.01 per Public Warrant.
Prior to their exercise/redemption, the Public Warrants were accounted for as a derivative liability and carried on the consolidated balance sheets at fair value. Upon exercise, the fair value of the derivative liability was reclassified to stockholders’ equity in accordance with FASB ASC Topic 480, Distinguishing Liabilities from Equity (“ASC 480”).
Private Placement Warrants and Working Capital Warrants
The Company will not be obligated to deliver any shares of Common Stock pursuant to the exercise of a Private Placement Warrant or Working Capital Warrant and will have no obligation to settle such exercise unless a registration statement under the Securities Act with respect to the shares of Common Stock underlying the warrants is then effective and a prospectus relating thereto is current, subject to the Company satisfying its obligations with respect to registration, or a valid exemption from registration is available. No warrant will be exercisable, and the Company will not be obligated to issue a share of Common Stock upon exercise of a warrant unless the share of Common Stock issuable upon such warrant exercise has been registered, qualified or deemed to be exempt under the securities laws of the state of residence of the registered holder of the warrants.
On the Closing Date, the Company filed with the SEC a registration statement for the registration, under the Securities Act, of the shares of Common Stock issuable upon exercise of the warrants, which the SEC declared effective on May 10, 2024. The Company will use its commercially reasonable efforts to maintain the effectiveness of such registration statement, and a current prospectus relating thereto, until the exercise or expiration of the warrants in accordance with the provisions of the warrant agreement. In addition, if the shares of Common Stock are at the time of any exercise of a warrant not listed on a national securities exchange such that they satisfy the definition of a “covered security” under Section 18(b)(1) of the Securities Act, the Company may, at its option, require holders of the Private Placement Warrants or Working Capital Warrants who exercise their warrants to do so on a “cashless basis” in accordance with Section 3(a)(9) of the Securities Act and, in the event the Company elects to do so, the Company will not be required to file or maintain in effect a registration statement, but it will use its best efforts to register or qualify the shares under applicable blue sky laws to the extent an exemption is not available.
The Private Placement Warrants, the Working Capital Warrants, and the shares of Common Stock issuable upon the exercise of such warrants were not transferable, assignable or salable until 30 days after the Closing Date, subject to certain limited exceptions, and are entitled to registration rights. Additionally, the Private Placement Warrants and Working Capital Warrants are exercisable on a cashless basis and non-redeemable so long as they are held by the initial purchasers or their permitted transferees. If the Private Placement Warrants or Working Capital Warrants are held by someone other than the initial purchasers or their permitted transferees, such warrants will be redeemable by the Company and exercisable by such holders on the same basis as the Public Warrants. In the event that the holder of a Private Placement Warrant or a Working Capital Warrant elect to exercise on a cashless basis, each holder would pay the exercise price by surrendering the warrants for that number of shares of Common Stock equal to (A) the quotient obtained by dividing (x) the product of the number of shares of Common Stock underlying the warrants, multiplied by the excess of the “fair market value” less the exercise price of the warrants by (y) the fair market value. The “fair market value” shall mean the volume weighted average price of the shares of Common Stock for the 10 trading days ending on the trading day prior to the date on which the notice of exercise is received by the warrant agent. Additionally, in no event will the Company be required to net cash settle the Private Warrants or Working Capital Warrants upon exercise.
During the period from February 14, 2024 through December 31, 2024 (Successor), warrant holders exercised 459,744 Private Placement Warrants on a cashless basis for 212,637 shares of Common Stock. These exercises were accounted for in accordance with ASC 480 in the same manner as exercises of Public Warrants described above. There were no Private Placement warrants exercised during the year ended December 31, 2025 (Successor).
The Private Placement Warrants and Working Capital Warrants that remain outstanding as of December 31, 2025 and 2024, respectively, are accounted for as liabilities and marked-to-market at each reporting period, with changes in fair
84
value included as Changes in fair value of warrant liabilities in the Successor’s consolidated statements of operations (refer to Note 11—Fair Value Measurements).
On February 24, 2026, the Private Placement Warrants held by Intrepid Financial Partners, L.L.C. (“Intrepid Financial Partners”) expired unexercised upon the fifth anniversary of the effective date of the registration statement pursuant to FINRA Rule 5110(g)(8)(A) and became cancellable by the Company. Intrepid Financial Partners is seeking an exemption from FINRA to Rule 5110(g)(8)(A) and, if an exemption is granted, the expiration date of these Private Placement Warrants may be extended. The exercise period end date for Intrepid’s Private Placement Warrants differed from the Company’s other Private Placement Warrants and Working Capital Warrants, which expire five years after the Closing Date, February 14, 2029, or earlier upon redemption or liquidation.
Note 8 — Commitments and Contingencies
Registration Rights
The holders of the Founder Shares (defined below), Private Placement Warrants and Working Capital Warrants (and any shares of Common Stock issuable upon the exercise of such instruments) are entitled to registration rights pursuant to a registration rights agreement. The holders of these securities are entitled to make up to three demands, excluding short form demands, that the Company register such securities. In addition, the holders have certain “piggy-back” registration rights with respect to registration statements filed subsequent to the completion of a Business Combination. However, the registration rights agreement provides that the Company will not permit any registration statement filed under the Securities Act to become effective until termination of the applicable lockup period. The Company will bear the expenses incurred in connection with the filing of any such registration statements.
Grey Fox Matter
On March 26, 2024, Sable entered into a Stipulation and Agreement of Settlement (the “Settlement Agreement”) among (i) Grey Fox, LLC, MAZ Properties, Inc., Bean Blossom, LLC, Winter Hawk, LLC, Mark Tautrim, Trustee of the Mark Tautrim Revocable Trust, and Denise McNutt, on behalf of themselves and the Court-certified Settlement Class (the “Plaintiffs and Settlement Class Members”), (ii) Pacific Pipeline Company (“PPC”) and (iii) Sable, with respect to the settlement and release of certain claims related to the Pipeline Segments 324 and 325, including claims impacting the right of way for the Pipeline Segments (collectively, the “Released Claims”).
Pursuant to the terms of the Settlement Agreement, (i) the Plaintiffs and Settlement Class Members are obligated to, among other things, (a) release Sable, PPC and the other released parties from and against the Released Claims, (b) grant certain temporary construction easements to facilitate the repair of certain portions of the Pipeline Segments 324 and 325, and (c) cooperate in good faith with Sable and PPC with respect to any and all steps reasonably required to resume petroleum transportation through the Pipeline Segments 324 and 325 and operate them thereafter, including obtaining all necessary regulatory approvals, consistent with the requirements of the relevant government agencies and the Consent Decree issued by the United States District Court for the Central District of California in relation to Civil Action No. 2:20-cv-02415 (United States of America and the People of the State of California v. Plains All American Pipeline, L.P. and Plains Pipeline, L.P.) and (ii) Sable agreed to among other things, (a) pay $35.0 million into an interest-bearing non-reversionary Qualified Settlement Fund, and (b) deliver to class counsel an irrevocable direct pay letter of credit issued by J.P. Morgan & Co. or another federally insured bank in the amount of $35.0 million to secure Sable’s obligation to make certain payments under the Settlement Agreement. The Company expensed $70.0 million upon the effectiveness of the Settlement Agreement, which is included in general and administrative expenses on the consolidated statement of operations for the period from February 14, 2024 through December 31, 2024 (Successor).
On May 1, 2024, the United States District Court for the Central District of California entered an order granting preliminary approval of the Settlement Agreement, and thus, on May 9, 2024, the Company made the initial $35.0 million payment into the Qualified Settlement Fund and delivered the $35.0 million Letter of Credit to plaintiffs’ counsel. On September 17, 2024, the court approved the Settlement Agreement in full. On September 30, 2025, the Plaintiffs submitted a draw statement on the irrevocable direct pay letter of credit in the amount of $35.0 million, and the Company paid the Plaintiffs directly the interest owed. On July 7, 2025, in accordance with the Settlement Agreement, J.P. Morgan & Co. processed the $35.0 million draw statement and wired the funds to Plaintiffs pursuant to the Letter of Credit. J.P. Morgan & Co. subsequently accepted the $35.0 million restricted cash as settlement in full of the obligations created by the draw of the Letter of Credit, all as contemplated by the Settlement Agreement.
85
California Coastal Commission Matter
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 the 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 the 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 Pipeline Segments 324 and 325 anomaly maintenance and repair work 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 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 the 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 subject to the Notice of Violation was previously approved and that no further coastal development permit is 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
86
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. The Company does not believe this penalty is lawful and has not recognized any accrued expense for the year ended December 31, 2025. Sable is prepared 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 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 $347.0 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 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, 2025.
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.
87
Zaca Preserve Matter
On October 3, 2024, plaintiff Zaca Preserve LLC filed a California state court complaint against Sable, its subsidiary PPC, Plains All American Pipeline LP, and Plains Pipeline LP. The case is captioned 24CV05483 and is pending in Santa Barbara Superior Court, Anacapa Division. The plaintiff filed a First Amended Complaint on December 12, 2024, and served the complaint on Sable and PPC on December 18, 2024.
