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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.

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. ☐

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 $550.0 million as of June 28, 2024 (based on the closing stock price of such stock as quoted on the New York Stock Exchange).

As of March 14, 2025 there were 89,413,358 shares of Common Stock, $0.0001 par value, issued and outstanding.

Portions of Sable Offshore Corp.’s Proxy Statement for the 2025 Annual Meeting of Stockholders are incorporated by reference in

Part III of this Form 10-K.

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 maintain the listing of our Common Stock on the NYSE;

•our ability to recommence production of the SYU Assets 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, 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 comply with laws and regulations applicable to our business;

•changes in applicable laws or regulations; or

•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, 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.

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 (as 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”).

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 SYU. SYU consists of three offshore platforms and a wholly owned onshore processing facility located along the Gaviota Coast at Las Flores Canyon in Santa Barbara County, California. SYU’s onshore facilities and the three offshore platforms remained in continuous operation until 2015. In May 2015, a Plains Pipeline that transported produced oil from SYU experienced a leak, as further described below under “—Pipeline 901 Incident.” The SYU platforms and facilities suspended production after the Line 901 incident, the SYU Assets were shut in and the facilities were placed in a safe state. The facilities are not currently producing oil and gas; however, all equipment remains in place in an operation-ready state, requiring ongoing inspections, maintenance and surveillance. As part of these suspension efforts, all SYU equipment was drained, flushed and purged in 2016. All hydrocarbon pipelines within SYU have been placed in a safe state and remain under regular monitoring. In 2020, Plains entered into a Consent Decree, described further below under “—Pipeline 901 Incident,” that provides a path for a potential restart of the pipelines.

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, the Company has invested significant capital to safely restore production operations to SYU. Sable began hydrotesting the Pipeline in early 2025 in advance of a potential restart of production from the Santa Ynez Unit offshore platforms and the associated Las Flores Canyon processing facilities in the second quarter of 2025.

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) “PPC” refers to Pacific Pipeline Company, a Delaware corporation, the equity of which was transferred from MPPC to Sable on the Closing Date pursuant to the Sable-EM Purchase Agreement, and (iv) the “Pipelines” are to Pipeline Segments 324/325 (formally known as Pipeline Segments 901/903) and the other “324/325 Assets” (formally known as "901/903 Assets" and as defined in the Sable-EM Purchase Agreement).

SYU Assets are comprised of three platforms located in federal waters offshore California and an onshore processing facility and pipeline 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).

The wholly owned onshore processing facility is a fully integrated oil and gas processing facility with additional capacity for development. The natural gas and natural gas liquids (“NGLs”) it processed prior to the Line 901 incident were sold into the Southern California markets and the oil volumes were sold to California refineries. 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;

•POPCO gas plant with approximately 80 MMcf/d sales capacity where it conducts gas sweetening, sulfur recovery, NGL fractionation, and gas compression;

•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.

Sable also acquired the Pipelines in the Business Combination, which were owned and operated by Plains and were acquired by EM on October 13, 2022. The Pipelines were used to deliver oil to local refinery markets. Following the crude oil release described further below, Plains indicated it shut down the pipeline, initiated its emergency response plan, and the Pipelines were subsequently emptied and placed in a safe state.

Line 324 (formerly known as Line 901) 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. Line 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 Louis Obispo, California.

On October 30, 2024, the Santa Barbara County Planning Commission (“Planning Commission”) approved the Company’s application for Change of Owner, Operator, and Guarantor for the Final Development Plan permits for the SYU, Pacific Offshore Pipeline Company Gas Plant, and the Pipelines. On November 5, 2024 and November 7, 2024, appeals of the Planning Commission’s October 30, 2024 approval of the permit transfers were filed. On February 25, 2025, the Santa Barbara County Board of Supervisors heard the appeals and voted 2-2 to uphold the appeals and 2-2 to deny the appeals, thus taking no action. Sable understands this to mean that the Planning Commission’s approval of the application stands, and has sought confirmation of the same understanding from Santa Barbara County.

Between 1981 and 2014, 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 platforms and facilities suspended production, the SYU Assets were shut in and the facilities were placed in a safe state as described below under “ —Pipeline 901 Incident.”

The estimated quantities of petroleum contained in the SYU Assets are classified as “contingent resources” as of December 31, 2024 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 from and/or inspection by federal, state and local regulators to restart production, (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 maybe 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, 2024 meet the requirements for disclosure as reserves pursuant to the guidelines published by the SEC in Rule 4-10(a) of Regulation S-X.

In May 2015, Plains All American Pipeline, L.P. (“Plains”) experienced a crude oil release from the Las Flores to Gaviota Pipeline (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 shut down the pipeline 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 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 potentially restarting Line 901 and the Sisquoc to Pentland portion of Line 903.

On October 13, 2022, Plains sold Line 901 and the Sisquoc to Pentland portion of Line 903 to 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 Line 901 and the Sisquoc to Pentland portion of Line 903.

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.

Restarting Lines 324 and 325 requires certain regulatory approvals and other actions, such as pipeline repair and maintenance activities, that may implicate federal, state, and local regulations.

Pursuant to Assembly Bill (“AB”) 864, the Office of the State Fire Marshall (“OSFM”) promulgated Coastal Best Available Technologies (“CBAT”) regulations that mandates the use of the best available technology for pipelines in environmentally sensitive coastal areas to minimize oil spills. In adhering to CBAT regulations, operators are required to submit a risk analysis to the OSFM for approval. If an operator identifies the best available technology to mitigate the quantity of hazardous liquid spills in case of a release, it must specify these technologies and propose their retrofitting into the pipeline. Following the installation of these technologies, the OSFM will review the operator's records to confirm compliance with CBAT regulations. On July 13, 2022, OSFM accepted the AB 864 Risk Analysis and Initial and Supplemental Implementation Plans submitted by PPC’s predecessor in April 2021 (the “2021 CBAT Plan”). On July 20, 2024, the OSFM stated that the 2021 CBAT Plan remains in effect and complies with AB-864, representing the best available technology.

On September 4, 2024, Santa Barbara County (the “County”) acknowledged that it does not have permit authority or jurisdiction over PPC’s installation of sixteen new safety valves in the County along the Pipelines in accordance with the 2021 CBAT Plan. The County’s acknowledgement was delivered pursuant to a conditional settlement agreement dated August 30, 2024 (the “Safety Valve Settlement Agreement”), among the County, PPC and the Company.

Pursuant to the Safety Valve Settlement Agreement, PPC agreed to the following additional surveillance and

response enhancements in the County:

i.PPC will create a Santa Barbara County-based Surveillance and Response Team, trained to comply with PPC’s tactical response plan, which will be responsible for timely initial incident response and equipped with key resources to deploy in early containment, particularly for those regions of the Pipeline between Gaviota and Las Flores Canyon;

ii.PPC will provide Santa Barbara first responders with additional training and equipment to assist in PPC’s incident response efforts; and

iii.PPC will undertake the following Pipeline system enhancements: (1) install and operate and maintain primary and secondary operations control centers in Santa Barbara County, and (2) refurbish the Gaviota pump in its existing station.

PPC, the Company and the County further agreed, in the Safety Valve Settlement Agreement, to file a stipulation to dismiss the pending lawsuit, Pacific Pipeline Company and Sable Offshore Corp. v. Santa Barbara County Planning Commission and Board of Supervisors (Case No. 2:23-cv-09218-DMG-MRW) within 15 days of final installation of all sixteen underground safety valves in the County.

Sable subsequently installed each of the sixteen required valves. Pursuant to the Safety Valve Settlement Agreement, Pacific Pipeline Company and Sable Offshore Corp. v. Santa Barbara County Planning Commission and Board of Supervisors was voluntarily dismissed on December 9, 2024.

Refer to Pipeline Maintenance and Repair Work of Item 1. Business below for further discussion of regulatory developments related to the Company’s installation of safety valves.

The Consent Decree requires OSFM approval of restart plans for each of the Pipelines (the “Restart Plans”) prior to returning Lines 324 and 325 to service. The Consent Decree prescribes what must be submitted in the Restart Plans, including a long-term plan for enhancing the existing cathodic protection system (in the form of state waivers through the OSFM) and the AB 864 risk assessment and mitigation plan (i.e., additional isolation valves or other CBAT).

On July 29, 2024, PPC submitted the Restart Plans to OSFM for approval. On December 17, 2024, the OSFM approved Sable’s implementation of enhanced pipeline integrity standards for the Pipelines by granting state waivers of certain regulatory requirements related to cathodic protection and seam weld corrosion for the Pipelines. On February 11, 2025, PHMSA notified the OSFM that PHMSA does not object to the OSFM’s granting of the state waivers.

Sable plans to submit updated Restart Plans and anticipates the OSFM will approve the Restart Plans following the completion and testing of the anomaly repair and maintenance work.

Federal regulations require Sable to “take prompt action to address all anomalous conditions in [a] pipeline that [an]

operator discovers.” The Consent Decree requires Sable to comply with this and other federal regulatory requirements related to pipeline safety at heightened standards. In addition, as discussed above in the AB 864 Coastal Best Available Technology section of Item 1. Business, Sable is required to comply with AB 864’s requirements to install certain safety valves along the Pipelines in the County. Accordingly, Sable has been undertaking pipeline repair activities for both Lines 324 and 325, including installing the sixteen safety valves required under the approved 2021 CBAT Plan.