The plaintiff was a class member of the Grey Fox litigation that was settled effective September 17, 2024, and chose to opt out of the final settlement class. The plaintiff raises claims similar to the Grey Fox plaintiffs, namely that the pipeline easement on its property is no longer valid in light of the 2015 Refugio oil spill and the conduct of defendants. The plaintiff brings contract and tort claims and seeks declaratory and injunctive relief determining his easement terminated and prohibiting defendants from accessing or using his easement to resume pipeline operations. The plaintiff seeks compensatory, exemplary, and statutory damages, costs, attorneys’ fees, and interest, as well as declaratory and injunctive relief. By stipulation, Sable and PPC’s deadline to respond to the First Amended Complaint was March 4, 2025. Sable and PPC timely filed and served their Demurrer to the Plaintiff’s First Amended Complaint and Sable filed and served a Motion to Strike the First Amended Complaint. The Demurrer and Motion to Strike were heard November 12, 2025. The court sustained the Demurrer, without leave to amend as to Plaintiff’s causes of action for injunctive relief, negligent misrepresentation, negligence, UCL violation, permanent nuisance and threatened nuisance, and denied the Motion to Strike. Plaintiffs filed a Second Amended Complaint on December 12, 2025. Sable and PPC answered the Second Amended Complaint on February 11, 2026, and intend to defend the case vigorously.
BSEE Matter
On June 27, 2024, the Center for Biological Diversity and the Wishtoyo Foundation filed a complaint against Debra Haaland, Secretary of the U.S. Department of the Interior; the Bureau of Safety and Environmental Enforcement (“BSEE”); and Bruce Hesson, BSEE Pacific Regional Director in the U.S. District Court for the Central District of California (Case No. 2:24-cv-05459). Sable intervened and vigorously contests the plaintiffs’ allegations. In the plaintiffs’ January 2025 first supplemental and amended complaint, the plaintiffs alleged that BSEE: violated the National Environmental Policy Act (“NEPA”), the Outer Continental Shelf Lands Act (“OCSLA”), and the Administrative Procedure Act (“APA”) in November 2023 by approving an extension to resume operations associated with the 16 oil and gas leases Sable holds in the SYU in federal waters offshore of California in the Santa Barbara Channel; and violated NEPA and the APA in September 2024 by approving applications for permits to modify for well reworking operations and by failing to conduct supplemental environmental analysis for oil and gas development and production in the SYU. The complaint asked for the court: to issue an order finding that BSEE violated NEPA, OCSLA and the APA; to vacate and remand the extension and the applications for permits to modify; to order BSEE to complete NEPA analysis by a date certain; to prohibit BSEE from authorizing further extensions, applications for permits to modify, or any other authorizations for resuming production until it complies with NEPA, OCSLA and the APA; and for an award of costs and attorneys’ fees. Sable believes that the government’s prior extensions to resume operations were both appropriate and authorized and independently that subsequent actions, including a May 28, 2025 Environmental Assessment (the “2025 Environmental Assessment”) relied on by BSEE and a May 29, 2025 decision by BSEE approving the extension, render plaintiffs’ corresponding claims moot. On September 24, 2025, the court denied cross-motions for summary judgment by all parties.
On November 7, 2025, the court approved a new scheduling order. On November 10, 2025, plaintiffs filed their second supplemental and amended complaint against Doug Burgum, Secretary of the U.S. Department of the Interior; BSEE; and Bobby Kurtz, BSEE Acting Pacific Regional Director. Plaintiffs added new claims to their existing complaint alleging that BSEE: violated NEPA and the APA in July 2025 by approving additional applications for permits to modify; and violated NEPA and the APA when issuing the May 29, 2025 decision approving the extension based upon the 2025 Environmental Assessment. In addition to the relief plaintiffs already sought, the second supplemental and amended complaint also asks the court: to issue an order finding that BSEE violated NEPA and the APA when issuing the July 2025 applications for permits to modify; to vacate and remand the July 2025 applications for permits to modify, the 2025 Environmental Assessment and Finding of No Significant Impact, and BSEE May 29, 2025 decision approving the extension. On November 24, 2025, Sable filed its answer to the second supplemental and amended complaint. The federal government lodged an updated administrative record on December 19, 2025. A hearing on Plaintiffs’ motion to compel completion and supplementation of the administrative record is scheduled for March 13, 2026.
88
BOEM Matter
On April 2, 2025, the Center for Biological Diversity and the Wishtoyo Foundation filed a complaint against Doug Burgum, Secretary of the U.S. Department of the Interior; BOEM; and Douglas Boren, BOEM Pacific Regional Director, in the U.S. District Court for the Central District of California (Case No. 2:25-cv-02840). On May 12, 2025, plaintiffs filed an amended complaint in which plaintiffs challenge BOEM’s April 2025 decision determining that Sable is not required to revise the development and production plan for Platform Harmony in the SYU. The amended complaint asks for the court: to issue an order finding that BOEM’s decision was not in accordance with OCSLA and violated the APA; order BOEM to require revision of the development and production plan for Platform Harmony; prohibit BOEM from authorizing new oil and gas drilling activity at the SYU unless and until revision of the development and production plan is complete; and for an award of costs and attorneys’ fees. Sable intervened and vigorously contests the plaintiffs’ allegations. On September 10, 2025, the court denied Sable’s motion to dismiss based on plaintiffs’ failure to provide notice under OCSLA’s citizen suit provision. The court approved a scheduling order that provides for a hearing on cross-motions for summary judgment on May 15, 2026. Per the scheduling order, plaintiffs filed their motion for summary judgment on December 12, 2025. On February 6, 2025, the federal government filed and on February 20, 2026 Sable filed their respective oppositions to plaintiffs’ motion for summary judgment and cross-motions for summary judgment. A hearing on the motions for summary judgment is scheduled for May 15, 2026.
Regional Water Quality Control Board and Department of Fish and Wildlife Matters
On December 13, 2024, the California Central Coast Regional Water Quality Control Board (“Regional Board”) issued three letters to the Company related to Pipeline Segments 324 and 325 of the Santa Ynez Pipeline System: (i) a Notice of Violation for an alleged unauthorized discharge of waste to waters of the state at an ephemeral stream in Santa Barbara 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 Construction Stormwater Discharges in Santa Barbara, San Luis Obispo, and Kern Counties.
On December 17, 2024, the California Department of Fish and Wildlife (“CDFW”) issued a Notice of Potential Violation to Sable for alleged violations of the California Fish and Game Code at four separate sites within Santa Barbara County and San Luis Obispo County in California for alleged placement or fill of waste to waters.
On January 10, 2025, Sable submitted a written response to the Regional Board’s December 2024 letters. On January 13, 2025, Sable submitted a written response to CDFW’s December 2024 Notice of Potential Violation. On January 22, 2025, the Regional Board issued two additional letters to Sable related to 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 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
89
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 against the Company 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 and based on the same underlying activities that were the focus of the Regional Board and CDFW actions. 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.
County Permit Transfer Matter
In October 2024, the County of Santa Barbara’s Planning Commission approved the transfer of the Final Development Permits for the SYU, POPCO Facilities and Pipeline Segments 324 and 325 from Exxon and certain of its subsidiaries to the Company and its subsidiaries, PPC and POPCO, pursuant to Santa Barbara County Code Chapter 25B. That approval was appealed by various environmental advocacy groups to the Santa Barbara County Board of Supervisors. On February 25, 2025, the Board of Supervisors heard the appeals but, despite a County staff recommendation to reject the appeals, did not decide them, splitting 2-2 in a tie vote. As the appeals did not reverse the Planning Commission’s decision, the Company thereafter sought the permit transfers from the County, but it was unsuccessful.
On May 8, 2025, the Company, its subsidiaries, PPC and POPCO, and Exxon and certain of its subsidiaries filed suit against the County of Santa Barbara and Board of Supervisors seeking a writ of mandamus directing Santa Barbara County to issue updated Final Development Permits reflecting the Sable plaintiffs as holders thereof, for declaratory relief finding that the County’s Chapter 25B ordinances violate the United States and California Constitutions, and for damages. Several environmental advocacy groups intervened in the litigation. On September 12, 2025, after a hearing, the court issued an order of mandate requiring that “within 60 days of service of the writ of mandate on the Board, hold a de novo public hearing to affirm, reverse, or modify the Planning Commission’s decision regarding Petitioners/Plaintiffs’ Final Development Permit applications in this action in compliance with Santa Barbara County Code Chapter 25B-8, 9, and 10. If the Board is unable to reach a vote that affirms, reverses, or modifies the Planning Commission’s decision, the Board shall hold another de novo public hearing within 45 days, and if unable again, every 45 days thereafter.” The litigation was stayed pending the final action at the Board of Supervisors’ re-hearing. The County set a hearing in this matter pursuant to the writ of mandate for November 4, 2025. At that hearing, the Board voted to continue the hearing until December 16, 2025, and directed County staff to prepare findings that would grant the appeals and deny the transfer of the permits to Sable for consideration at that hearing. At the December 16 hearing, the Board adopted the findings to grant the appeals and deny the transfer of the permits. The matter will return to federal court.
Johnson Class Action / Kelly and Vora Derivative Claims
On July 28, 2025, shareholder Tracy Johnson filed a putative class action complaint against the Company in the U.S. District Court for the Central District of California, captioned Johnson v. Sable Offshore Corp., et al., Case No. 2:25-cv-06869 (C.D. Cal) (the “Johnson Action”). The complaint alleged violations of Sections 10(b) and 20(a) of the Exchange Act of 1934 and Sections 11, 12(a)(2), and 15 of the Securities Act of 1933, on behalf of a putative class of investors who purchased or acquired Sable’s publicly traded securities between May 19, 2025 and June 3, 2025, when the Company engaged in a public offering, and/or pursuant and/or traceable to the offering. The complaint named as defendants the Company, certain of its officers, and the underwriters in the offering.