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 Pipelines in 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 pipelines 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”) to Sable 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 12, 2025, the County delivered a letter to Sable confirming that certain Pipeline 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.

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 Notice of Violation V-9-24-0152 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 Notice of Violation V-9-24-0152 and the Order, in addition to other claims. 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.

Also on February 18, 2025, the Coastal Commission issued (i) Executive Director Cease and Desist Order No. ED-25-CD-01 with respect to alleged unpermitted development activities located onshore along the Pipelines and (ii) a Notice of Intent to Commence Proceedings for a Commission Cease and Desist Order, Restoration Order, and Administrative Penalty Order with respect to alleged unpermitted development activities located onshore along the Pipelines and offshore at certain SYU facilities.

Sable’s pipeline repair operations remain ongoing.

Given the Company’s current progress in complying with AB 864, submitting the Restart Plan to the OSFM, and repairing Lines 324 and 325, we believe that these requirements will not inhibit our ability to restart the onshore and offshore facilities consistent with our timeline of restarting production during the second quarter of 2025.

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 Pipelines. EM acquired the Pipelines 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.

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. EM did not make rental payments for use of a right-of-way easement for the Pipelines and there is some risk the government could allege the easement has lapsed, as further 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.” Aside from the foregoing, the owners of the SYU Assets believe they have 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, the Bureau of Safety and Environmental Enforcement (“BSEE”) has confirmed that Sable’s recent completion of lease-holding activities serves to maintain all 16 leases within the Santa Ynez Unit to December 9, 2025. Refer to Item 1A Risk Factors and Item 3. Legal Proceedings for pending litigation concerning federal leases.

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.

Sable is not currently party to any commodity derivative contracts. After the restart of production, 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.

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.

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.

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 or upon the restart of production Sable expects to have insurance policies including the following:

Sable monitors regulatory changes and comments and considers their impact on the insurance market, along with SYU’s 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.

Sable may pursue new opportunities on the Outer Continental Shelf (“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 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.

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, BSEE, PHMSA, OSFM, California Department of Conservation’s Geologic Energy Management Division (“CalGEM”), Coastal Commission, CDFW, 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 restart the Pipelines 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. SYU’s 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, SYU’s 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, SYU 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.

Our oil and gas operations are conducted on offshore leases in federal waters and those operations are regulated by agencies such as the Bureau of Ocean Energy Management (“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. This rule is included in Secretary's Order 3418 implementing President Trump’s Unleashing American Energy executive order for suspension, revision or rescission.

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 SYU’s offshore 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 SYU’s 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, California State Parks and the SLC.

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 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 idled 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.

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 idled 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.

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 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 makes the existing regulations in Subpart OOOOa more stringent and creates a Subpart OOOOb to expand reduction requirements for new, modified, and reconstructed oil and gas sources, including standards focusing on certain source types that have never been regulated under the CAA (including intermittent vent pneumatic controllers, associated gas, and liquids unloading facilities). In addition, the rule establishes “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 March 2024, BLM finalized a new 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. 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.

On August 16, 2022, President Biden signed into law the Inflation Reduction Act of 2022 (the “Inflation Reduction Act” or “IRA”). The Inflation Reduction Act 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, 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 IRA. However, Congress approved and President Trump signed a resolution that repealed the rule, making the future implementation of the emissions charge uncertain. The methane emissions charge may have the effect of increasing our capital expenditures to limit methane releases and increasing our costs to the extent we exceed the limits.

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.

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. In addition, various states and local governments have vowed to continue to enact regulations to achieve the goals of the Paris Agreement.

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. However, on August 16, 2022, President Biden signed the Inflation Reduction Act into law, which imposes fees on methane emissions, beginning in calendar year 2024. 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.

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.

Oil and natural gas exploration and production activities on federal lands may be subject to NEPA. NEPA requires federal agencies, including the U.S. Departments of the Interior and Transportation, to evaluate major federal actions having the potential to significantly impact the human environment. In July 2020, the White House’s Council on Environmental Quality (“CEQ”) published a final rule to amend the NEPA implementing regulations intended to streamline the environmental review process, including shortening the time for review as well as eliminating the requirement to evaluate cumulative impacts. On April 20, 2022, CEQ published its Phase 1 final rule, the first of two planned rules to revise the 2020 rule. On May 1, 2024, CEQ finalized its Phase 2 rule. The Phase 1 and 2 rules substantially altered how federal agencies carried out their responsibilities under NEPA by requiring agencies to consider climate change impacts and disproportionate impacts to communities with environmental justice concerns, among other things. On February 3, 2025, the U.S. District Court for the District of North Dakota held invalid and vacated CEQ’s Phase 2 rule. Following an Executive Order from President Trump, on February 25, 2025, CEQ published an interim final rule removing CEQ’s NEPA implementing regulations and requesting public comment; the interim final rule is effective April 11, 2025. CEQ has directed federal agencies to revise or establish their NEPA implementing procedures to expedite permitting approvals and for consistency with NEPA as amended by the Fiscal Responsibility Act of 2023. Future development and production activities and plans on federal lands, 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.

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 (the “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.

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, the Department of the Interior finalized a rule limiting the application of the MBTA. However, the Department of the Interior revoked the rule in October 2021 and simultaneously issued an advanced notice of proposed rulemaking seeking comment on the Department of the Interior’s plan to develop regulations to authorize incidental take under certain prescribed conditions. However, new regulations have not been finalized.

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.

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 SYU’s 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 a new OSHA standard limiting respirable silica exposure, the oil and gas industry was required to implement engineering controls and work practices to 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.

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 our hazardous liquid and natural gas pipelines and pipeline facilities, 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.

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.

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, including pipeline facilities on the OCS. Pipelines 324 and 325 are subject to regulation by PHMSA.

At the state level, our intrastate hazardous liquid and natural gas pipeline facilities are regulated by the California Public Utility Commission (“CPUC”) and OSFM. The CPUC has jurisdiction over the construction and operations of certain intrastate natural gas pipeline facilities in California and the rates, terms and conditions of service under which companies provide intrastate transportation of gas, oil and other liquids by pipeline. If the Pipelines engage in intrastate common carrier operations, the Pipelines will be subject to regulation by the CPUC and intrastate tariffs filed by us with the CPUC will be regulated under a cost-of-service methodology and established on the basis of revenues, expenses and any investments. A variety of factors can affect the rates of return permitted by the CPUC. Tariff rates with respect to intrastate pipeline service in California are subject to challenge by complaint by interested parties or by independent action of the CPUC. The CPUC could limit our ability to increase our rates or could order us to reduce our rates and require the payment of refunds to shippers. The OSFM regulates the safety of intrastate hazardous liquid pipeline facilities in California. Both the CPUC and the OSFM are certified by PHMSA to regulate intrastate pipeline safety as certified state partners under the natural gas program and hazardous liquid program, respectively. Through this certification with PHMSA, they are required to adopt the minimum federal pipeline safety regulations and they may establish more stringent regulatory requirements as long as they are compatible with federal regulations.

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 our Pipelines.

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. Effective April 2017, PHMSA adopted new rules significantly increasing the maximum administrative civil penalties for violation of the pipeline safety laws and regulations.

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 $2,729,926 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 transmissions 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 yet to be published in the Federal Register. Thus, its implementation 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.

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. 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.

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.

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 California State Lands Commission 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.”

Additionally, the rates charged by the Pipelines if engaged in intrastate common carrier operations will be subject to regulation by the CPUC under a cost-of-service methodology as described above under “ -Sale and Transportation of Gas and Oil.” For additional information, see “Risk Factors—If engaged in intrastate common carrier operations, our financial results with respect to the Pipelines will primarily depend on the outcomes of ratemaking proceedings with the California Public Utilities Commission and we may not be able to earn an adequate rate of return in a timely manner or at all.”

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.

We have approximately 161 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 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 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.

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.

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.

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.

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.

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.

The following is a summary of the principal risks and uncertainties described in more detail in this annual report:

•We need to satisfy a number of permitting obligations and other requirements before we can restart production of the SYU Assets. There is no assurance that we will be successful in satisfying such obligations and requirements and restarting production of the SYU Assets in a timely manner.

•Our assumptions and estimates regarding the total costs associated with restarting production may be inaccurate.

•There is no guarantee that we will have sufficient cash to restart production of the SYU Assets.

•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 production 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.”

•Even if all contingencies are resolved and all facilities are restarted, the amounts recovered may be substantially less than estimated.

•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 most of our equipment has been shut-in for more than nine 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.

•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.

•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.

•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.

•We may be unable to Restart Production by March 2026, which would permit EM to exercise a reassignment option and take ownership of the SYU Assets without any compensation or reimbursement other than the deemed repayment in full of the principal and accrued interest outstanding under the Senior Secured Term Loan Agreement.

•Restrictive covenants in the Senior Secured Term Loan Agreement 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.

•Under the terms of the Senior Secured Term Loan Agreement, restarting production will trigger a springing maturity date following a specified grace period, and the terms on which we will be able to refinance the Senior Secured Term Loan Agreement, if necessary, will depend on then-prevalent market conditions.

•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.

•If engaged in intrastate common carrier operations, our financial results with respect to the Pipelines will primarily depend on the outcomes of ratemaking proceedings with the CPUC and we may not be able to earn an adequate rate of return in a timely manner or at all.