90
On October 27, 2025, the Court appointed a lead plaintiff. On November 10, 2025, the lead plaintiff filed an amended complaint purportedly on behalf of persons or entities who purchased or otherwise acquired publicly traded Sable securities between May 19, 2025 and November 4, 2025. The amended complaint dropped the claims under the Securities Act of 1933 and dropped the underwriters as defendants. On November 24, 2025, Defendants moved to dismiss the amended complaint. On December 8, 2025, the lead plaintiff filed a second amended complaint. The second amended complaint alleges, among other things, that the Company and certain of its officers made false and misleading statements or failed to disclose certain information regarding the Company’s business activities at the Santa Ynez Unit. The plaintiff seeks damages, costs, expenses, expert and attorneys’ fees, and other unspecified relief. On January 5, 2026, Defendants moved to dismiss the second amended complaint. Plaintiff filed an opposition on January 12, 2026. Defendants’ reply was filed on January 26, 2026, and the motion to dismiss was heard on February 23, 2026. The Company intends to vigorously defend against the claims in this lawsuit.
On August 21, 2025, shareholder Bryce Kelly filed a verified shareholder derivative complaint, purportedly on behalf of the Company, in the U.S. District Court for the Central District of California, captioned Kelly v. Flores, et al., Case No. 2:25-cv-07848 (C.D. Cal.) (the “Kelly Action”). The complaint names as defendants the members of the Board of Directors of the Company, certain officers of the Company, and the underwriters of the Company’s May 2025 public offering. The complaint alleges claims for breach of fiduciary duty, aiding and abetting breach of fiduciary duty, unjust enrichment, waste of corporate assets, contribution under Section 10(b) and 21D of the Exchange Act of 1934, and contribution under Section 11(f) of the Securities Act of 1933, based on similar factual allegations to those at issue in the Johnson Action. On December 12, 2025, the Kelly Action was ordered stayed pending the motion to dismiss filed in the Johnson Action.
On December 17, 2025, shareholder Udit Vora filed a verified shareholder derivative complaint, purportedly on behalf of the Company, in the U.S. District Court for the Central District of California, captioned Vora v. Flores, et al., Case No. 2:25-cv-11944 (C.D. Cal.) (the “Vora Action”). The complaint names as defendants the members of the Board of Directors of the Company and certain officers of the Company. The complaint alleges claims for breach of fiduciary duties, unjust enrichment, abuse of control, gross mismanagement, waste of corporate assets, and contribution under Sections 10(b) and 21D of the Securities Exchange Act of 1934, based on similar factual allegations to those at issue in the Johnson Action. The case is at a preliminary stage.
CalGEM
On May 9, 2025, the California Department of Conservation’s Geologic Energy Management Division (“CalGEM”) issued a letter to the Company asserting that the Company’s Las Flores Canyon Facility is a “production facility” under the California Public Resources Code and therefore subject to various statutory requirements applicable to such facilities. In that letter, CalGEM’s demanded that the Company post a bond of approximately $31.9 million, submit certain oil spill contingency response and management plans for CalGEM’s review, and indicating that the failure to timely respond could result in civil penalties of up to $50,000 per day/per violation. On January 27, 2026, CalGEM issued a letter to the Company revising the bond amount to approximately $57.3 million based on material increases to the estimates for labor, equipment, transportation, engineering, and handling costs associated with decommissioning and remediation after an additional on-site inspection by CalGEM. Sable disputes that CalGEM possesses jurisdiction to impose those requirements. On February 17, 2026, Sable filed a lawsuit against CalGEM, the State Oil and Gas Supervisor, the California Department of Conservation, and its Director, seeking a writ of mandate against these agencies and officers prohibiting them from enforcing those provisions of the California Public Resources Code applicable to oil and gas production facilities against Sable, as well as a declaratory judgment that Sable’s Las Flores Canyon Facility is not a “production facility” under California Public Resources Code section 3010.
California Senate Bill 237
On September 13, 2025, the California Legislature passed Senate Bill 237 (“SB 237”). On September 19, 2025, Governor Gavin Newsom signed SB 237 into law. SB 237 became effective January 1, 2026. SB 237 added Section 51014.1 to the California Government Code, which requires that an “existing oil pipeline … that has been idle, inactive, or out of service for five years or more, shall not be restarted without passing a spike hydrostatic testing program.” SB 237 also amends Section 30262 of the California Coastal Act to provide that the “[r]epair, reactivation, [] maintenance,” or “[d]evelopment associated with the repair, reactivation or maintenance of an oil pipeline that has been idled, inactive or out of service for five years or more” must obtain a “new coastal development permit.”
On September 29, 2025, Sable filed a Complaint for Declaratory Relief against the State of California in Kern County Superior Court seeking a declaratory judgment that the Santa Ynez Pipeline System is not subject to SB 237 because the Santa Ynez Pipeline System is not “idle, inactive, or out of service,” and because the Legislature did not give SB 237 retroactive effect. On January 21, 2026, the Company filed its First Amended Complaint adding a claim that the application
91
of SB 237 to the Santa Ynez Pipeline System is preempted by federal law. On February 20, 2026, the State of California removed the case to the U.S. District Court for the Eastern District of California. Sable intends to continue to vigorously prosecute the action.
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.
Office of State Fire Marshal Matters
On December 17, 2024, the California Office of the State Fire Marshal (“OSFM”) approved Sable’s implementation of enhanced pipeline integrity standards for the 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 Pipeline and Hazardous Materials Safety Administration (“PHMSA”) notified the 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. 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. 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.
A hearing was held 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 Pipeline Segments 324 and 325 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 provided its initial response to the OSFM 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.
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
92
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; Pipeline and Hazardous Materials Safety Administration (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.
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.
Note 9 — Stockholders’ Equity (Successor)
Preferred Stock — The Company is authorized to issue a total of 1,000,000 shares of preferred stock at par value of $0.0001 each. As of December 31, 2025 and 2024, there were no shares of preferred stock issued or outstanding.
Common Stock — The Company is authorized to issue a total of 500,000,000 shares of Common Stock at par value of $0.0001 each. As of December 31, 2025 and 2024, there were 144,961,796 and 89,310,996 shares issued and outstanding, respectively.
Equity Issuance. On the Closing Date, the Company issued 44,024,910 shares of Common Stock of the Company, at a price of $10.00 per share for aggregate gross proceeds of $440.2 million (the “First PIPE Investment”). The shares of Common Stock issued in the First PIPE Investment were offered in a private placement under the Securities Act of 1933, as amended (the “Securities Act”). Upon the closing of the Business Combination, an associated marketing fee and legal fees of approximately $22.9 million was paid in full, and was recognized as an offset to the proceeds from the First PIPE Investment within Additional paid-in capital in the consolidated balance sheets and statements of changes in stockholders’ equity (deficit)/net parent investment as of December 31, 2025 and 2024.
On September 26, 2024, the Company issued 7,500,000 shares of Common Stock of the Company, at a price of $20.00 per share for aggregate gross proceeds of approximately $150.0 million (the “Second PIPE Investment”). The shares of Common Stock issued in the Second PIPE Investment were offered in a private placement under the Securities Act. Upon the closing of the Second PIPE Investment, associated marketing fee and legal fees of approximately $7.8 million was paid in full, and was recognized as an offset to the proceeds from the Second PIPE Investment within Additional paid-in capital in the consolidated balance sheets and statements of changes in stockholders’ equity (deficit)/net parent investment as of December 31, 2025 and 2024.
On May 23, 2025, the Company closed an upsized underwritten public offering of 10,000,000 shares of Common Stock at the public offering price of $29.50 per share for aggregate gross proceeds of approximately $295.0 million. Upon the closing of the 2025 Offering, associated marketing fees and legal fees of approximately $12.4 million were incurred, and were recognized as an offset to the proceeds from the 2025 Offering within Additional paid-in capital in the consolidated balance sheet and statement of stockholders’ equity (deficit)/net parent investment as of December 31, 2025.
On November 10, 2025, the Company entered into subscription agreements with certain investors (the “Third PIPE Investors”), pursuant to which, among other things, the Third PIPE Investors agreed to subscribe for and purchase from the
93
Company, and the Company agreed to issue and sell to the Third PIPE Investors an aggregate of 45,454,546 newly issued shares of its Common Stock on the terms and subject to the conditions set forth therein (the “Third PIPE Investment”).
On November 12, 2025, in connection with the Third PIPE Investment, the Company issued 45,454,546 shares of Common Stock of the Company, at a price of $5.50 per share for aggregate gross proceeds of approximately $250.0 million. Upon the closing of the Third PIPE Investment, associated marketing and legal fees of approximately $14.2 million were incurred, and were recognized as an offset to the proceeds from the Third PIPE Investment within Additional paid-in capital in the consolidated balance sheet and statement of stockholders’ equity (deficit) as of December 31, 2025.
Transportation Assets. As discussed in Note 5—Related Party Transactions, on October 3, 2024, the Company purchased transportation assets and related equipment in exchange for 600,000 shares of the Company’s Common Stock, valued at $15.2 million.
Founders Shares. 7,187,500 shares of Common Stock held by the initial stockholders (“Founders Shares”) are not transferable, assignable or salable (except to our officers and directors and other persons or entities affiliated with the Sponsor, each of whom will be subject to the same transfer restrictions) until the earlier of (A) February 13, 2025 or (B) subsequent to February 14, 2024, (x) if the last sale price of our Common Stock equals or exceeds $12.00 per share (as adjusted for stock splits, stock dividends, reorganizations, recapitalizations and the like) for any 20 trading days within any 30-trading day period commencing at least 150 days after February 14, 2024, or (y) the date on which the Company completes a liquidation, merger, capital stock exchange, reorganization or other similar transaction that results in all of our stockholders having the right to exchange their shares of Common Stock for cash, securities or other property (such restrictions on transfer, the “Restrictions”). The stock performance conditions described in (B) above were satisfied on August 9, 2024 and, accordingly, the Restrictions no longer apply to the Founder Shares.
Warrants Exercised. During the period from February 14, 2024 through December 31, 2024 (Successor), warrant holders exercised 15,957,820 Public Warrants for 15,957,820 shares of Common Stock resulting in approximately $183.5 million in cash proceeds to the Company. Additionally, 459,744 Private Placement Warrants were exercised on a cashless exercise basis for 212,637 shares of Common Stock. Refer to Note 7—Warrants for further discussion of warrant related activities.
Note 10 — Share Based Compensation
Prior to the Business Combination, the Company’s stockholders approved a share based compensation plan (the “Incentive Plan”) to enhance the Company’s ability to attract, retain and motivate persons who make (or are expected to make) important contributions to the Company by providing these individuals with equity ownership opportunities and/or equity-linked compensatory opportunities. The Predecessor had no equity compensation plans or outstanding equity awards specific to the SYU Assets. The total stock-based compensation expense is included on the consolidated statements of operations based upon the job function of the employees receiving the grants as follows:
| Successor | |||||||||||
(in thousands) | Year Ended December 31, 2025 | February 14—December 31, 2024 | |||||||||
| Operations and maintenance expenses | $ | 5,107 | $ | 5,045 | |||||||
| General and administrative expenses | 37,572 | 86,564 | |||||||||
| Total | $ | 42,679 | $ | 91,609 | |||||||
Incentive Plan
The Company’s Incentive Plan includes incentive stock options and nonqualified stock options, stock appreciation rights, restricted stock, dividend equivalents, restricted stock units and other stock or cash-based awards. Certain awards under the Incentive Plan may constitute or provide for payment of “nonqualified deferred compensation” under Section 409A of the Code, which may impose additional requirements on the terms and conditions of such awards. Awards other than cash awards generally will be settled in shares of the Company’s Common Stock, but the applicable award agreement may provide for cash settlement of any award.
Our employees, consultants and directors, and employees and consultants of our subsidiaries, may be eligible to receive awards under the Incentive Plan. Following the closing of the Business Combination, the Compensation Committee of the Company’s Board of Directors (the “Board”) was appointed by the Board to administer the Incentive Plan (the Compensation Committee, in its role as administrator of the Incentive Plan, the “Plan Administrator”).
94
The Plan Administrator has the authority to take all actions and make all determinations under the Incentive Plan, to interpret the Incentive Plan and award agreements and to adopt, amend and repeal rules for the administration of the Incentive Plan as it deems advisable. The Plan Administrator will also have the authority to, among other things, determine which eligible service providers receive awards, grant awards, set the terms and conditions of all awards under the Incentive Plan, including any performance goals, vesting and vesting acceleration provisions, subject to the conditions and limitations in the Incentive Plan, accelerate vesting requirements, waive or amend performance goals and other restrictions, and amend award agreements. As of December 31, 2025, 866,558 share based awards were authorized and available to be granted by the Plan Administrator under the Successor’s Incentive Plan.
Restricted Stock Awards
On the Closing Date, and in connection with the executive officers’ employment agreements, the Company granted 650,000 shares of restricted Common Stock to each of the Company’s executive officers (other than Mr. Flores), which vest on the restart of sales of production from the SYU Assets. The executive officer shares are subject to a three-year lock-up period which began on the Closing Date.
During March 2024, the Plan Administrator authorized the grant of 158,334 shares of restricted Common Stock in the aggregate to the independent members of the Board for their contributions towards closing the Business Combination and for their service on the Board. These restricted shares vested 12 months after the grant date.
Additionally, 2,237,190 shares of restricted Common Stock, net of forfeitures, were granted to employees of the Company through December 31, 2025, 2,218,190 of which vested following the May 15, 2025 restart of production from the SYU Assets. The remaining 19,000 shares of restricted Common Stock will vest 12 months from their respective grant dates. All of the executive officer awards, the awards granted to the members of the Board, and the awards granted to employees of the Company following the closing of the Business Combination are restricted stock awards to be settled in shares, and qualify as equity classified awards. The value of the stock-settled restricted stock awards is established by the market price on the date of grant and was recorded as compensation expense ratably over the vesting terms. Forfeitures are recognized as they occur.
The following table summarizes restricted stock award activity for the year ended December 31, 2025 (Successor), and for the period February 14, 2024 through December 31, 2024 (Successor):
| Successor | |||||||||||||||||||||||
| Year Ended December 31, 2025 | February 14—December 31, 2024 | ||||||||||||||||||||||
| Weighted-average grant date fair value | Weighted-average grant date fair value | ||||||||||||||||||||||
| Shares | Shares | ||||||||||||||||||||||
| Non-vested, beginning of the period | 4,874,270 | $ | 11.99 | — | $ | — | |||||||||||||||||
| Granted | 227,885 | 25.91 | 4,875,270 | 11.99 | |||||||||||||||||||
| Vested | (2,376,524) | 13.10 | — | — | |||||||||||||||||||
| Forfeited | (106,631) | 11.46 | (1,000) | 10.97 | |||||||||||||||||||
| Non-vested, end of the period | 2,619,000 | $ | 12.22 | 4,874,270 | $ | 11.99 | |||||||||||||||||
There was $0.3 million unrecognized stock-based compensation expense associated with unvested restricted stock awards as of December 31, 2025, which is to be recognized over the weighted average remaining life of less than one year.
Restricted Stock Units
In April 2025, the Compensation Committee approved long-term incentive grants of up to 10,653,076 restricted stock units to our CEO, executive officers and other employees of the Company. The restricted stock units will vest over , or three-year periods and generally will vest ratably and annually beginning on the one-year anniversary of the grant date. The associated restricted stock unit agreements also include dividend equivalent rights, which entitle the grantee to the aggregate value of the dividends declared on the Common Stock, if any, whose dividend record date occurs during the period from the grant date until the day before the applicable settlement date for such vested restricted stock unit. Each
95
annual vesting of restricted stock units (and the right to receive the corresponding dividend equivalent amount) is subject to continued service by the grantee.
No restricted stock units were granted during the period February 14, 2024 through December 31, 2024 (Successor), the period January 1, 2024 through February 13, 2024 (Predecessor), or the year ended December 31, 2023 (Predecessor).
There were 10,084,265 outstanding restricted stock units that were granted and are to be settled in shares, which qualify as equity classified awards, while 381,300 outstanding restricted stock units granted are to be settled in cash, and therefore are accounted for as liability classified awards. The value of the stock-settled restricted stock units is established by the market price of the Company’s Common Stock on the date of grant and is recorded as compensation expense ratably over the vesting terms. The value of the cash-settled restricted stock units is also established by the market price of the Company’s Common Stock but is remeasured at the end of each reporting period through settlement, with the related compensation expense recognized ratably over the vesting terms based on the change in the liability. The liability recognized for the cash-settled restricted stock units is presented within other current liabilities on the consolidated balance sheet as of December 31, 2025. Forfeitures are recognized as they occur.
The following table summarizes the activity of restricted stock units for the year ended December 31, 2025 (Successor):
| Successor | |||||||||||
| Weighted-average grant date fair value | |||||||||||
| Shares | |||||||||||
| Non-vested, beginning of the period | — | $ | — | ||||||||
| Granted | 10,478,765 | 20.34 | |||||||||
| Vested | — | — | |||||||||
| Forfeited | (13,200) | 21.19 | |||||||||
| Non-vested, end of the period | 10,465,565 | $ | 20.34 | ||||||||
As of December 31, 2025, unrecognized share based compensation expense to be recognized over the life of the restricted stock units consists of $175.5 million for the stock-settled restricted stock units and $2.7 million for the cash-settled restricted stock units. Such expense is to be recognized over the weighted average remaining life of 5.1 years and 2.3 years, respectively.
Other Stock Awards
In April 2025, the Compensation Committee approved an annual grant of 25,000 shares of Common Stock to each of the Company’s three non-employee directors as compensation for service on the Board. These Board stock awards had a weighted-average grant date fair value of $19.82 per share, resulting in $1.5 million in share based compensation expense, which was recognized during the year ended December 31, 2025 (Successor).
Merger Consideration
Pursuant to the Merger Agreement, on the Closing Date and contemporaneously with the completion of the transactions contemplated under the Sable-EM Purchase Agreement, as previously noted Holdco merged with and into Flame, with Flame as the surviving company, and immediately thereafter, Sable merged with and into Flame, with Flame as the surviving company. The aggregate consideration received by holders of limited liability company membership interests in Holdco designated as Class A shares immediately prior to the Holdco Merger Effective Time was 3,000,000 shares of Flame Class A Common Stock. Share based compensation expense of $36.3 million was recognized associated with the issuance of the 3,000,000 shares in General and administrative expenses on the consolidated statement of operations for the period from February 14, 2024 through December 31, 2024 (Successor). The Merger Consideration Shares are subject to a three-year lock-up provision.
Founders Shares
In the periods prior to the Business Combination, the Sponsor sold 434,375 Founder Shares to some of the Company’s directors and executives, including Gregory D. Patrinely, the Company’s Executive Vice President and Chief Financial Officer, at their original purchase price. Such sale of Founder Shares to the Company’s directors and executives is within the scope of FASB ASC Topic 718, Compensation-Stock Compensation (“ASC 718”). Under ASC 718, stock-based compensation associated with equity-classified awards is measured at fair value upon the grant date. The Founder Shares were sold to directors and executives and effectively transferred subject to a performance condition (i.e., the consummation of a Business Combination). Compensation expense related to the Founder Shares is recognized only when the
96
performance condition is probable of achievement under the applicable accounting literature. As such, the Company recognized $3.7 million in stock-based compensation expense upon the completion of the Business Combination, which is included in the General and administrative expenses on the consolidated statement of operations for the period from February 14, 2024 through December 31, 2024 (Successor).