•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.

•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 have identified material weaknesses in our internal control over financial reporting. These material weaknesses could continue to adversely affect investor confidence in us and materially adversely affect our ability to report our results of operations and financial condition accurately and in a timely manner.

•If we fail to develop and maintain an effective system of disclosure controls and internal control over financial reporting, our ability to produce timely and accurate financial statements or comply with applicable regulations could be impaired, which may adversely affect investor confidence in us and, as a result, the market price of our Common Stock.

Production was suspended as a result of the Line 901 incident and consequent suspension of service, and our business depends on its production restarting. We need to satisfy a number of requirements related to the SYU Assets and Lines 901 and 903 before we can restart production. 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. For further information, see “Business—Pipeline 901 Incident.” While the previous operator of Lines 901 and 903 satisfied most of the conditions to restart including under the Consent Decree, there is no assurance that we will be successful in satisfying the remaining requirements and restarting production in a timely manner. If we fail to restart production by March 1, 2026, the prior owner of the SYU Assets may exercise its right to cause us to reassign the SYU Assets. See “Risk Factors—Risks Related to the Business of the Company-We may be unable to Restart Production of SYU Assets by March 1, 2026, which would permit EM to exercise a reassignment option and take ownership of the SYU Assets without any compensation or reimbursement other than the deemed repayment in full of the principal and accrued interest outstanding under the Senior Secured Term Loan Agreement.”

We currently estimate the total remaining start-up expenses of approximately $152.0 million to restart production. The expenditures will primarily be directed toward obtaining the necessary regulatory approvals and completing the pipeline repairs and bringing the shut-in assets back online during the second quarter of 2025. This estimate of costs to restart production 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, 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. 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 significantly higher than our estimated costs for the restart of production.

Until we restart production of the SYU Assets, we will not generate any revenue or cash flows from operations. We will rely on cash on hand to fund the operations necessary to restart production of the SYU Assets. If we do not have sufficient cash on hand to restart production, 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 restart production, which could materially affect our business, financial condition and results of operations. See “Risk Factors—Risks Related to the Business of the Company-We may be unable to Restart Production of the SYU Assets by March 1, 2026, which would permit EM to exercise a reassignment option and take ownership of the SYU Assets without any compensation or reimbursement other than the deemed repayment in full of the principal and accrued interest outstanding under the Senior Secured Term Loan Agreement.”

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;

•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, 2024, the NYMEX-WTI oil futures price ranged from a high of $123.70 per Bbl to a low of $(37.63) per Bbl, while the NYMEX-Henry Hub natural gas futures price ranged from a high of $9.68 per MMBtu to a low of $1.48 per MMBtu. For the year ended December 31, 2024, the NYMEX-WTI oil futures price ranged from a high of $86.91 per Bbl on April 5, 2024 to a low of $65.75 per Bbl on September 10, 2024 and the NYMEX-Henry Hub natural gas futures price ranged from a high of $3.95 per MMBtu on December 24, 2024 to a low of $1.58 per MMBtu on March 26, 2024. 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.

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.

The prices that we expect to receive for our future oil and natural gas production 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 production 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 resources are contingent upon (1) approval and/or inspection by from federal, state and local regulators to restart production, (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.

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.

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

•adverse weather conditions and natural disasters.

Many of these risks are heightened for us due to the fact that most of our equipment has been shut-in for more than eight 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 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.

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.

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.

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 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.

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.

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 Agreement (the “Senior Secured Term Loan Agreement”), dated as of the Closing Date by and among Sable, EMC, 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, such approval not to be unreasonably withheld.

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 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 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 Matter, infra). However, at least one private landowner along sections of Pipeline Segment 324 has continued to make claims that the easement agreements with it are no longer effective. Our loss of any of these surface use agreements, rights-of-way or other 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.

If we fail to Restart Production (as defined in the Sable-EM Purchase Agreement) of the SYU Assets by March 1, 2026 (the “Restart Failure Date”), then pursuant to the Sable-EM Purchase Agreement, for 180 days thereafter, EM will have the exclusive right, but not the obligation, to require us to reassign the SYU Assets and rights to EM or its designated representative, without reimbursing us for any of our costs or expenditures (the “Reassignment Option”). If we have acquired any additional rights or assets or have developed additional improvements related to the SYU Assets, records or benefits, on EM’s request we also would be required to assign and deliver those additional rights, assets, improvements, records or benefits to EM without being reimbursed for any of our additional costs or expenses. If we are unable to Restart Production of the SYU Assets by the Restart Failure Date and EM exercises its Reassignment Option, EM will become the owner of substantially all of our business and we may be forced to wind-down our operations. Our ability to Restart Production of the SYU Assets is subject to several risks, and there is no assurance that we will be able to Restart Production of the SYU Assets by the Restart Failure Date. See “Risk Factors—Risks Related to the Restart of Production.”

Restrictive covenants in the Senior Secured Term Loan Agreement 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 Agreement 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 Agreement, 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 Agreement 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 Agreement 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.

The Senior Secured Term Loan Agreement includes a springing maturity date of ninety (90) days after Restart Production (as defined in the Sable-EM Purchase Agreement) (i.e., two hundred forty (240) days after resumption of actual production from the wells), which could require a future refinancing of the indebtedness under the Senior Secured Term Loan Agreement or the incurrence of new indebtedness. The terms on which we would be able to obtain any refinancing of the Senior Secured Term Loan Agreement will depend on market conditions at the time of any such refinancing.

The outstanding principal amount under our Senior Secured Term Loan Agreement 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.

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 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.

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.

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 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.

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. We may incur substantial costs in order to maintain compliance with these existing laws and regulations. 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 environmental protection, resource protection, and damage to natural resources.

These laws and regulations may impose numerous obligations applicable to our operations, including the ability to obtain a permit before conducting our operations, including regulated drilling activities; the restriction of types, quantities and concentrations of materials that can be released or discharged into or through the environment; the limitation or prohibition of drilling, production and transportation activities on certain lands lying within wilderness, wetlands, seismically active 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, SLC and numerous other governmental authorities have the authority to enforce compliance with these laws and regulations and the permits 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 restart or replace the Pipelines, which may delay or interrupt our operations and limit our growth and revenue, or may result in a failure to Restart Production by the Restart Failure Date.

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, under the Biden Administration, 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 laws are 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.

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.

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.

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 Inflation Reduction Act (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, Congress has approved a resolution that would repeal the rule, making the future implementation of the emissions charge uncertain. 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. In addition, various states and local governments have vowed to continue to enact regulations to achieve the goals of the Paris Agreement.

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.”

If determined to be a regulated intrastate common carrier in California, the Pipelines’ tariffs will be set by the CPUC on a prospective basis and will generally be designed to allow us to collect sufficient revenues to recover reasonable costs of providing service on the basis of revenues, expenses and a return on our capital investments. Our financial results with respect to the Pipelines could be materially affected if the CPUC does not authorize sufficient revenues for us to safely and reliably serve our pipeline customers and earn an adequate return of equity. The outcome of the ratemaking proceedings can be affected by many factors, including the level of opposition by intervening parties; potential rate impacts; increasing levels of regulatory review; changes in the political, regulatory, or legislative environments; and the opinions of our regulators, consumer and other stakeholder organizations, and customers, about our ability to provide safe and reliable oil transportation pipeline transportation.

In addition to the amount of authorized revenues, our financial results with respect to the Pipelines could be materially affected if our actual costs to safely and reliably serve our pipeline customers differ from authorized or forecast costs. We may incur additional costs for many reasons including changing market circumstances, unanticipated events (such as wildfires, storms, earthquakes, accidents, or catastrophic or other events affecting our pipeline operations), or compliance with new state laws or policies. Although we may be allowed to recover some or all of the additional costs, there may be a substantial delay between when we incur the costs and when we are authorized to collect revenues to recover such costs. Alternatively, the CPUC may disallow certain costs that they determine were not reasonably or prudently incurred.

California, where our operations and assets are located, is heavily regulated with respect to oil and gas operations. Federal, state and local laws and regulations govern most aspects of exploration and production in California. Collectively, the effect of the existing laws and regulations is to potentially limit the number and location of our wells through restrictions on the use of our properties, limit our ability to develop certain assets and conduct certain operations, and reduce the amount of oil and natural gas that we can produce from our wells below levels that would otherwise be possible. 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.

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.

In February 2021, California State Senators Scott Wiener and Monique Limón introduced Senate Bill 467, which proposes to halt the issuance or renewal of permits for hydraulic fracturing, acid well stimulation treatments, cyclic steaming, and water and steam flooding starting January 1, 2022, and then prohibit these extraction methods entirely starting January 1, 2027. SB 467 also would have prohibited all new or renewed permits for oil and gas extraction within 2,500 feet of any homes, schools, healthcare facilities or long-term care institutions such as dormitories or prisons, by January 1, 2022. However, SB 467 never made it out of committee and other bills to limit well stimulation treatments have also previously been introduced and failed to pass through the California legislature. Although these legislative efforts have failed, it is possible that SB 467 or similar legislation could be reintroduced in the future and we cannot predict the results of such future efforts.