Note 11 — Fair Value Measurements
Certain of the Company’s financial assets and liabilities are reported at fair value on the consolidated balance sheets. An established fair value hierarchy prioritizes the relative reliability of inputs used in fair value measurements. The hierarchy gives highest priority to Level 1 inputs that represent unadjusted quoted market prices in active markets for identical assets and liabilities that the reporting entity has the ability to access at the measurement date. Level 2 inputs are directly or indirectly observable inputs other than quoted prices included within Level 1. Level 3 inputs are unobservable inputs and have the lowest priority in the hierarchy.
Recurring Fair Value Measurements
The following tables present information about the Company’s assets and liabilities that are measured at fair value on a recurring basis, and indicates the fair value hierarchy of the valuation inputs the Company utilized to determine such fair value:
| As of December 31, 2025 | |||||||||||||||||||||||
| (in thousands) | Quoted Prices in Active Markets (Level 1) | Significant Other Observable Inputs (Level 2) | Significant Unobservable Inputs (Level 3) | Total | |||||||||||||||||||
| Liabilities: | |||||||||||||||||||||||
| Senior Secured Term Loan | $ | — | $ | 921,584 | $ | — | $ | 921,584 | |||||||||||||||
| Private Placement Warrants | — | — | 22,331 | 22,331 | |||||||||||||||||||
| Working Capital Warrants | — | — | 15,407 | 15,407 | |||||||||||||||||||
Restricted Stock Unit Liability(1) | — | 719 | — | 719 | |||||||||||||||||||
(1) As discussed in Note 10—Share Based Compensation, certain restricted stock units qualify for liability treatment and are remeasured at the end of each reporting period. | |||||||||||||||||||||||
| As of December 31, 2024 | |||||||||||||||||||||||
| (in thousands) | Quoted Prices in Active Markets (Level 1) | Significant Other Observable Inputs (Level 2) | Significant Unobservable Inputs (Level 3) | Total | |||||||||||||||||||
| Liabilities: | |||||||||||||||||||||||
| Senior Secured Term Loan | $ | — | $ | 833,542 | $ | — | $ | 833,542 | |||||||||||||||
| Private Placement Warrants | — | — | 79,263 | 79,263 | |||||||||||||||||||
| Working Capital Warrants | — | — | 47,678 | 47,678 | |||||||||||||||||||
The following table presents the changes in the fair value of the Level 3 Private Placement Warrants and Working Capital Warrants:
| (in thousands) | Private Placement Warrants (Level 3) | Working Capital Warrants (Level 3) | Total Fair Value Liabilities (Level 3) | ||||||||||||||
| Fair Value as of February 14, 2024 | $ | 19,813 | $ | — | $ | 19,813 | |||||||||||
| Additions | — | 10,283 | 10,283 | ||||||||||||||
| Transfer out of Level 3 | (21,054) | — | (21,054) | ||||||||||||||
| Liabilities removed due to warrant exercises | (4,214) | — | (4,214) | ||||||||||||||
| Change in valuation inputs or other assumptions | 84,718 | 37,395 | 122,113 | ||||||||||||||
| Fair Value as of December 31, 2024 | 79,263 | 47,678 | 126,941 | ||||||||||||||
| Change in valuation inputs or other assumptions | (56,932) | (32,271) | (89,203) | ||||||||||||||
| Fair Value as of December 31, 2025 | $ | 22,331 | $ | 15,407 | $ | 37,738 | |||||||||||
97
During the period from February 14, 2024 through December 31, 2024 (Successor), 1,609,564 Private Placement Warrants ceased to be held by the initial purchasers or their permitted transferees and therefore became redeemable by the Company and exercisable by the holders of such warrants on the same basis as the Public Warrants. As a result, $21.1 million was transferred out of Level 3 and into Level 1 in the fair value hierarchy during the period from February 14, 2024 through December 31, 2024 (Successor).
There were no other transfers in or out of Level 3 from other levels in the fair value hierarchy for the year ended December 31, 2025 (Successor) or for the period from February 14, 2024 through December 31, 2024 (Successor).
There were no financial assets or liabilities accounted for at fair value on a recurring basis in the Predecessor financial statements for the period from January 1, 2024 to February 13, 2024 (Predecessor) or for the year ended December 31, 2023 (Predecessor).
Fair Value of Financial Assets
The carrying amount of cash and cash equivalents, prepaid expenses and other current assets, accounts payable, and accrued liabilities approximate their fair value because of the short-term nature of the instruments.
Senior Secured Term Loan
As of December 31, 2025 and 2024, the estimated fair value of the Senior Secured Term Loan approximates the amount of principal and paid-in-kind interest outstanding because the interest rate is reflective of market rates and such outstanding amount may be repaid, in full or in part, at any time without penalty. The associated inputs are considered a Level 2 fair value measurement.
Warrant Liabilities
Prior to the Redemption, the Public Warrants were measured at the observable quoted price in active markets. Refer to Note 7—Warrants for details regarding the Warrant exercises and redemptions for the period from February 14, 2024 through December 31, 2024 (Successor). The estimated fair values of the Private Warrants and the Working Capital Warrants are measured using the Modified Black-Scholes Optional Pricing Model, which utilizes Level 3 inputs. Inherent in a binomial options pricing model are assumptions related to expected share-price volatility, expected life, risk-free interest rate and dividend yield. A change in these significant unobservable inputs to a different value could result in a significantly higher or lower fair value measurement at future reporting dates. The Company estimates the volatility of its Common Stock based on historical volatility that matches the expected remaining life of the warrants. The risk-free interest rate is based on the U.S. Treasury zero-coupon yield curve on the grant date for a maturity similar to the expected remaining life of the warrants. The expected life of the warrants is assumed to be equivalent to their remaining contractual term. The dividend rate is based on the historical rate, which the Company anticipates to remain at zero. The aforementioned warrant liabilities are not subject to qualified hedge accounting. Changes in the estimated fair value of the Private Placement Warrants and Working Capital Warrants are included in the Change in fair value of warrant liabilities on the Company’s consolidated statements of operations for the year ended December 31, 2025 (Successor), the period from February 14, 2024 through December 31, 2024 (Successor), the period January 1, 2024 through February 13, 2024 (Predecessor), and the year ended December 31, 2023 (Predecessor).
As Private Placement Warrants held by FL Co-Investment, LLC (“FL Co-Investment”) and Intrepid Financial Partners will not be exercisable more than five years from the effective date of the registration statement, the exercise period end date is different than other Private Placement Warrants and Working Capital Warrants which will expire five years after the Closing Date or earlier upon redemption or liquidation. Accordingly, they have different inputs to the Modified Black-Scholes Optional Pricing Model.
98
The following table provides quantitative information regarding Level 3 inputs used to determine the fair values of Private Placement Warrants held by Intrepid Financial Partners as of December 31, 2025.
| Inputs | December 31, 2025 | ||||
| Stock price | $ | 9.02 | |||
| Strike price | $ | 11.50 | |||
| Term (in years) | 0.15 | ||||
| Volatility | 180.0 | % | |||
| Risk-free rate | 3.64 | % | |||
| Dividend yield | 0.00 | % | |||
The following table provides quantitative information regarding Level 3 fair value measurements used to determine the fair value of the Working Capital Warrants and the Private Placement Warrants, excluding Private Placement Warrants held by Intrepid Financial Partners as of December 31, 2025.
| Inputs | December 31, 2025 | ||||
| Stock price | $ | 9.02 | |||
| Strike price | $ | 11.50 | |||
| Term (in years) | 3.12 | ||||
| Volatility | 85.0 | % | |||
| Risk-free rate | 3.50 | % | |||
| Dividend yield | 0.00 | % | |||
The following table provides quantitative information regarding Level 3 inputs used to determine the fair values of Private Placement Warrants held by Intrepid Financial Partners as of December 31, 2024.
| Inputs | December 31, 2024 | ||||
| Stock price | $ | 22.90 | |||
| Strike price | $ | 11.50 | |||
| Term (in years) | 1.15 | ||||
| Volatility | 60.0 | % | |||
| Risk-free rate | 4.09 | % | |||
| Dividend yield | 0.00 | % | |||
The following table provides quantitative information regarding Level 3 fair value measurements used to determine the fair value of the Working Capital Warrants and the Private Placement Warrants, excluding Private Placement Warrants held by Intrepid Financial Partners, as of December 31, 2024.
| Inputs | December 31, 2024 | ||||
| Stock price | $ | 22.90 | |||
| Strike price | $ | 11.50 | |||
| Term (in years) | 4.12 | ||||
| Volatility | 45.0 | % | |||
| Risk-free rate | 4.24 | % | |||
| Dividend yield | 0.00 | % | |||
99
Note 12 — Income Taxes
The Company follows the asset and liability method of accounting for income taxes under FASB ASC Topic 740, Income Taxes. Deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that included the enactment date. Valuation allowances are established, when necessary, to reduce deferred tax assets to the amount expected to be realized. After consideration of all of the information available, management believes that significant uncertainty exists with respect to future realization of the deferred tax assets and has therefore established a valuation allowance. Income taxes were not allocated to the Predecessor as the seller did not file a consolidated tax return and was not a taxable legal entity.
The components of the deferred income taxes were as follows:
| December 31, | |||||||||||
| (in thousands) | 2025 | 2024 | |||||||||
| Deferred tax assets | |||||||||||
| Net operating loss | $ | 216,910 | $ | 48,155 | |||||||
| Net oil & gas acquisition, exploration and development costs | — | 17,800 | |||||||||
| Stock based compensation | 4,207 | 5,221 | |||||||||
| Start up costs & other | 9,622 | 6,036 | |||||||||
| Accruals and other | 9,794 | — | |||||||||
| Total deferred tax assets | 240,533 | 77,212 | |||||||||
| Valuation allowance | (209,363) | (76,327) | |||||||||
| Deferred tax assets, net of allowance | 31,170 | 885 | |||||||||
| Deferred Tax Liabilities | |||||||||||
| Net oil & gas acquisition, exploration and development costs | 39,137 | — | |||||||||
| Other property | 4,866 | 2,047 | |||||||||
| Total deferred tax liabilities | 44,003 | 2,047 | |||||||||
| Net deferred tax liabilities | $ | 12,833 | $ | 1,162 | |||||||
The components of the Company’s income tax expense (benefit) were as follows:
| Successor | |||||||||||
| (in thousands) | Year Ended December 31, 2025 | February 14—December 31, 2024 | |||||||||
| Current: | |||||||||||
| Federal | $ | — | $ | — | |||||||
| State | — | — | |||||||||
| Deferred: | |||||||||||
| Federal | (102,529) | (62,730) | |||||||||
State1 | 267 | (99) | |||||||||
| Change in valuation allowance | 113,933 | 62,781 | |||||||||
| Income tax expense (benefit) | $ | 11,671 | $ | (48) | |||||||
1Net of federal benefit and state valuation allowance. | |||||||||||
As a result of the implementation of the One Big Beautiful Bill Act (OBBBA) enacted in July 2025, we recorded a $5.8 million charge in the third quarter of 2025, which was a valuation allowance against our U.S. federal deferred tax assets as of the enactment date of OBBBA.
As of December 31, 2025, the Company had $913.7 million U.S. federal net operating loss carryovers available to offset future taxable income. The Company had $359.7 million of California net operating loss carryovers available to offset future taxable income beginning in 2027 and are subject to expiration in 2047. Under the Tax Cuts and Jobs Act (“TCJA”), federal NOLs generated after 2017 will be carried forward indefinitely but are limited to an 80% deduction of taxable income. In June 2024, California’s Governor signed into law AB 167 suspending California NOL utilization for taxpayers
100
with more than $1 million of taxable income, effective for tax years 2024, 2025, and 2026. AB 167 includes an extended carryover period for suspended net operating losses (“NOL”) that would have been utilized if not for AB 167.
The Company’s ability to utilize its NOL carryforwards may be substantially limited due to ownership changes that have occurred or that could occur in the future, as required by Section 382 of the Internal Revenue Code of 1986, as amended (the Code), as well as similar state provisions. These ownership changes may limit the amount of NOL carryforwards that can be utilized annually to offset future taxable income and tax, respectively. In general, an “ownership change,” as defined by Section 382 of the Code, results from a transaction or series of transactions over a three-year period resulting in an ownership change of more than 50 percent of the outstanding stock of a company by certain stockholders or public groups.
During the course of preparing the Company’s consolidated financial statements, as of and for the year ended December 31, 2025, the Company completed a preliminary assessment of the available NOL carryforwards under Section 382 of the Code. The Company determined that in September of 2024, we had a Section 382 owner shift. As such, $143.1 million of U.S. federal net operating loss carryovers and $72.3 million of California net operating loss carryovers will be subject to an annual limitation of approximately $53.9 million.
A reconciliation of the federal income tax rate to the Company’s effective tax rate for the periods presented is as follows:
There were no foreign tax effects, impact from cross-border tax laws, tax credits, or unrecognized tax benefits as of December 31, 2025 or December 31, 2024. Interest and penalties for the years ended December 31, 2025 and 2024, were not material. The Company is currently not aware of any issues under review that could result in significant payments, accruals or material deviation from its position. The Company files income tax returns in the U.S. federal and state of California, Texas and Louisiana jurisdictions. The Company is not currently under examination in any jurisdiction. The Company’s tax returns for the years ended December 31, 2025, 2024, 2023 and 2022, remain open and subject to examination. The Company paid no cash income taxes during the years ended December 31, 2025 and 2024.
Note 13 — Leases
Right-of-use assets and lease liabilities are established on the consolidated balance sheet for leases with an expected term greater than one year by discounting the amounts fixed in the lease agreement for the duration of the lease which is reasonably certain, considering the probability of exercising any early termination and extension options. Generally, assets are leased only for a portion of their useful lives and are accounted for as operating leases. Our leased assets primarily consist of office space and additionally include facilities, land sites, vessels, and equipment used in the operation of the SYU Assets. All of our leases are classified as operating leases.
101
The following table shows the classification and location of our right-of-use assets and lease liabilities on our consolidated balance sheets:
| December 31, | |||||||||||||||||
| (in thousands) | Consolidated Balance Sheets Location | 2025 | 2024 | ||||||||||||||
| Other, net | $ | 16,060 | $ | 17,239 | |||||||||||||
| Total right-of-use assets | $ | 16,060 | $ | 17,239 | |||||||||||||
| Other current liabilities | $ | 1,770 | $ | 918 | |||||||||||||
| Other | 19,341 | 16,988 | |||||||||||||||
| Total lease liabilities | $ | 21,111 | $ | 17,906 | |||||||||||||
The lease costs are classified by the function of the right-of-use asset. Our short term lease costs related to exploration and development activities are initially included in the Oil and gas properties line on the consolidated balance sheets and subsequently accounted for in accordance with the ASC 932. The remaining lease costs are included in our consolidated statements of operations as either Operations and maintenance expenses or General and administrative expenses based on the function of the right-of-use asset.
The following table shows the classification and location of our lease costs on our consolidated statements of operations:
| Successor | Predecessor | |||||||||||||||||||||||||
| (in thousands) | Year Ended December 31, 2025 | February 14—December 31, 2024 | January 1—February 13, 2024 | Year Ended December 31, 2023 | ||||||||||||||||||||||
| Operating lease costs | $ | 3,580 | $ | 2,081 | $ | 173 | $ | 1,187 | ||||||||||||||||||
| Variable lease costs | 366 | 121 | — | — | ||||||||||||||||||||||
| Short-term lease costs | 8,142 | 2,543 | — | — | ||||||||||||||||||||||
| Total lease costs | $ | 12,088 | $ | 4,745 | $ | 173 | $ | 1,187 | ||||||||||||||||||
The following table shows the weighted-average remaining lease term and weighted-average discount rate for our operating leases:
| December 31, | ||||||||||||||
| 2025 | 2024 | |||||||||||||
| Weighted-average remaining lease term (years) | 13.7 | 14.1 | ||||||||||||
| Weighted-average discount rate (percent) | 10.4 | % | 10.3 | % | ||||||||||
Future annual minimum lease payments for operating leases as of December 31, 2025, are as follows (in thousands):
| Years Ending December 31, | Operating Leases | ||||
| 2026 | $ | 2,222 | |||
| 2027 | 3,489 | ||||
| 2028 | 1,676 | ||||
| 2029 | 2,611 | ||||
| 2030 | 3,260 | ||||
| Thereafter | 31,094 | ||||
| Total lease payments | 44,352 | ||||
| Less: discount to present value | (23,241) | ||||
| Present value of lease liabilities | $ | 21,111 | |||
102
The Company has generated sublease income from facilities for which it acts as lessor. Variable lease costs represent costs incurred above the contractual minimum payments. The following table includes other quantitative information for our operating leases:
Note 14 — Supplemental Cash Flow Information
The following table provides supplemental disclosure of substantive cash flow information:
| Successor | Predecessor | |||||||||||||||||||||||||
| (in thousands) | Year Ended December 31, 2025 | February 14—December 31, 2024 | January 1—February 13, 2024 | Year Ended December 31, 2023 | ||||||||||||||||||||||
| Assets and Liabilities resulting from Business Combination: | ||||||||||||||||||||||||||
| Senior Secured Term Loan, including paid-in-kind interest | $ | — | $ | 765,018 | $ | — | $ | — | ||||||||||||||||||
| Supplies and materials | — | 16,637 | — | — | ||||||||||||||||||||||
| Accrued liabilities | — | 129 | — | — | ||||||||||||||||||||||
| Deferred tax liability | — | 1,209 | — | — | ||||||||||||||||||||||
| Asset retirement obligation assumed | — | 90,073 | — | — | ||||||||||||||||||||||
| Right-of-use assets obtained in exchange for operating lease liabilities | — | 4,621 | — | — | ||||||||||||||||||||||
| Change in capital expenditures included in accounts payable and accrued liabilities | 33,435 | 62,384 | — | — | ||||||||||||||||||||||
| Accrued equity issuance costs | 12,918 | — | — | — | ||||||||||||||||||||||
| Capitalization of depletion to Inventory | 5,977 | — | — | — | ||||||||||||||||||||||
| Asset retirement obligation revisions | 1,436 | — | — | — | ||||||||||||||||||||||
| Right-of-use assets obtained in exchange for operating lease liabilities | 420 | 13,689 | — | — | ||||||||||||||||||||||
| Warrant liability removed upon exercise | — | 170,571 | — | — | ||||||||||||||||||||||
| Acquisition of transportation assets | — | 15,234 | — | — | ||||||||||||||||||||||
Note 15 — Subsequent Events
The Company evaluated subsequent events and transactions that occurred after the consolidated balance sheet date up to the date that the consolidated financial statements were issued. Based upon this review, the Company, other than as previously described herein, did not identify any subsequent events that would have required adjustment or disclosure in the financial statements.
On February 2, 2026, the Company established an “at-the-market” equity offering program pursuant to a sales agreement with TD Securities (USA) LLC and Jefferies LLC (collectively, the “Sales Agents”) under which the Company may offer and sell, at its discretion, shares of its Common Stock from time to time. The aggregate offering size under the program is up to $250.0 million of Common Stock, and any sales completed by the Sales Agents thereunder will be made pursuant to the Company’s effective shelf registration statement on Form S-3 and an accompanying prospectus supplement. The Company expects to use the net proceeds from any sales under the program for general corporate purposes, and restart-related capital expenditures.