On February 21, 2025, California State Assembly Member Hart introduced AB 1448 to the California State Legislature. Among other changes, AB 1448 would amend certain provisions of California’s Public Resources Code to add additional procedural requirements for oil- and gas-related leases in state waters and would require that the repair, reactivation, and maintenance of an oil and gas facility that has been idled, inactive, or out of service for three years or more obtain a new coastal development permit. We cannot predict whether AB 1448 will make it out of committee in its current form.

On June 3, 2022, the U.S. Court of Appeals for the Ninth Circuit prohibited the federal government from issuing new permits for hydraulic fracturing and acidizing of oil wells in federal waters off the coast of California until a full environmental review is completed by federal agencies. 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 on offshore California platforms before the unconventional drilling methods had been fully reviewed. The court also found that the California Coastal Commission must determine if hydraulic fracturing and acidizing are consistent with California’s coastal management program.

While currently none of our California 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.

We operate exclusively in California and in the 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.

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.

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 have had increasing success in limiting oil and gas production by appealing to regulatory agencies, filing lawsuits and applying political pressure. In order to restart production we are required to obtain a series of permits or regulatory approvals from, among other agencies, OSFM. 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. 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. There is no assurance that these groups will not be successful in delaying or preventing us from obtaining the required approvals through litigation or other actions.

For example, 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; 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 was not named as a party to the case, but on December 3, 2024, the Court granted Sable’s motion to intervene as a defendant to become a party to the lawsuit, and Sable vigorously contests the plaintiffs’ allegations. On January 29, 2025, the Court granted plaintiffs’ request to supplement and amend their complaint. In the amended complaint, plaintiffs allege that BSEE: violated 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 asks 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; 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 restarting production until it complies with NEPA, OCSLA and the APA; and for an award of costs and attorneys’ fees.

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 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, Congress approved and President Trump signed a resolution that repealed the rule, making the future implementation of the emissions charge uncertain. 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.

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.

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.

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 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.

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 financial results or the annual 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 restart production;

•our success in satisfying permitting and other regulatory requirements to restart the Pipelines 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 restarting and maintaining production and the Pipelines;

•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;

•the outcome of ratemaking proceedings with the California Public Utilities Commission;

•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;

•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 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.

As a U.S. public company, we are required to comply with the requirements of the Sarbanes-Oxley Act of 2002 (the “Sarbanes-Oxley Act”), including, among other things, that we maintain effective disclosure controls and procedures and internal control over financial reporting. We are continuing to develop and refine our disclosure controls and other procedures that are designed to ensure that information required to be disclosed by us in the reports that we file with the SEC is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms, and that such information is accumulated and communicated to our management, including our principal executive and financial officers.

We are required to make a formal assessment of the effectiveness of our internal control over financial reporting and, after we cease to be an emerging growth company, we will be required to include an attestation report on internal control over financial reporting issued by our independent registered public accounting firm. To achieve compliance with these requirements within the prescribed time period, we have begun a process to document and evaluate our internal control over financial reporting, which is both costly and challenging. We will need to continue to dedicate internal resources, potentially engage outside consultants and adopt a detailed work plan to assess and document the adequacy of our internal control over financial reporting, validate through testing that controls are functioning as documented and implement a continuous reporting and improvement process for internal control over financial reporting. There is a risk that we will not be able to conclude, within the prescribed time period or at all, that our internal control over financial reporting is effective as required by Section 404 of the Sarbanes-Oxley Act. Moreover, our testing, or the subsequent testing by our independent registered public accounting firm, may reveal additional deficiencies in our internal control over financial reporting that are deemed to be material weaknesses.

Any failure to implement and maintain effective disclosure controls and procedures and internal control over financial reporting, including the identification of one or more material weaknesses, could cause investors to lose confidence in the accuracy and completeness of our financial statements and reports, which would likely adversely affect the market price of our Common Stock. In addition, we could be subject to sanctions or investigations by the stock exchange on which our Common Stock is listed, the SEC and other regulatory authorities.

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.

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 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.

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 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.

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 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 restarting and maintaining production and the Pipelines;

•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 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.

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 are an “emerging growth company,” as defined in the JOBS Act. For as long as we remain an emerging growth company, we may choose to take advantage of exemptions from various reporting requirements applicable to other public companies but not to “emerging growth companies,” including:

•not being required to have an independent registered public accounting firm audit our internal control over financial reporting under Section 404 of the Sarbanes-Oxley Act;

•reduced disclosure obligations regarding executive compensation in our periodic reports and annual reports on Form 10-K; and

•exemptions from the requirements of holding non-binding advisory votes on executive compensation and stockholder approval of any golden parachute payments not previously approved.

As a result, our stockholders may not have access to certain information that they may deem important. Our status as an emerging growth company will end as soon as any of the following takes place:

•the last day of the fiscal year in which we have at least $1.235 billion in annual revenue;

•the date we qualify as a “large accelerated filer,” with at least $700.0 million of common equity securities held by non-affiliates;

•the date on which we have issued, in any three-year period, more than $1.0 billion in non-convertible debt securities; or

•the last day of the fiscal year ending after the fifth anniversary of the Flame IPO.

Under the JOBS Act, emerging growth companies can also delay the adoption of new or revised accounting standards until such time as those standards apply to private companies. We may elect to take advantage of this extended transition period and as a result, our financial statements may not be comparable with similarly situated public companies.

We cannot predict if investors will find our Common Stock less attractive if we choose to rely on any of the exemptions afforded emerging growth companies. If some investors find our Common Stock less attractive because we rely on any of these exemptions, there may be a less active trading market for our Common Stock and the market price of our Common Stock may be more volatile and may decline.

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 restart of production of the SYU Assets and the repayment or refinancing of the Senior Secured Term Loan Agreement) to pay any cash dividends for the foreseeable future. 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 Agreement 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.

Since the completion of the Business Combination on February 14, 2024, management has been working to create a defined cybersecurity risk management program, through the addition of enhanced applications to identify and mitigate risks. During 2024 the Company engaged and managed 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 management and are being incorporated into the Company’s information 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. Management will complete implementation of the action items during 2025, which we intend to test periodically for effectiveness.

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 2025, 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.

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 quarterly 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.

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.

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 subsea pipelines, which transport crude oil, natural gas and produced water from the platforms to the onshore processing facilities along with the pipeline assets Line 324 and Line 325. Line 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. Line 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 2920, Houston, Texas 77002. We consider our current office space adequate for our current operations.

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.

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.

On September 27, 2024, the Coastal Commission issued Notice of Violation No. V-9-24-0152 to Sable, which asserted that the safety valve installation work and certain maintenance and repair activities undertaken by Sable on the Pipelines in the Coastal Zone to address anomalies and install safety valves constituted unpermitted development activities under the Coastal Act and the County’s 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 certain repair work on the pipelines since they were first permitted and built over 30 years ago, as well as the County’s acknowledgement that it does not have permit authority or jurisdiction over the Company’s installation of the sixteen new safety valves in the County along the Pipelines in accordance with the 2021 CBAT Plan. 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 to Sable 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. Sable subsequently recommenced the repair and maintenance activities which were subject to Notice of Violation V-9-24-0152.

On February 12, 2025, the County delivered a letter to Sable confirming that certain Pipeline 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.”

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 Offshore Corp. 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 Notice of Violation V-9-24-0152 and Executive Director Cease and Desist Order ED-24-CD-02, in addition to other claims. 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.

Also on February 18, 2025, the Coastal Commission issued (i) Executive Director Cease and Desist Order No. ED-25-CD-01 with respect to alleged unpermitted development activities located onshore along the Pipelines and (ii) a Notice of Intent to Commence Proceedings for a Commission Cease and Desist Order, Restoration Order, and Administrative Penalty Order with respect to alleged unpermitted development activities located onshore along the Pipelines and offshore at certain SYU facilities (the “EDCDO/NOI”).

On December 13, 2024, the Regional Board issued three letters to Sable related to the Pipelines: (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. Sable believes that coverage under the Regional Board’s General Permit is not required. On January 10, 2025, Sable submitted a written response to each of the three letters to the Regional Board. On January 22, 2025, the Regional Board issued two additional letters to the Company related to the Pipelines: (i) a Second and Final 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; and (ii) an order requiring Sable to submit a technical report responding to information requests 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 under the Regional Board’s General Permit WQO 2004-004 for the alleged discharge waste to waters of the state, and on February 18, 2025, Sable submitted an application for CDFW for an after-the-fact Lake and Streambed Alteration Agreement (LSAA) to address the same site. On February 21, 2025, Sable submitted to the Regional Board, under protest, an application for coverage under the Regional Board’s General Permit for Stormwater Discharges.

On March 8, 2025, Sable submitted its responses to the Regional Board’s order requiring the Company to submit a technical report.

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. Permit applications for after-the-fact permits for these four sites were submitted to the Regional Board and CDFW during the week of March 10, 2025.

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 restart 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. Sable and PPC intend to defend the case vigorously. See Part II, Item 8 “Financial Statements and Supplementary Data — Notes to Consolidated Financial Statements,” Note 8 — Commitments and Contingencies for additional information regarding this matter.

Our Common Stock trades on the NYSE under the symbol “SOC”.

On October 3, 2024, Sable Aviation, LLC (“Sable Aviation”), an entity controlled by our Chairman and Chief Executive Officer, and Sable entered into an Agreement of Purchase and Sale, pursuant to which Sable Aviation sold transportation assets and related equipment to Sable in exchange for 600,000 shares of Common Stock, valued at $15.2 million.