103
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
None.
Item 9A. Controls and Procedures.
Evaluation of Disclosure Controls and Procedures
Disclosure controls are procedures that are designed with the objective of ensuring that information required to be disclosed in our reports filed under the Exchange Act is recorded, processed, summarized, and reported within the time period specified in the SEC’s rules and forms. Disclosure controls are also designed with the objective of ensuring that such information is accumulated and communicated to our management, including the chief executive officer and chief financial officer, as appropriate to allow timely decisions regarding required disclosure.
As required by Rules 13a-15 and 15d-15 under the Exchange Act, our Chief Executive Officer and Chief Financial Officer carried out an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures as of December 31, 2025. Based upon their evaluation, our Chief Executive Officer and Chief Financial Officer concluded that, as of December 31, 2025, our disclosure controls and procedures (as defined in Rules 13a-15 (e) and 15d-15 (e) under the Exchange Act) were effective as of December 31, 2025. Accordingly, management believes that the financial statements included in this Annual Report on Form 10-K present fairly in all material respects our financial position, results of operations and cash flows for the periods presented.
Management’s Report on Internal Control Over Financial Reporting
Reports of Management
Management prepared, and is responsible for, the consolidated financial statements and the other information appearing in this annual report. The consolidated financial statements present fairly the company’s financial position, results of operations and cash flows in conformity with accounting principles generally accepted in the United States. In preparing its consolidated financial statements, the company includes amounts that are based on estimates and judgments management believes are reasonable under the circumstances. The company’s financial statements have been audited by Ham, Langston & Brezina, L.L.P., an independent registered public accounting firm appointed by the Audit Committee of the Board of Directors and ratified by stockholders. Management has made available to Ham, Langston & Brezina, L.L.P. all of the company’s financial records and related data, as well as the minutes of stockholders’ and directors’ meetings.
Assessment of Internal Control Over Financial Reporting
The management of our Company is also responsible for establishing and maintaining adequate internal control over financial reporting. The Company’s internal control over financial reporting is a process designed under the supervision of the Company’s Chief Executive Officer and Chief Financial Officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the Company’s financial statements for external purposes in accordance with generally accepted accounting principles in the United States.
All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.
Management assessed the effectiveness of the company’s internal control over financial reporting as of December 31, 2025. In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control—Integrated Framework (2013). Based on this assessment, management concluded that the company’s internal control over financial reporting was effective at the reasonable assurance level as of December 31, 2025.
Ham, Langston & Brezina, L.L.P. has issued an audit report on the company’s internal control over financial reporting as of December 31, 2025, and their report is included herein.
Attestation Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting
The attestation report of the independent registered public accounting firm, Ham, Langston & Brezina, L.L.P., on the Company’s internal control over financial reporting is included below under the heading “Report of Independent Registered Public Accounting Firm.”
104
Changes in Internal Control over Financial Reporting
There were no changes in our internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act) during the most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Stockholders and the Board of Directors of Sable Offshore Corp.
Opinion on Internal Control Over Financial Reporting
We have audited the internal control over financial reporting of Sable Offshore Corp. (the “Company”) as of December 31, 2025, based on criteria established in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2025, based on criteria established in the 2013 Internal Control—Integrated Framework issued by COSO.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated financial statements of the Company as of and for the year ended December 31, 2025, and our report dated February 27, 2026 expressed an unqualified opinion on those financial statements.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting in the accompanying Management’s Report on Internal Control Over Financial Reporting (“Management’s Report”). Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control Over Financial Reporting
A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ Ham, Langston & Brezina, L.L.P.
Houston, Texas
February 27, 2026
105
Item 9B. Other Information
During the twelve months ended December 31, 2025, no director or officer of the Company adopted or terminated a “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement,” as each term is defined in Item 408(a) of Regulation S-K.
Item 9C. Disclosures Regarding Foreign Jurisdictions that Prevent Inspections
Not applicable.
PART III
Item 10. Directors, Executive Officers and Corporate Governance
Except as set forth below, the information required by this item is incorporated by reference to our Proxy Statement for the 2026 Annual Meeting of Stockholders, which will be filed within 120 days of our fiscal year ended December 31, 2025.
Information about our Executive Officers
The following chart names each of the Company’s executive officers and their ages and positions at February 27, 2026. Also included below is biographical information relating to each of the Company’s executive officers. Each of the executive officers is elected by and serves at the pleasure of the board of directors.
Name | Age | Position | ||||||||||||
| James C. Flores | 66 | Chairman and Chief Executive Officer | ||||||||||||
| J. Caldwell Flores | 33 | President and Chief Operating Officer | ||||||||||||
| Gregory D. Patrinely | 40 | Executive Vice President and Chief Financial Officer | ||||||||||||
| Anthony C. Duenner | 66 | Executive Vice President, General Counsel and Secretary | ||||||||||||
James C. Flores, 66, has been our Chairman and Chief Executive officer since February 2024. Prior to that, Mr. Flores served as Flame’s co-founder, Chief Executive officer and Chairman of its board of directors from its inception to February 2024. From its inception to March 3, 2023, he also served as Flame’s President. From May 2017 until February 2021, Mr. Flores served as President, Chief Executive Officer and Chairman of Sable Permian Resources, which engaged in the acquisition, consolidation and optimization of oil and gas upstream opportunities. Sable Permian Resources filed a voluntary petition for bankruptcy on June 25, 2020 and emerged from bankruptcy on February 1, 2021. Prior to Sable Permian Resources, Mr. Flores served as Vice Chairman of Freeport-McMoRan, Inc. and CEO of Freeport-McMoRan Oil & Gas, a wholly owned subsidiary of Freeport-McMoRan Inc., the world’s largest publicly traded copper producer, from June 2013 until April 2016. From 2001 until 2013, Mr. Flores was the Chairman, CEO and President of Plains Exploration & Production Company and Chairman and CEO of Plains Resources Inc. From 1994 until 2000, Mr. Flores was also the Chairman and CEO of Flores & Rucks, Inc. which, after several acquisitions, was later renamed Ocean Energy Inc. prior to its sale to Devon Energy Corporation. Since 1982, Mr. Flores has had an extensive career in the oil and gas industry in the roles of Chairman, Chief Executive Officer, and President of four public and one private oil & gas exploration and production companies. He is a member of the National Petroleum Council, serves as Trustee for the Baylor College of Medicine and is a Director for the Waterfowl Research Foundation. He was recognized as Executive of the Year in 2004 in Oil and Gas Investor magazine. Mr. Flores received a B.S. degree in corporate finance and petroleum land management from Louisiana State University. We believe Mr. Flores is qualified to serve on our board of directors due to his more than 35 years in the oil and gas industry, including as Chief Executive Officer of several public companies. Mr. Flores is the father of J. Caldwell Flores, who is the President and Chief Operating Officer of Sable.
J. Caldwell Flores, 33, has served as President and Chief Operating Officer of Sable Offshore Corp. since November 2025 after previously serving as President starting in March 2023. Prior to that, Mr. Flores served as Flame’s President from March 2023 to February 2024. Previously, he served as Flame’s Vice President from March 1, 2021 to March 3, 2023. Mr. Flores has also served as President of Sable Offshore Corp. since September 2021 and as President of Sable Minerals, Inc., a Houston-based private oil and gas company, overseeing the daily operations and administration, as well as providing investment analysis for the firm since January 2015. Prior to assuming the role of President of Sable Minerals, Inc., Mr. Flores was a Senior Associate for Sable Permian Resources, LLC, which engaged in the acquisition, consolidation and optimization of oil and gas upstream opportunities from February 2018 until February 2021. Prior to that time, Mr. Flores served as Operations Manager for Sable Minerals, Inc. from 2015 through 2017. Mr. Flores attended the University of
106
Houston where he graduated with a Bachelor of Science in Business Administration. Mr. Flores is the son of James C. Flores, who is the Chairman and Chief Executive Officer of Sable.
Gregory D. Patrinely, 40, has been our Executive Vice President and Chief Financial Officer since February 2024. Prior to that, Mr. Patrinely served as Flame’s Chief Financial Officer from its inception to February 2024. Since March 3, 2023, he has also served as Flame’s Executive Vice President. From its inception to March 3, 2023, he also served as Flame’s Secretary. From June 2018 until February 2021, Mr. Patrinely served as Executive Vice President and Chief Financial Officer of Sable Permian Resources, which engaged in the acquisition, consolidation and optimization of oil and gas upstream opportunities. Sable Permian Resources filed a voluntary petition for bankruptcy on June 25, 2020 and emerged from bankruptcy on February 1, 2021.
Mr. Patrinely previously served as Treasurer for Sable Permian Resources, from May 2017 to June 2018, where he oversaw the financial analysis and execution of refinancing, restructuring and acquisition efforts. Prior to Sable Permian Resources, Mr. Patrinely was a Manager in the Acquisitions & Divestments Group of Freeport-McMoRan Oil & Gas from May 2015 to May 2017 following the Freeport-McMoRan merger with Plains Exploration & Production Company. Mr. Patrinely served in the same capacity with Plains Exploration & Production Company. During his tenure at Freeport-McMoRan Oil & Gas and Plains Exploration & Production Company, Mr. Patrinely managed the execution of financings, mergers, acquisitions and divestments. Prior to his service with PXP, Mr. Patrinely worked in the Energy Investment Banking group at Madison Williams. Mr. Patrinely holds a B.S. degree in Economics with Financial Applications and a B.A. degree in English, with Honors, from Southern Methodist University.
Anthony C. Duenner, 66, has been our Executive Vice President, General Counsel and Secretary since February 2024. Prior to that, he served as Flame’s Executive Vice President, General Counsel and Secretary from March 3, 2023 to February 2024. Previously, he served as Flame’s Vice President from March 1, 2021 to March 3, 2023. Mr. Duenner has also served as Executive Vice President, General Counsel & Secretary of Sable Offshore Corp. since September 2021. Mr. Duenner has over 35 years of diverse legal and commercial energy experience. From May 2017 until February 2021, Mr. Duenner served as Vice President, Corporate Development of Sable Permian Resources, LLC, which engaged in the acquisition, consolidation and optimization of oil and gas upstream opportunities. Prior to Sable Permian Resources, LLC, from June 2013 to April 2017, Mr. Duenner was Vice President—International & New Ventures for Freeport-McMoRan Oil & Gas (“FM O&G”), a wholly owned subsidiary of Freeport-McMoRan Inc., where he had responsibility for the company’s international commercial activities as well as new ventures and partnerships. He previously served as Vice President – International & New Ventures of FM O&G’s predecessor, Plains Exploration & Production Company (“PXP”) from May 2005 until PXP merged into Freeport-McMoRan in May 2013. While with PXP, Mr. Duenner also served as the company’s Assistant General Counsel from May 2005 until November 2007.
Prior to that time, Mr. Duenner was Vice President, Corporate Development for integrated energy company Entergy Corp., where he led corporate development activities for Entergy and its subsidiaries from 2004 to 2005. Prior to Entergy, from 1998 to 2004, Mr. Duenner served in various project development and wholesale origination functions within Enron International and its successor Prisma Energy International. Previously, Mr. Duenner was in the private practice of law with Bracewell LLP in Houston (Partner from 1994 to 1997 and Associate from 1988 to 1994) and with Morgan Lewis in Washington, D.C. (Associate from 1986 to 1988). Mr. Duenner attended the University of Oklahoma and received a Bachelor of Science in Finance and a Juris Doctor degree from the University of Tulsa.
Code of Ethics
We have adopted a Code of Business Conduct and Ethics that applies to our directors, officers and employees. Any amendments to or waivers from the code of business conduct and ethics will be disclosed on our website. The Company has made the Code of Business Conduct and Ethics available on our website under the “Governance—Governance Documents” section at www.sableoffshore.com. We will make any legally required disclosures regarding amendments to, or waivers of, provisions of our code of ethics on our website.
Insider Trading Policy
We have adopted an Insider Trading Policy that governs the purchase, sale, and/or other dispositions of our securities by directors, officers and employees that is reasonably designed to promote compliance with insider trading laws, rules and regulations, and the listing requirements of the New York Stock Exchange. A copy of our Insider Trading Policy is filed as Exhibit 19.1 to this Annual Report on Form 10-K.
107
Item 11. Executive Compensation
The information required by this item is incorporated by reference to our Proxy Statement for the 2026 Annual Meeting of Stockholders, which will be filed within 120 days of our fiscal year ended December 31, 2025.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
The information required by this item is incorporated by reference to our Proxy Statement for the 2026 Annual Meeting of Stockholders, which will be filed within 120 days of our fiscal year ended December 31, 2025.
Item 13. Certain Relationships and Related Transactions, and Director Independence
The information required by this item is incorporated by reference to our Proxy Statement for the 2026 Annual Meeting of Stockholders, which will be filed within 120 days of our fiscal year ended December 31, 2025.
Item 14. Principal Accountant Fees and Services.
The information required by this item is incorporated by reference to our Proxy Statement for the 2026 Annual Meeting of Stockholders, which will be filed within 120 days of our fiscal year ended December 31, 2025.
108
PART IV
Item 15. Exhibits, Financial Statements and Financial Statement Schedules
(a) The following documents are filed as part of this annual report:
(1)Financial Statements
(2)Financial Statement Schedules: All financial statement schedules have been omitted because they are not applicable, not required or the information required is shown in the financial statements or the notes thereto.
(3)Exhibits
We hereby file as part of this annual report the exhibits listed in the attached Exhibit Index. Exhibits which are incorporated herein by reference can be obtained on the SEC website at www.sec.gov.
(b) The following exhibits are filed as part of, or incorporated by reference into, this Annual Report on Form 10-K.
| Incorporate by Reference | |||||||||||||||||||||||
| Filing | |||||||||||||||||||||||
| No. | Description of Exhibit | Form | Exhibit | Date | |||||||||||||||||||
| 2.1† | 8-K | 2.1 | 2/14/24 | ||||||||||||||||||||
| 2.1 | 8-K | 3.1 | 2/14/24 | ||||||||||||||||||||
| 3.2 | 8-K | 3.2 | 2/14/24 | ||||||||||||||||||||
| 4.1 | S-1 | 4.2 | 7/2/20 | ||||||||||||||||||||
| 4.2 | S-1 | 4.3 | 7/2/20 | ||||||||||||||||||||
| 4.3 | 8-K | 4.1 | 3/2/21 | ||||||||||||||||||||
| 4.4 | 10-K | 4.4 | 3/28/24 | ||||||||||||||||||||
| 10.1 | 8-K | 10.1 | 9/24/24 | ||||||||||||||||||||
| 10.2 | 8-K | 10.33 | 2/14/24 | ||||||||||||||||||||
| 10.3 | 10-Q | 10.1 | 11/13/25 | ||||||||||||||||||||
| 10.4 | 8-K | 10.32 | 2/14/24 | ||||||||||||||||||||
| 10.5^ | 8-K | 10.1 | 2/14/24 | ||||||||||||||||||||
| 10.6 | 10-Q | 10.1 | 11/14/24 | ||||||||||||||||||||
| 10.7 | 8-K | 99.1 | 11/25/25 | ||||||||||||||||||||
| 10.8 | 8-K | 10.31 | 2/14/24 | ||||||||||||||||||||
| 10.9^ | 8-K | 10.27 | 2/14/24 | ||||||||||||||||||||
109
| 10.10 | 10-K | 10.11 | 2/14/24 | ||||||||||||||||||||
| 10.11 | 10-K | 10.12 | 2/14/24 | ||||||||||||||||||||
| 10.12# | 10-K | 10.39 | 2/14/24 | ||||||||||||||||||||
| 10.13# | 10-K | 10.40 | 2/14/24 | ||||||||||||||||||||
| 10.14# | 10-K | 10.41 | 2/14/24 | ||||||||||||||||||||
| 10.15# | 10-K | 10.42 | 2/14/24 | ||||||||||||||||||||
| 10.16# | 10-K | 10.43 | 2/14/24 | ||||||||||||||||||||
| 19.1 | 10-K | 19.1 | 2/14/24 | ||||||||||||||||||||
| 21.1* | — | — | — | ||||||||||||||||||||
| 23.1* | — | — | — | ||||||||||||||||||||
| 31.1* | — | — | — | ||||||||||||||||||||
| 31.2* | — | — | — | ||||||||||||||||||||
| 32.1** | — | — | — | ||||||||||||||||||||
| 32.2** | — | — | — | ||||||||||||||||||||
| 97.1 | 10-K | 97.1 | 3/28/24 | ||||||||||||||||||||
| 101.INS* | XBRL Instance Document—the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document | ||||||||||||||||||||||
| 101.CAL* | Inline XBRL Taxonomy Extension Calculation Linkbase Document | ||||||||||||||||||||||
| 101.SCH* | Inline XBRL Taxonomy Extension Schema Document | ||||||||||||||||||||||
| 101.DEF* | Inline XBRL Taxonomy Extension Definition Linkbase Document | ||||||||||||||||||||||
| 101.LAB* | Inline XBRL Taxonomy Extension Labels Linkbase Document | ||||||||||||||||||||||
| 101.PRE* | Inline XBRL Taxonomy Extension Presentation Linkbase Document | ||||||||||||||||||||||
110
| 104* | Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101) | ||||||||||||||||||||||
| * | Filed herewith. | ||||
| ** | Furnished | ||||
| # | Indicates a management contract or compensatory plan. | ||||
| † | Certain exhibits and schedules to this Exhibit have been omitted in accordance with Regulation S-K Item 601(b)(2). The Registrant agrees to furnish supplementally a copy of all omitted exhibits and schedules to the Securities and Exchange Commission upon its request. | ||||
| ^ | Certain portions of this exhibit (indicated by “[***]”) have been omitted pursuant to Regulation S-K, Item 601(b)(10). | ||||
111
Item 16. Form 10-K Summary
None.
112
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
| SABLE OFFSHORE CORP. | ||||||||
Date: February 27, 2026 | By: | /s/ James C. Flores | ||||||
| Name: | James C. Flores | |||||||
| Title: | Chairman and Chief Executive Officer (Principal Executive Officer) | |||||||
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
| Name | Position | Date | ||||||||||||
| /s/ James C. Flores | Chairman and Chief Executive Officer (Principal Executive Officer) | February 27, 2026 | ||||||||||||
James C. Flores | ||||||||||||||
| /s/ Gregory D. Patrinely | Executive Vice President and Chief Financial Officer (Principal Financial and Accounting Officer) | February 27, 2026 | ||||||||||||
Gregory D. Patrinely | ||||||||||||||
| /s/ Michael E. Dillard | Director | February 27, 2026 | ||||||||||||
Michael E. Dillard | ||||||||||||||
| /s/ Gregory P. Pipkin | Director | February 27, 2026 | ||||||||||||
Gregory P. Pipkin | ||||||||||||||
| /s/ Christopher B. Sarofim | Director | February 27, 2026 | ||||||||||||
Christopher B. Sarofim | ||||||||||||||
113