On March 14, 2025, there were 54 holders of record of our Common Stock, and eight holders of record of our private placement warrants.

The following table sets forth, for the periods indicated, Sable's equity incentive plans authorized activity:

In connection with the Business Combination, the Company adopted the Incentive Plan in order to facilitate the grant of cash and equity incentives to directors, employees, including named executive officers, and consultants to help attract and retain the services of these individuals. As of December 31, 2024, the aggregate number of shares of Common Stock that are available for issuance under the Incentive Plan is 10,747,299, provided that the number of shares of Common Stock authorized for issuance under the Incentive Plan is subject to an annual increase for ten years on the first day of each calendar year beginning January 1, 2024, in an amount equal to the lesser of (A) 5% of the aggregate number of shares of Common Stock outstanding on the final day of the immediately preceding calendar year and (B) such smaller number of shares as is determined by the Board.

Unless otherwise indicated, references to “we”, “us”, “our”, “Sable” or the “Company” in this Item 7 are to Sable Offshore Corp. (f/k/a Flame Acquisition Corp.) and its consolidated subsidiaries, following the Business Combination. References to “Flame” are to Flame Acquisition Corp. before the consummation of the Business Combination. References to the “Pipelines” are to Pipeline Segments 324/325 (formerly known as Pipeline Segments 901/903) and the other “324/325 Assets” (formally known as "901/903 Assets" and as defined in the Sable-EM Purchase Agreement). As a result of the closing of the Business Combination, which was accounted for as a forward merger in accordance with GAAP, the financial statements of Successor (as defined below) are now the financial statements of the Company. The following discussion and analysis of our financial condition and results of operations is provided as a supplement to, and should be read in conjunction with our financial statements and related notes thereto included elsewhere in this Annual 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 Notice Regarding Forward-Looking Statements” and Part I, Item 1A, “Risk Factors.”

Sable Offshore Corp. is an independent oil and gas company headquartered in Houston, Texas. We were incorporated in Delaware on October 16, 2020 and, until February 14, 2024, were a blank check company formed for the purpose of effecting a merger, capital stock exchange, asset acquisition, stock purchase, reorganization or similar business combination with one or more businesses. We are an emerging growth company and, as such, we are subject to all of the risks associated with emerging growth companies.

On November 1, 2022 (as amended on June 13, 2023 and December 15, 2023), Sable Offshore Corp., a Texas corporation (“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”).

On November 2, 2022, Flame entered into an agreement and plan of merger, dated as of November 2, 2022 (as amended, the “Merger Agreement”), with SOC and Sable Offshore Holdings, LLC, a Delaware limited liability company and the parent company of SOC (“Holdco” and, together with SOC, “Legacy Sable”), which provided for the following transactions at the closing: (i) Holdco would merge with and into Flame, with Flame surviving such merger (the “Holdco Merger”) and (ii) SOC would merge 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 “Business Combination”).

On February 12, 2024, Flame held a special meeting of stockholders (the “Special Meeting”), at which the Flame stockholders considered and adopted, among other matters, a proposal to approve the Business Combination, including (a) adopting the Merger Agreement and (b) approving the other transactions contemplated by the Merger Agreement.

Pursuant to the terms and subject to the conditions set forth in the Merger Agreement, following the Special Meeting, on February 14, 2024 (the “Closing Date”), the Business Combination was consummated (the “Closing”). In connection with the Business Combination, Flame changed its name to “Sable Offshore Corp.”

On February 14, 2024, in connection with the Business Combination, the Company issued 44,024,910 shares of Common Stock, 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 is recognized as an offset to the proceeds from 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 (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. An associated marketing fee and legal fees of approximately $7.8 million was recognized as an offset to the proceeds from the Second PIPE Investment.

On October 3, 2024, Sable issued a press release announcing the redemption of all of its outstanding Public Warrants to purchase shares of Common Stock that were issued under the Warrant Agreement, as part of the units sold in the Company IPO.

On October 31, 2024, the Public Warrants ceased trading on the New York Stock Exchange. As of November 4, 2024 (the “Redemption Date”), approximately 99.8% of the Company’s outstanding Public Warrants were exercised by the holders thereof to purchase fully paid and non-assessable shares of Common Stock at an exercise price of $11.50 per share. As a result, holders of the Public Warrants received an aggregate of 15,957,820 shares of the Company’s Common Stock in exchange for $183.5 million in cash proceeds to the Company. All unexercised and outstanding Public Warrants as of 5:00 p.m. New York City time on the Redemption Date were redeemed at a price of $0.01 per Public Warrant and, as a result, no Public Warrants currently remain outstanding and the Public Warrants have ceased trading on the New York Stock Exchange. The private placement warrants and working capital warrants to purchase Common Stock that were issued under the Warrant Agreement and that are still held by the initial holders thereof or their permitted transferees were not subject to this redemption and remain outstanding. Refer to Note 7 — Warrants for additional details regarding the warrant exercises.

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 SYU. SYU consists of three offshore platforms and a wholly owned onshore processing facility located along the Gaviota Coast at Las Flores Canyon in Santa Barbara County, California. SYU’s onshore facilities and the three offshore platforms remained in continuous operation until 2015. In May 2015, a pipeline operated by Plains All American Pipeline, L.P. (“Plains”) that transported produced oil from SYU experienced a leak, as further described under “Business—Pipeline 901 Incident.” The SYU platforms and facilities suspended production after the incident, the SYU Assets were shut in and the facilities were placed in a safe state. The facilities are not currently producing oil and gas; however, all equipment remains in place in an operation-ready state, requiring ongoing inspections, maintenance and surveillance. As part of these suspension efforts, all equipment was drained, flushed and purged in 2016. All hydrocarbon pipelines within SYU have been placed in a safe state and remain under regular monitoring. In 2020, Plains entered into a Consent Decree, described further under “Business—Pipeline 901 Incident,” that provides a path for a potential restart of the Pipelines.

The discussion of the results of operations for the Predecessor periods below do not include the results from the Pipelines and the Pipelines 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 Pipelines have not been included because SEC guidance provides that the financial statements of recently acquired businesses such as the Pipelines 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 Pipelines renders the Predecessor combined financial statements misleading or substantially incomplete. The Successor financial statements include the results from the Pipelines and the Pipelines are included in the consolidated financial statements.

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 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.”

The Company has not had any substantial revenues since the shut-in. The Company’s various operating expenses are the principal metrics used to assess its performance.

•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, which is based on estimated asset service life taking obsolescence into consideration. Since being shut in, no depletion or amortization has been recorded for the Successor periods presented. 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 year ended December 31, 2023, and 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 restart of production.

The comparability of our operating results for the period 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) was impacted by the Business Combination. In the discussion of our results of operations for these periods, we may quantitatively disclose the impacts of the Business Combination to the extent they remain ascertainable. Following the Closing Date, all of our operations have focused on restarting production of the SYU Assets. We lack the ability to generate any operating revenues until we receive the necessary regulatory approvals and complete the repairs necessary to restart production. Our only source of non-operating income is generated in the form of interest income on cash and cash equivalents. Post the Business Combination, we expect to incur additional expenses as a result of being an operating public company, for legal, accounting and compliance expenses.

The following table presents selected consolidated financial results of operations for the Successor and Predecessor periods presented.

Operating and maintenance expenses. Operating and maintenance expenses were $7.3 million and $87.9 million for the periods from January 1, 2024 through February 13, 2024 (Predecessor) and February 14, 2024 through December 31, 2024 (Successor), respectively, or a combined $95.2 million, representing an increase of $34.5 million, or 56.9%, compared to $60.7 million for the year ended December 31, 2023 (Predecessor). The increase in operating and maintenance expenses was primarily attributable to activities associated with restart, which includes an 88% increase in operations employee headcount since the Closing Date. Operations and maintenance expenses are expected to increase over the next several years as production is restarted and additional employees are hired to support safe production operations.

Depletion, depreciation, amortization and accretion. Depletion, depreciation, amortization and accretion was $2.6 million and $9.7 million for the periods from January 1, 2024 through February 13, 2024 (Predecessor) and February 14, 2024 through December 31, 2024 (Successor), respectively, or a combined $12.4 million, representing a decrease of $8.7 million, or 41.2%, compared to $21.0 million for the year ended December 31, 2023 (Predecessor). The decrease in depletion, depreciation, amortization and accretion was primarily attributable to the Company not recognizing depletion expense following the Business Combination, as the assets were not in service since repairs are necessary prior to achieving production restart. Depletion will resume once production commences and the assets are placed in service. The decrease can also be attributed to a decrease in accretion expense associated with the lower ARO recognized in the Business Combination in accordance with the accounting for the transaction. The $9.7 million depletion, depreciation, amortization and accretion expense recognized for the period February 14, 2024 through December 31, 2024 (Successor) primarily represents the recognition of ARO accretion for the period. Depletion, depreciation, amortization and accretion expense is expected to increase over the next several years as production is restarted.

General and administrative expenses. General and administrative expenses were $1.7 million and $229.1 million for the periods from January 1, 2024 through February 13, 2024 (Predecessor) and February 14, 2024 through December 31, 2024 (Successor), respectively, or a combined $230.9 million, representing an increase of $218.1 million compared to $12.8 million for the year ended December 31, 2023 (Predecessor). The increase in general and administrative expenses was primarily attributable to general and administrative related stock-based compensation of $86.6 million following the Business Combination, the $70.0 million settlement of the Grey Fox Matter (Refer to Note 8 — Commitments and Contingencies), $17.5 million in legal expenses and professional fees related to the Business Combination, restart efforts, and other legal matters, and the recognition of salaries and wages following the Company's commencement of operations following the Business Combination.

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.

Total other expense (income), net. Total other expense, net was $0.1 million and $290.6 million for the periods from January 1, 2024 through February 13, 2024 (Predecessor) and February 14, 2024 through December 31, 2024 (Successor), respectively, or a combined $290.7 million, representing an increase of $291.5 million compared to $0.8 million in other income for the year ended December 31, 2023 (Predecessor). The increase in total other expense, net was primarily attributable to an increase of $227.5 million in fair value of the warrants and $67.3 million in interest expense, partially offset by interest income of $4.2 million. The increase during the Successor period is also due to the fact that the Predecessor did not have any debt or associated interest expense, warrants, or interest income.

Income tax benefit. Income tax benefit was zero and less than $0.1 million for the periods from January 1, 2024 through February 13, 2024 (Predecessor) and February 14, 2024 through December 31, 2024 (Successor), respectively, representing an increase of less than $0.1 million compared to zero for the year ended December 31, 2023 (Predecessor). Based on our ongoing assessment of our ability to recover our deferred tax assets, we concluded that it was more likely than not that our deferred tax assets in excess of deferred tax liabilities would not be realized. 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 future estimated taxable income. 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.

Overview. Our plans for restarting production, including restarting the existing wells and facilities and recommencing transportation through the Pipelines, 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 the shut-in, capital contributions from its parent. While production is in the process of being restarted and prior to generating positive cash flow from production, capital expenditure needs will be substantial and are expected to come from cash on hand. 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. Sable raised $440.2 million in gross proceeds from the First PIPE Investment in connection with the Business Combination, $150.0 million in gross proceeds from the Second PIPE Investment, and approximately $183.5 million from the exercise of 15,957,820 warrants for 15,957,820 shares of Common Stock. Additionally, more than $600 million of the Purchase Price was seller-financed through a Senior Secured Term Loan with EM. Based on its current financial plan, Sable management expects production to restart in the second quarter 2025, after which its operating cash flows are expected to be sufficient to service Sable’s operating expenses and indebtedness.

Capital Requirements. Sable currently estimates remaining start-up expenses of approximately $152.0 million in order to restart production in the second quarter 2025. Management evaluates its cost estimates on an ongoing basis. The expenditures will primarily be directed toward obtaining the necessary regulatory approvals and completing the pipeline repairs and bringing the shut-in assets back online in the second quarter 2025. After production restarts, Sable management expects a rapid increase in operating cash flows that should allow Sable to fund further capital expenditures. If Sable is unable to obtain funds or provide funds as needed for the planned capital expenditure program, Sable may not be able to finance the capital expenditures necessary to restart production or sustain production thereafter.

Prior to the Business Combination, EM funded the Predecessor SYU operational expenses. Since the consummation of the Business Combination, Sable has addressed near-term capital funding needs with the First PIPE Investment, the Second PIPE Investment and proceeds from the exercise of Warrants (refer to Note 7 — Warrants for additional details regarding the warrant exercises) and believes the Company has sufficient capital to maintain operations and complete the repairs necessary to restart production. However, the Company’s plans for production restart are contingent upon approvals from federal, state and local regulators. Additionally, if the Company’s estimates of the costs of restarting production are less than the actual amounts necessary to do so, the Company may have insufficient funds available to operate its business prior to first production and will need to raise additional capital. If the Company is unable to raise additional capital, it may be required to take additional measures to conserve liquidity, which could include, among other things, reducing overhead expenses.

The Company cannot provide any assurance that new financing will be available to it on commercially acceptable terms, if at all.

Due to the remaining regulatory approvals necessary to restart production, along with the timing of ongoing construction repair efforts, 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.

The following table summarizes cash flows from Operating, Investing and Financing activities:

Cash Flows from Operating Activities. The SYU Assets have been shut in since 2015 and therefore there has been no production and associated revenues for the comparative periods. The net cash used in operating activities for the Company was $22.5 million and $163.0 million for the periods from January 1, 2024 through February 13, 2024 (Predecessor) and February 14, 2024 through December 31, 2024 (Successor), respectively, or a combined $185.4 million, representing an increase of $115.3 million, or 164.5% compared to the year ended December 31, 2023 (Predecessor). 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 period from February 14, 2024 through December 31, 2024 (Successor), we had a net loss of $617.3 million, which consists of a non-cash increase of $227.5 million in fair value of the warrants, non-cash stock-based compensation of $91.6 million, non-cash paid-in-kind interest of $66.3 million, changes in accounts payable of $54.0 million, non-cash depreciation, depletion, amortization and accretion of $9.7 million and a non-cash effect from the First Amendment to the Senior Secured Term Loan of $5.0 million. Changes in accounts payable for that period is primarily attributable to the Grey Fox Matter settlement, with $35.0 million remaining in accounts payable and accrued expenses as of December 31, 2024 (Refer to Note 2 — Significant Accounting Policies), and other vendor payables associated with the restart efforts. Future cash flow from operations will depend on our ability to bring the associated oil and gas production of the assets back online, as well as the prices of oil, NGLs and natural gas.

For the year ended December 31, 2023 (Predecessor), the $70.1 million cash used in operating activities was related to maintenance and operational readiness expenses.

Cash Flows from Investing Activities. The net cash used in investing activities for the Company was zero and $276.2 million for the periods from January 1, 2024 through February 13, 2024 (Predecessor) and February 14, 2024 through December 31, 2024 (Successor), respectively. The Successor investing cash flow is primarily comprised of $203.9 million paid to EM at Closing, with the remaining $72.3 million cash paid for capital expenditures associated with restart efforts.

For the year ended December 31, 2023 (Predecessor), the net cash used in investing activities for the Predecessor period was zero since the SYU Assets have been shut in since 2015, without investing activities, but has been maintained in an operation-ready state.

Cash Flows from Financing Activities. The net cash provided by financing activities for the Company was $22.5 million and $721.7 million for the periods from January 1, 2024 through February 13, 2024 (Predecessor) and February 14, 2024 through December 31, 2024 (Successor), respectively. The Successor financing activities for the period are comprised of the aggregate $590.2 million in gross proceeds received from the First PIPE Investment and the Second PIPE Investment, less $30.6 million of capitalized transaction expenses, or approximately $559.7 million net, cash received from Warrant exercises of $183.5 million, less the deposit paid to EM for the Senior Secured Term Loan of $18.8 million, payment of debt issuance costs of $1.6 million, and repayment of Flame's non-convertible promissory notes—related parties for $1.1 million.

For the year ended December 31, 2023 (Predecessor), the net cash used in financing activities was $70.1 million. Predecessor financing activities consists of EM capital contributions financing the maintenance and operational readiness activities.

Pursuant to the Senior Secured Term Loan, which financed most of the Purchase Price (as defined in the Senior Secured Term Loan), Sable will pay interest at ten percent (10%) per annum compounded annually, payable in arrears on January 1st of each year. 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 under the Senior Secured Term Loan. 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. In the absence of further negotiations, Restart Production must take place prior to March 1, 2026, and the Senior Secured Term Loan must be refinanced within 240 days following such first production date. Refer to Note 6 — Debt for additional disclosures regarding the Senior Secured Term Loan.

Pursuant to the Transition Services Agreement with EM, EM provided to Sable certain operational, accounting, cash management, information technology and other general transition services with respect to the Assets (as such term is defined in the Sable-EM Purchase Agreement) for three months following the Closing Date, or until May 14, 2024.

Additional obligations include the performance of ARO as referenced under “Critical Accounting Policies and Estimates—Asset Retirement Obligations” below.

As of December 31, 2024, the Company had no off-balance sheet arrangements.

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.

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 and transportation assets. Due to the natural of such assets, the onshore midstream facilities are presented within oil and gas properties, while the transportation assets are presented within other assets on the consolidated balance sheets.

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 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 have been shut in 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 has been recorded for the periods presented. The recognition of depletion expense will commence upon restart and related production.

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—Property, Plant, and Equipment and ASC 932 Extractive Activities—Oil and Gas. 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 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 asset retirement obligations 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.

We are an “emerging growth company,” as defined in Section 2(a) of the Securities Act, as modified by the JOBS Act, and it has elected to comply with certain reduced public company reporting requirements. Sable could remain an emerging growth company until the last day of the fiscal year following the fifth anniversary of the completion of the Company IPO. However, if (a) Sable’s total annual gross revenue exceed $1.235 billion, (b) Sable is deemed to be a large accelerated filer, which means the market value of Common Stock that is held by non-affiliates exceeds $700.0 million as of the end of the prior fiscal year’s second fiscal quarter, or (c) Sable’s non-convertible debt issued within a three-year period exceeds $1.0 billion, Sable would cease to be an emerging growth company as of the following fiscal year.

Additionally, we are a “smaller reporting company” as defined in Item 10(f)(1) of Regulation S-K. Smaller reporting companies may take advantage of certain reduced disclosure obligations, including, among other things, providing only two years of audited financial statements. Sable will be a smaller reporting company until the last day of any fiscal year for so long as either (1) the market value of Common Stock held by non-affiliates did not exceed $250 million as of the prior June 30, or (2) Sable’s annual revenues did not exceed $100 million during such completed fiscal year and the market value of Common Stock held by non-affiliates did not exceed $700 million as of the prior June 30.

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.

We are a smaller reporting company as defined by Rule 12b-2 of the Exchange Act and are not required to provide the information otherwise required under this item.

To the Stockholders and Board of Directors of Sable Offshore Corp.

We have audited the accompanying balance sheets of Sable Offshore Corp. (the “Company”) as of December 31, 2024 (Successor) and December 31, 2023 (Predecessor), the related statements of operations, changes in stockholders’ equity (deficit) / parent net investment and cash flows for 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, 2024 (Successor) and December 31, 2023 (Predecessor), and the results of its operations and its cash flows for each of 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.

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 restart production, along with the timing of ongoing construction repair efforts 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.

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 Public Company Accounting Oversight Board (United States) (“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. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

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.

/s/ Ham, Langston & Brezina, L.L.P.

We have served as the Company’s auditor since 2024.

Houston, TX

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”).

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 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 statement of stockholders' equity (deficit)/net parent investment as of December 31, 2024 (Successor).

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, an 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 sheet and statement of stockholders' equity (deficit)/net parent investment as of December 31, 2024 (Successor).

On October 31, 2024, the Public Warrants (refer to Note 7 — 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 Public Warrants that were not exercised were redeemed by the Company for $0.01 per Public Warrant. Refer to Note 7 — Warrants for additional details regarding the warrant exercises.

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. In the absence of further negotiations, Restart Production must take place prior to March 1, 2026, and the Senior Secured Term Loan must be refinanced within 240 days following such first production date.

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, and (iii) the “Pipelines” are to Pipeline Segments 324/325 (formally known as Pipeline Segments 901/903) and the other “324/325 Assets” (formally known as "901/903 Assets" and as defined in the Sable-EM Purchase Agreement).

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 the Pipelines) 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”.

The accompanying consolidated financial statements have been prepared on a basis that assumes the Company will continue as a going concern. The Company has experienced losses from operations and has negative cash flows from operations since inception. As of December 31, 2024, the Successor reported unrestricted cash of $300.4 million and an accumulated deficit of $698.3 million. The Company expects to continue to incur losses until it can restart production of the SYU Assets.

Following the Closing Date and through December 31, 2024, management has addressed capital funding needs with the First PIPE Investment, the consummation of the Business Combination, the Second PIPE Investment, and proceeds from the exercise of warrants (refer to Note 7 — Warrants for additional details regarding the warrant exercises). Management believes the Company has sufficient capital to maintain operations and complete the repairs necessary to restart production of the SYU Assets. However, the Company’s plans for production restart are contingent upon approvals from federal, state and local regulators. Additionally, if the Company’s estimates of the costs of restarting production are less than the actual amounts necessary to do so, the Company may have insufficient funds available to operate its business prior to first production and will need to raise additional capital. If the Company is unable to raise additional capital, it may be required to take additional measures to conserve liquidity, which could include, among other things, reducing overhead expenses. The Company cannot provide any assurance that new financing will be available to it on commercially acceptable terms, if at all.

Due to the remaining regulatory approvals necessary to restart production, along with the timing of ongoing construction repair efforts, 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.

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 Accounting Standards Codification 805, Business Combinations, with such transactions being accounted for as a forward merger, and SYU was deemed the Predecessor entity for accounting purposes.

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 through February 13, 2024 concurrent with the Business Combination, and a Successor period from February 14, 2024 through December 31, 2024. 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 Article 8 of 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, revenues, expenses, and cash flows of SYU. SYU has 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.

•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.

The Company is an “emerging growth company,” as defined in Section 2(a) of the Securities Act of 1933, as amended, (the “Securities Act”), as modified by the Jumpstart our Business Startups Act of 2012, (the “JOBS Act”), and it may take advantage of certain exemptions from various reporting requirements that are applicable to other public companies that are not emerging growth companies including, but not limited to, not being required to comply with the auditor attestation requirements of Section 404 of the Sarbanes-Oxley Act, reduced disclosure obligations regarding executive compensation in its periodic reports and proxy statements, and exemptions from the requirements of holding a nonbinding advisory vote on executive compensation and stockholder approval of any golden parachute payments not previously approved.

Further, Section 102(b)(1) of the JOBS Act exempts emerging growth companies from being required to comply with new or revised financial accounting standards until private companies (that is, those that have not had a Securities Act registration statement declared effective or do not have a class of securities registered under the Exchange Act) are required to comply with the new or revised financial accounting standards. The JOBS Act provides that a company can elect to opt out of the extended transition period and comply with the requirements that apply to non-emerging growth companies but any such election to opt out is irrevocable. The Company has elected not to opt out of such extended transition period which means that when a standard is issued or revised and it has different application dates for public or private companies. The Company, as an emerging growth company, can adopt the new or revised standard at the time private companies adopt the new or revised standard.

This may make comparison of the Company’s financial statements with another public company which is neither an emerging growth company nor an emerging growth company which has opted out of using the extended transition period difficult or impossible because of the potential differences in accounting standards used.

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.

Sable is managed as one reportable segment, oil and gas. To date, the Company has not generated any oil and gas revenue as it is working to restart production associated with its oil and gas properties (refer to Note 1 — Organization, Business Operations, and Going Concern). The oil and gas segment is defined based on the way in which internally reported financial information is regularly reviewed by the chief operating decision maker ("CODM"), our Chairman and Chief Executive Officer, to analyze financial performance and allocate resources. Due to the nature of the integrated SYU Assets, the overall financial and operational performance is analyzed as one operating segment. Financial information and annual operating budgets and forecasts are prepared and reviewed by the CODM at a consolidated level, making operating decisions to maximize consolidated financial results. The accounting policies of our oil and gas segment are the same as those described in our summary of significant accounting policies herein.

The CODM assesses performance for the oil and gas segment, and decides how to allocate resources in accordance with the Company’s restart efforts, based on net income (loss) that is reported in the Company's consolidated statements of operations. Net income (loss) is used to monitor budget versus actual results of the Company. The consolidated financial results are used in assessing the performance of the segment and in establishing management's compensation. The measure of segment assets is reported on the consolidated balance sheets as Total assets. The CODM uses net income (loss) generated from our oil and gas operations in determining capital allocations decisions, such as whether to reinvest profits into the SYU Assets or to utilize them for other purposes, including acquisitions.

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.

Refer to Note 11 — Fair Value Measurements for fair value disclosures.

The Company considers all short-term investments with an original maturity of three months or less when purchased to be cash equivalents.

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 a letter of credit (the "Letter of Credit") in the amount of $35.0 million to the plaintiffs' counsel 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 is pledged as collateral to JPMorgan as the issuer of the Letter of Credit. Pursuant to the terms of the Settlement Agreement, the plaintiffs' counsel in the Grey Fox Matter may draw upon the Letter of Credit at a future date upon satisfaction of certain conditions, and the funds held in the Collateral Account are legally restricted to reimburse JPMorgan for such draws, in addition to any related fees and expenses. Additionally, pursuant to the Settlement Agreement, the Company will pay interest on the $35.0 million to the Grey Fox plaintiffs at the rate earned on the Collateral Account (the "Interest Payable"); provided however that the Company is entitled to reduce the Interest Payable by the ordinary and customary expenses charged to the Company from JPMorgan as the issuer of the Letter of Credit, capped at $0.4 million (1%). On September 17, 2024, the Court approved the Settlement Agreement and the $35.0 million deposit in the Collateral Account and related Interest Payable are payable upon the final payment date, which must occur no later than June 30, 2025 (the "Final Payment Date").

Prior to the Final Payment Date, the related Interest Payable is not legally restricted and is available for the Company's use. However, the Company has adopted an accounting policy to consider interest that is both (i) earned on cash that is legally restricted in relation to a legal settlement and (ii) payable as a part of such settlement, such as the Interest Payable, restricted for presentation purposes. Accordingly, the $35.0 million deposit in the Collateral Account and the related Interest Payable are presented within the restricted cash balance presented on the Company’s consolidated balance sheet as of December 31, 2024.

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. At December 31, 2024, the Company did not experience losses on this account.

Transactions between related parties are considered to be related party transactions even though they may not be given accounting recognition. Financial Accounting Standards Board ("FASB") Accounting Standards Codification ("ASC") Topic 850, Related Party Disclosures (“ASC Topic 850”), 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, net on the accompanying consolidated balance sheet.

Cost Basis. The Company's 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 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 and transportation assets. Due to the nature of such assets, the onshore midstream facilities are presented within oil and gas properties, while the transportation assets are presented within other assets on the consolidated balance sheets.

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 to be 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.

SYU has been shut in since 2015 due to a pipeline incident but has been maintained to preserve it in an operation-ready state and thus no depreciation, depletion or amortization has been recorded by the Company since its acquisition of the SYU Assets. Depreciation, depletion, amortization, and accretion expense for oil and gas properties for the period February 14, 2024 through December 31, 2024 (Successor) consisted of asset retirement obligation related accretion expense in the amount of $9.6 million, and depreciation on other property and equipment of $0.1 million.

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 $1.2 billion as of December 31, 2024 (Successor) and $689.0 million as of December 31, 2023 (Predecessor), 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.a significant decrease in the market price of a long-lived asset;

b.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;

c.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;

d.an accumulation of project costs significantly in excess of the amount originally expected; and

e.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 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.

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. OPEC 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 proved reserve 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 periods February 14, 2024 through December 31, 2024 (Successor), January 1, 2024 through February 13, 2024 (Predecessor), or the year ended December 31, 2023 (Predecessor).

Materials and supplies are valued at the lower of cost or net realizable value.

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:

The Company’s asset retirement obligations 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.

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 ASC 480 and 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).

The Company accounts for income taxes under ASC 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. 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.

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.

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.

Restricted shares and Warrants outstanding are anti-dilutive due to the Company's net loss position and therefore have not been included in the weighted average shares calculation for the period from February 14, 2024 through December 31, 2024 (Successor).

In December 2023, the FASB issued ASU 2023-09, Income Taxes (Topic 740) - Improvements to Income Tax Disclosures. The FASB issued this ASU to enhance the transparency and decision usefulness of income tax disclosures. The amendments in this ASU address investor requests for more transparency about income tax information through improvements to income tax disclosures primarily related to the rate reconciliation and income taxes paid information. The amendments in this ASU are effective for annual periods beginning after December 15, 2024. Early adoption is permitted. The Company is currently reviewing what impact, if any, adoption will have on the Company’s financial position, results of operations or cash flows.

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 the Company's 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.

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 preliminary adjusted purchase consideration (in thousands):

*Included in the initial principal associated with the Senior Secured Term Loan.

The acquisition of the SYU Asset's is accounted for under the scope of FASB’s ASC Topic 805, Business Combinations (“ASC 805”). Pursuant to ASC 805, Sable was determined to be the accounting acquirer. The allocation of the purchase price included in the consolidated balance sheet as of December 31, 2024 (Successor) is based on the best estimate of management. To assist management in the allocation, the Company engaged valuation specialists.

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):

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 is 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.

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:

Since Flame's inception, it 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.

Since Flame's inception, it 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.

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).

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.

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 bears interest at ten percent (10.0%) per annum (computed on a 360-day year). 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"). The Senior Secured Term Loan matures on the earliest to occur of (i) the five year anniversary of the applicable effective time (such effective time, 12:00:01 a.m. (Houston Time) on January 1, 2022), (ii) 90 days after Restart Production (i.e., 240 days after first production from the wells) under and as defined in the Sable-EM Purchase Agreement or (iii) acceleration of the term loan in accordance with the terms of the Senior Secured Term Loan.

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, such approval not to be unreasonably withheld. Additionally, if we fail to restart production of the SYU Assets by March 1, 2026 (the “Restart Failure Date”), then pursuant to the Purchase and Sale Agreement dated November 1, 2022, by and among Legacy Sable, EM and MPPC relating to the Sable-EM Purchase Agreement, for 180 days thereafter, EM will have the exclusive right, but not the obligation, to require us to reassign the SYU Assets and rights to EM or its designated representative, without reimbursing us for any of our costs or expenditures (the “Reassignment Option”). If we have acquired any additional rights or assets or have developed additional improvements related to the SYU Assets, records or benefits, on EM’s request we also would be required to assign and deliver those additional rights, assets, improvements, records or benefits to EM without being reimbursed for any of our additional costs or expenses. If we are unable to restart production of the SYU Assets by the Restart Failure Date and EM exercises its Reassignment Option, EM will become the owner of substantially all of our business and we may be forced to wind-down our operations. Our ability to restart production of the SYU Assets is subject to several risks, and there is no assurance that we will be able to restart production of the SYU Assets by the Restart Failure Date.

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.

On September 6, 2024 (the "Amendment Closing Date"), the Company entered into an amendment to the Senior Secured Term Loan (the "First 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 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 Amendment Effective Date through the 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 ASC 420. As a result, the Effective Additional Principal is included within Other expense on the Company's consolidated statement of operations for the period from February 14, 2024 through December 31, 2024 (Successor).

Long-Term Debt as of December 31, 2024 (Successor) consisted of the following:

For the period from February 14, 2024 through December 31, 2024 (Successor), the Company incurred interest expense of $67.3 million, which is included as interest expense on the consolidated statement of operations and the paid-in-kind interest is accrued and included in the Senior Secured Term Loan on the consolidated balance sheet as of December 31, 2024 (Successor). 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 10.0%.

The table below reflects outstanding warrants as of December 31, 2024 (Successor):

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.

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").

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. The remaining 26,715 Public Warrants that were not exercised by the Redemption Date were redeemed by the Company for cash. 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 Topic 480”).

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 Topic 480 in the same manner as exercises of Public Warrants described above.

The Private Placement Warrants and Working Capital Warrants that remain outstanding at December 31, 2024 (Successor) are accounted for as liabilities and marked-to-market at each reporting period, with changes in fair value included as Changes in fair value of warrant liabilities in the Successor's consolidated statement of operations (refer to Note 11 — Fair Value Measurements).

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.

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 Pipelines, including claims impacting the right of way for the Pipelines (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 Pipelines, and (c) cooperate in good faith with Sable and PPC with respect to any and all steps reasonably required to restart the Pipelines 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 has 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). Following the effectiveness of the Settlement Agreement, the Company offset $0.4 million of Interest Payable with ordinary and customary expenses charged to the Company from JPMorgan as the issuer of the Letter of Credit, resulting in less than $0.1 million expense for the period from February 14, 2024 through December 31, 2024 (Successor) (refer to discussion of restricted cash in Note 2 — Significant Accounting Policies for additional details regarding the Interest Payable and the Letter of Credit).

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.

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 restart 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. Sable and PPC intend to defend the case vigorously.

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. At December 31, 2024 (Successor) 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. At December 31, 2024 (Successor) there were 89,310,996 shares issued and outstanding.

The following summarizes the shares of Common Stock outstanding immediately following the consummation of the Business Combination:

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.

As discussed in Note 1 — Organization, Business Operations, and Going Concern, on September 26, 2024, the Company issued 7,500,000 shares of Common Stock for $150.0 million in gross proceeds in connection with the Second PIPE Investment. Upon the closing of the Second PIPE Investment, an associated marketing 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 sheet and statement of stockholders' equity (deficit)/net parent investment as of December 31, 2024 (Successor).

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.

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.

On February 12, 2024, the Company’s stockholders approved a stock-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 (in thousands):

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").

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.

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 earlier of (i) the restart of production from the SYU Assets or (ii) three years after the Closing Date. The executive officer awards are subject to a three-year lock-up provision.

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 vest 12 months from the grant date.

Additionally, 2,115,936 shares of restricted Common Stock, net of forfeitures, were granted to employees of the Company following the closing of the Business Combination through December 31, 2024. These restricted shares vest on the earlier of (i) the restart of production from the SYU Assets or (ii) three years after the Closing Date. 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 is recorded as compensation expense ratably over the vesting terms. Forfeitures are recognized as they occur.

As of December 31, 2024 (Successor), 10,747,299 share-based awards were authorized and available for grant under the Successor's Incentive Plan. The following table summarizes restricted stock award activity for the period February 14, 2024 through December 31, 2024 (Successor):

The unrecognized stock-based compensation expense associated with the unvested restricted stock awards at December 31, 2024 (Successor) was $6.9 million, which is to be recognized over the weighted average remaining life of approximately three months.

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.

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 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).

Certain of the Company's financial assets and liabilities are reported at fair value on the consolidated balance sheet (Successor). 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.

The following table presents information about the Company’s assets and liabilities that are measured at fair value on a recurring basis at December 31, 2024 (Successor), and indicates the fair value hierarchy of the valuation inputs the Company utilized to determine such fair value:

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 2 or Level 3 from other levels in the fair value hierarchy during 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 as of December 31, 2023 (Predecessor) or for the period from January 1, 2024 to February 13, 2024 (Predecessor) and the year ended December 31, 2023 (Predecessor).

As of December 31, 2024 (Successor), investments in the Company's money market accounts consisted of $300.5 million in demand deposit accounts (and are therefore not reflected in the table above).

The carrying values of accounts payable and accrued expenses are considered to be representative of their respective fair values due to the short-term maturities of those instruments (and are therefore not reflected in the table above).

As of December 31, 2024 (Successor), 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.

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 statement of operations for the period from February 14, 2024 through December 31, 2024 (Successor).

As Private Placement Warrants held by FL Co-Investment, LLC ("FL Co-Investment") and Intrepid Financial Partners, L.L.C. ("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.

The following table provides quantitative information regarding Level 3 inputs used to determine the fair values of Private Placement Warrants held by FL Co-Investment and Intrepid Financial Partners as of December 31, 2024 (Successor).

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 FL Co-Investment and Intrepid Financial Partners, as of December 31, 2024 (Successor).

The Company follows the asset and liability method of accounting for income taxes under FASB ASC 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:

The components of the income tax benefit were as follows:

As of December 31, 2024 (Successor), the Company had $195.6 million U.S. federal net operating loss carryovers available to offset future taxable income. The Company had $184.8 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 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 NOLs that would have been utilized if not for AB 167.

A reconciliation of the federal income tax rate to the Company’s effective tax rate for the periods presented is as follows: