SOC 10-K & 10-Q changes, risk factors and insider trading

•The requirements to resume petroleum transportation through Pipeline Segments 324 and 325 include those set forth in a Consent Decree with federal and state agencies. While the operator of the Pipeline Segments believes it has satisfied all of the conditions to resuming petroleum transportation included under the Consent Decree, there is no assurance that we will be successful in resuming petroleum transportation through Pipeline Segments 324 and 325 and recommence oil sales in a timely manner.

•In order to commence operations pursuant to the OS&T Strategy, we will require clearances and permitting, including from BOEM.

•The timing of returning wells to production is subject to risks that may cause delays and initial production rates are expected to decline.

•Restrictive covenants in the Senior Secured Term Loan or any future agreements governing our indebtedness could limit our growth and our ability to finance our operations, fund our capital needs, respond to changing conditions and engage in other business activities that may be in our best interests.

Production from the SYU Assets was suspended as a result of the Line 901 incident and consequent suspension of service. In May 2025 we restarted production from the SYU Assets and resumed petroleum transportation through the Santa Ynez Pipeline System. However, absent OS&T offtake, our business depends on resuming petroleum transportation through Pipeline Segments 324 and 325. We are required to satisfy certain requirements related to Pipeline Segments 324 and 325 before we can recommence oil sales. Such requirements include conditions set forth in a U.S. federal district court Consent Decree executed by Plains and relevant U.S. and State of California government agencies. Sable believes all such requirements have been satisfied. However, there is no guarantee that the State of California government agencies will agree that such requirements have been met, which may delay or interrupt our operations and limit our growth and revenue, or may impact our ability to repay or refinance the Senior Secured Term Loan. On January 14, 2026, both Plains and the Company submitted letters to the United States Department of Justice Environment and Natural Resources Division and the California Office of the Attorney General Natural Resources Law Section regarding the termination of the Consent Decree because the prerequisites for termination have been satisfied, however, there is no guarantee these parties will agree the prerequisites have been satisfied and terminate the Consent Decree. See “Risk Factors—Under the terms of the Senior Secured Term Loan, the loans thereunder will mature on the earlier of (i) March 31, 2027 or (ii) the date falling 90 days after first sales of Hydrocarbons, and the terms on which we will be able to refinance the Senior Secured Term Loan will depend on then-prevalent market conditions.”

In order to commence operations pursuant to the OS&T Strategy, we will require clearances and permitting, including from BOEM.

We may experience delays in obtaining or be unable to obtain required permits, including authorizations necessary to recommence oil sales pursuant to the OS&T Strategy, which may delay or interrupt our operations and limit our growth and revenue, or may impact our ability to repay or refinance the Senior Secured Term Loan. In particular, prior to implementation of the OS&T Strategy, regulatory authorizations are required, including clearance from BOEM. If we do not receive regulatory clearances in connection with the OS&T Strategy in a timely manner, we may not be able to reach commercial sales on our estimated timeline of the fourth quarter of 2026.

While the previous operator of the SYU was able to utilize the OS&T Strategy to process SYU production in federal waters from 1981 to 1994 under previously issued permits, there is no assurance that we will be able to successfully obtain the agency clearance or permits required to recommence oil sales pursuant to the OS&T Strategy or that no additional state or federal clearances or permits will be required in the future.

The timing of returning wells to production is subject to risks that may cause delays and initial production rates are expected to decline.

We returned a number of wells to production on Platform Harmony beginning in May 2025, and we expect to return a number of additional wells to production on Platforms Harmony, Heritage and Hondo. Operations on offshore platforms are subject to numerous risks and potential delays.

In addition, oil and natural gas wells typically exhibit a decline in production over time. Accordingly, initial production rates as our wells are brought back into production are expected to be higher than the rate of sustained production at such wells. There is substantial uncertainty regarding the amount and timing of production decline from recently reopened wells.

We are currently evaluating and pursuing the OS&T Strategy and have curtailed certain capital expenditures relating to the Santa Ynez Pipeline System. If in the future we are permitted to conduct commercial sales using such assets, we intend to do so and would incur such curtailed Santa Ynez Pipeline System costs, in addition to the costs related to the pursuit of the OS&T Strategy. Accordingly, our assumptions and estimates may change in future periods based on future events and total costs may materially increase. Therefore, we can provide no assurance that we will not have to incur additional costs in future periods that are significantly higher than our estimated costs to recommence oil sales.

Under the terms of the Senior Secured Term Loan, the loans thereunder will mature on the earlier of (i) March 31, 2027 or (ii) the date falling 90 days after first sales of Hydrocarbons, and the terms on which we will be able to refinance the Senior Secured Term Loan will depend on then-prevalent market conditions.

The Senior Secured Term Loan will mature on the earlier of (i) March 31, 2027 or (ii) the date falling 90 days after first sales of Hydrocarbons (as defined in the Senior Secured Term Loan). Our ability to obtain any refinancing of the Senior Secured Term Loan, and the terms of any such refinancing, will depend on market conditions at the time of any such refinancing. There can be no assurance that we will be able to obtain such refinancing on terms commercially acceptable to us, or at all.

Changes in tax law may materially adversely affect our financial condition, results of operations and cash flows.

New income, sales, use or other tax laws, statutes, rules, regulations or ordinances are continuously being enacted, proposed, interpreted, changed, or modified, any of which could adversely affect our business operations and financial performance. For example, on July 4, 2025, the One Big Beautiful Bill Act (the “OBBBA”), was signed into law in the United States, which includes revisions to key business tax provisions such as the reinstatement of bonus depreciation deductions for qualified property, the restoration of an EBITDA-based business interest expense limitation, the revision and expansion of certain renewable energy tax credits that were previously available under the IRA and the implementation of changes relating to the computation of certain taxes in respect of non-US activities. Since future changes to tax legislation and regulations are unknown, we cannot predict the ultimate impact such changes may have on our business. To the extent that these or other changes have a negative impact on us or our consumers, including as a result of related uncertainty, these changes may materially and adversely impact us, our business, financial condition, results of operations and cash flow.

On August 16, 2022, President Biden signed into law the IRA, which targets methane from oil and gas sources by imposing an applicable “waste emissions charge” on petroleum and natural gas production facilities that exceed a specified waste emissions threshold and requiring the reporting of emissions that exceed 25,000 metric tons of carbon dioxide equivalent per year. On November 18, 2024, the EPA published a final rule to implement this waste emissions charge as required by the IRA. However, on March 14, 2025, Congress a joint resolution under the Congressional Review Act disapproved EPA’s final rule, and EPA removed the implementing regulations in May 2025. Subsequently, Congress amended the Clean Air Act in July 2025 to delay the start of this methane emissions charge until emissions reported for calendar year 2034 and to constrain EPA’s implementation authority and funding for that program.

On February 12, 2026, EPA rescinded its 2009 “Endangerment Finding” under Clean Air Act Section 202(a). In the rescission rule, EPA determined that Clean Air Act Section 202(a)(1) does not authorize EPA to prescribe emission standards in response to global climate change for multiple reasons, and accordingly EPA rescinded GHG emission standards and related regulatory provisions for new vehicles and engines. It is expected that this rescission rule will be challenged in federal court.

A discussion of the year ended December 31, 2024, compared to the year ended December 31, 2023, has been reported previously under “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report on Form 10-K for the year ended December 31, 2024, filed with the SEC on March 17, 2025.

We are a Houston-based independent upstream company focused on responsibly developing the Santa Ynez Unit in federal waters offshore California. Our team has decades of experience safely operating in California and creating value for stakeholders. We have one reportable segment, the oil and gas segment, refer to Note 1—Organization, and Business Operations and Going Concern and Note 2—Significant Accounting Policies in Item 8. Financial Statements and Supplementary Data of this report for further discussion.

For the purposes of this discussion, periods on or before February 13, 2024 reflect the financial position, results of operations and cash flows of SYU prior to the Business Combination, referred to herein as the “Predecessor,” and periods beginning on or after February 14, 2024 reflect the financial position, results of operations and cash flows of the Company as a result of the Business Combination, referred to herein as the “Successor.”

2025 Operational and Financial Highlights

•On May 19, 2025, we announced that (i) as of May 15, 2025, we had restarted production at the Santa Ynez Unit and begun flowing oil production to Las Flores Canyon and (ii) we completed our anomaly repair program on Pipeline Segments 324 and 325 of the Santa Ynez Pipeline System as specified by the Consent Decree.

•On May 23, 2025, we closed an upsized underwritten public offering of 10,000,000 shares of Common Stock at a public offering price of $29.50 per share. The gross proceeds from the offering, before deducting discounts and commissions and estimated expenses, were approximately $295.0 million.

•On May 28, 2025, we announced that we successfully completed hydrotests of all segments of the Santa Ynez Pipeline System, satisfying the final operational condition to resume petroleum transportation through Pipeline Segments 324 and 325 as outlined in the Consent Decree.

•As an alternative to the Santa Ynez Pipeline System, we announced that we are also pursuing an OS&T strategy to provide access to domestic and global markets via shuttle tankers for federal crude oil produced from the Santa Ynez Unit in the Pacific Outer Continental Shelf Area.

•On November 10, 2025, we entered into subscription agreements to issue 45,454,546 shares of Common Stock in a private placement to institutional investors at a purchase price of $5.50 per share, raising $250.0 million in gross proceeds.

•On November 24, 2025, we satisfied all conditions to effectiveness of the Second Amendment to the Senior Secured Term Loan, thereby extending the maturity date of the Senior Secured Term Loan to the earlier of (i) March 31, 2027 or (ii) the date falling 90 days after first sales of hydrocarbons. The Second Amendment increased the interest rate from ten percent (10%) per annum to fifteen percent (15%) per annum, compounded annually.

•On December 17, 2025, PHMSA notified us that it concurred with our determination that the Santa Ynez Pipeline System is an interstate pipeline facility under the Pipeline Safety Act, pursuant to which PHMSA is vested with exclusive regulatory authority over interstate pipelines. In its notification, PHMSA additionally states that it considers the Santa Ynez Pipeline System to be an “active” pipeline according to PHMSA regulations.

•On December 23, 2025, PHMSA issued an emergency special permit for segments of the interstate Santa Ynez Pipeline System (specifically Pipeline Segments 324 and 325), related to cathodic protection and seam weld corrosion along Pipeline Segments 324 and 325.

•We reported a net loss of $410.2 million, primarily attributable to production restart related operating expenses, general & administrative expenses, and non-cash interest expense, partially offset by a non-cash change in fair value of warrant liabilities.

•We ended the year with short-term outstanding debt of $921.6 million, inclusive of paid-in-kind interest, and a cash and cash equivalents balance of $97.7 million.

Beginning in 1968 and over the course of 14 years, EM consolidated more than a dozen offshore federal oil leases and organized them into a streamlined production unit known as the SYU. The SYU remained in continuous operation until 2015. In May 2015, Pipeline Segment 324 (then known as “Line 901”) experienced a leak while operated by Plains. The SYU suspended production after the Line 901 incident and the facilities were maintained in a safe state. On May 19, 2025, the Company announced that as of May 15, 2025, it had restarted production at the SYU and begun flowing oil production from six wells at SYU’s Platform Harmony to the Company’s storage and processing facilities at LFC.

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

Outlook

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

Recommencing Oil Sales

Our near-term outlook is highly dependent on our ability to recommence oil transportation through the Santa Ynez Pipeline System. As previously noted, PHMSA confirmed that the Santa Ynez Pipeline System is classified as active interstate pipeline subject to federal jurisdiction under the Pipeline Safety Act. Additionally, we received an Emergency Special Permit from PHMSA related to cathodic protection and seam weld corrosion along Pipeline Segments 324 and 325. This permit is conditional in nature and requires ongoing compliance with specified operational and reporting obligations, including enhanced integrity management, inspection, testing, and monitoring requirements. The emergency special permit expired on February 21, 2026. By letter dated February 13, 2026 to PHMSA, the Company committed to continued compliance with the conditions of the emergency special permit until PHMSA makes a determination on the Company’s application for Special Permit (which was submitted on January 22, 2026).

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

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

We cannot generate material oil sales without a functioning transportation solution. As a result, any delay, suspension, or revocation of PHMSA’s approvals, or any operational issue encountered during commissioning Pipeline Segments 324 and 325, could materially delay the resumption of commercial oil sales and adversely affect future revenues and cash flows. “Risk Factors—We are subject to complex federal, state, local and other laws, regulations and permits that could adversely affect the cost, manner, ability or feasibility of conducting our operations.”

Offshore Storage and Treating Vessel (OS&T) Alternative

In parallel with pursuing oil sales via Santa Ynez Pipeline System, we continue to evaluate an OS&T vessel as a potential alternative pathway to market crude oil. Under this concept, produced fluids would be processed offshore, stored on a floating vessel, and periodically offloaded to shuttle tankers for delivery to third-party purchasers.

The OS&T Strategy is significantly more capital-intensive than the Santa Ynez Pipeline System, requiring an estimated capital investment of approximately $475.0 million, inclusive of vessel acquisition, configuration, offshore integration, regulatory compliance, and related infrastructure. Based on current assessments, we do not expect to commence commercial oil sales under an OS&T Strategy until approximately the fourth quarter of 2026, assuming timely execution, regulatory approvals, and availability of capital.

While the OS&T Strategy could reduce reliance on the Santa Ynez Pipeline System, which may enhance our marketing strategy going forward by providing flexibility to sell production to additional purchasers through the OS&T rather than being limited to a purchaser under a pipeline-only sales configuration, it presents substantial execution, financing, regulatory, and operational risks. These risks include vessel availability, permitting complexity, higher operating costs, exposure to marine operational risks, and uncertainty regarding the economic returns relative to pipeline transportation. We have not made a final investment decision with respect to an OS&T vessel, and there can be no assurance that such a project would be pursued, financed, or completed on acceptable terms, if at all. See “Risk Factors—Risks Associated with Our Operations—In order to commence operations pursuant to an OS&T offtake strategy, we will require clearances and permitting, including from BOEM” and “Risk Factors—Risks Associated with Our Operations—Our assumptions and estimates regarding the total costs associated with recommencing oil sales may be inaccurate.”

Legal and Regulatory Environment

The Company’s assets are located in California, a jurisdiction with a complex regulatory framework and heightened environmental oversight. PHMSA’s approvals related to the Santa Ynez Pipeline System have been challenged by third parties through litigation, and the outcome of such proceedings is uncertain. Adverse court rulings, including the issuance of injunctions or stays, could delay or prevent pipeline operations regardless of the Company’s technical readiness.

In addition to federal oversight, the Company remains subject to state and local regulatory agencies, including the California Geologic Energy Management Division and other environmental and land-use authorities. While these agencies do not directly regulate interstate pipeline safety, their actions may affect related permits, inspections, or operational approvals, which could influence the timing, cost, or feasibility of both pipeline and OS&T-based solutions.

We are involved in various legal and regulatory proceedings, including matters related to our pipeline operations and permitting activities, which are at various stages of resolution; while these matters are subject to inherent uncertainty, we currently believe that the outcomes are not probable of resulting in a material loss and, accordingly, no litigation-related accruals have been recorded as of the reporting date. Refer to Part II, Item 8, “Financial Statements and Supplementary Data – Notes to the Consolidated Financial Statements, Note 8—Commitments and Contingencies” for further information regarding ongoing litigation.

Production Ramp-Up and Operational Execution

Assuming a transportation solution is established, our future performance will depend on our ability to safely ramp up offshore production, manage operating costs, and maintain asset integrity following an extended period of curtailed operations. Restarting production from offshore facilities involves inherent operational risks, including mechanical failures, unplanned downtime, and higher-than-expected maintenance or remediation costs, any of which could adversely affect production volumes and operating margins.

Capital and Financing Requirements

Until sustained commercial oil sales are achieved, our liquidity will depend on available cash balances, access to raise additional capital from investors, and the timing of expenditures related to regulatory compliance, litigation, offshore facility maintenance, and potential alternative transportation solutions. The OS&T vessel alternative, in particular, would require substantial external financing or strategic arrangements and could materially increase our leverage or dilution. There can be no assurance that such financing would be available on acceptable terms, or at all.

Capital Expenditures. During 2025, we funded $417.6 million in development and other property, plant and equipment expenditures primarily by utilizing net cash provided by our financing activities and cash on hand.

We currently estimate no remaining start-up expenses to recommence oil sales via the Santa Ynez Pipeline System, other than applicable legal expenses. Upon resuming petroleum transportation through the Santa Ynez Pipeline System, we anticipate approximately $100.0 million to $200.0 million in additional post-sales capital expenditures for 2026, primarily related to facilities, pipeline ramp-up activities, and other property, plant and equipment, depending on timing and excluding any OS&T-related capital expenditures. Alternatively, if we elect to pursue the OS&T Strategy, total anticipated 2026 capital expenditures are estimated to be approximately $475.0 million, including costs to acquire and purchase the vessel in addition to incremental investments associated with related infrastructure. Depending on the timing and outcome of regulatory approvals and the execution of commercial arrangements, we could incur capital expenditures beyond these ranges. We cannot provide any assurances that our assumptions used to estimate our liquidity requirements, our anticipated cost savings or reductions, or the costs required to achieve operations under the OS&T Strategy will be correct, as we have not previously undertaken such actions and as a consequence, our ability to predict such amounts is uncertain and may be impacted by factors outside of our control.

Debt Financing. As of December 31, 2025, we had gross indebtedness of $921.6 million outstanding under the Senior Secured Term Loan, (refer to Note 6—Debt to the consolidated financial statements). On November 3, 2025, we entered into the Second Debt Amendment, which became effective on November 24, 2025 following the completion of the Third PIPE Investment and satisfaction of all conditions to effectiveness. Pursuant to the Second Debt Amendment, the maturity date of the Senior Secured Term Loan was extended to the earlier of (i) March 31, 2027 or (ii) 90 days after the Company’s first sales of hydrocarbons. In connection with the Second Debt Amendment, the interest rate on the Senior Secured Term Loan increased from ten percent (10.0%) per annum to fifteen percent (15.0%) per annum, computed on a 360-day year, compounded annually, and payable in arrears on January 1 of each year. Notwithstanding the maturity extension, the Senior Secured Term Loan is classified as a current liability on the Company’s consolidated balance sheet as of December 31, 2025 due to management’s expected maturity date based on anticipated first sales from SYU.

After we are able to recommence oil sales and improve our operating cash flows, we expect to pursue a refinancing of the Senior Secured Term Loan, which may include a new credit facility, term notes, or other debt capital market transactions. We believe that demonstrating sustained oil sales and cash flow generation in the future could improve our access to financing and potentially reduce our overall cost of capital. Any refinancing would be subject to market conditions, lender requirements, regulatory developments, and other factors outside our control. There can be no assurance that such a refinancing will be completed on favorable terms, or at all.

The requirements to transport petroleum through Pipeline Segments 324 and 325 include those set forth in a Consent Decree with federal and state agencies, and we believe the Company has substantially complied with such requirements. While we also believe that the prerequisites for terminating the Consent Decree have been satisfied, there is no assurance that the Consent Decree will be terminated or, in the alternative, modified.

In May 2015, Pipeline Segment 324 (then known as “Line 901”) experienced a leak while operated by Plains All American Pipeline, L.P. (the “Line 901 Incident”). Production from the SYU Assets was suspended as a result of the Line 901 Incident and consequent suspension of service. In May 2025 we restarted production from the SYU Assets and resumed petroleum transportation through the SYPS. In March 2026, in compliance with the DPA Order, we resumed petroleum transportation through Pipeline Segments 324 and 325 and subsequently resumed oil sales from the SYU Assets. We are required to satisfy certain requirements related to Pipeline Segments 324 and 325 in connection with recommencing oil sales. Such requirements include conditions set forth in a U.S. federal district court Consent Decree executed by Plains and relevant U.S. and State of California government agencies. Sable believes all such requirements have been satisfied. On January 14, 2026, both Plains and the Company submitted letters to the United States Department of Justice Environment and Natural Resources Division and the California Office of the Attorney General Natural Resources Law Section regarding the termination of the Consent Decree because the prerequisites for termination have been satisfied.

On March 16, 2026, OSFM and State Parks (“California Plaintiffs”) filed an ex parte Emergency Motion to Enforce Consent Decree in United States, et al. v. Plains All American Pipeline, L.P., et al., Case No. 2:20-cv-02415 (C.D. Cal) in U.S. District Court seeking an order enforcing the Consent Decree and ordering Sable not to restart or continue operating Pipeline Segments 324 and 325 of the SYPS. The Department of Justice (“DOJ”), on behalf of the United States of America (the “United States”), filed its opposition to California Plaintiffs’ Ex Parte Motion on March 18, 2026. On March 23, 2026, the Court denied the California Plaintiffs’ Ex Parte Motion, finding “no evidence to support a showing of irreparable prejudice” to California Plaintiffs’ cause if required to seek relief through a regularly noticed motion. On March 30, 2026, the DOJ, on behalf of the United States, filed a Motion to Terminate or Modify the Consent Decree. Sable and PPC, as nonparties to the cases, filed a Memorandum in Support of the United States’ motion on April 1, 2026, and filed a combined brief in opposition to California’s Motion to Enforce and reply brief in support of the United States’ Motion to Terminate or Modify the Consent Decree on April 27, 2026. A hearing was held on California Plaintiffs’ Motion to Enforce Consent Decree and the United States’ Motion to Terminate or Modify the Consent Decree on June 8, 2026, and the Court ordered supplemental briefing, which was completed by the parties June 25, 2026.

There is no guarantee that the Court will grant the DOJ’s Motion to Terminate or Modify the Consent Decree. If the Consent Decree is not modified or otherwise terminated, State of California government agencies which are parties to the Consent Decree have alleged that the Company has not satisfied its requirements, which may delay or interrupt our operations and limit our growth and revenue, which could have a material adverse effect on our business and financial condition or may impact our ability to service and repay or refinance the New Senior Secured Credit Facilities or the Convertible Notes.

The DPA Order is subject to legal challenges and any adverse ruling could require us to cease or curtail petroleum transportation through the SYPS, which could have a material adverse effect on our results of operations, financial condition, and ability to service the notes.

Our ability to transport petroleum through Pipeline Segments 324 and 325, and accordingly our ability to generate revenue from oil sales, is currently based on the requirements set forth in the DPA Order.

On March 30, 2026, the State of California filed a Complaint for Declaratory and Injunctive Relief in the U.S. District Court for the Central District of California (State of California v. Chris Wright, et al., Case No. 2:26-cv-03396), alleging that the DPA Order violates provisions of the Administrative Procedure Act and the U.S. Constitution. The Court held a hearing on the State’s Motion for Preliminary Injunction on June 8, 2026, and ordered supplemental briefing. On July 20, 2026, the State filed a First Amended Complaint. The outcome and timeline of this litigation, including with respect to the supplemental briefing ordered by the Court, remain uncertain.

If the State of California’s challenge, or any future legal challenge, to the DPA Order is successful, including through the granting of a preliminary injunction or other injunctive relief, the requirement that we transport petroleum through Pipeline Segments 324 and 325 could be vacated, enjoined, or otherwise rendered ineffective, and we could be required to cease or curtail petroleum transportation through the SYPS. Any such cessation or curtailment would materially reduce or terminate our ability to sell oil produced from the SYU Assets, which could have a material adverse effect on our business, results of operations, financial condition, and our ability to service and repay or refinance the New Senior Secured Credit Facilities or the notes.

In addition, even if the current challenge is resolved favorably, we cannot assure you that additional legal challenges to the DPA Order will not be brought by other parties in the future. The State of California or its agencies may also pursue additional regulatory, legislative, or enforcement actions directed at impeding pipeline operations on the SYPS, including through further enforcement proceedings by the Coastal Commission, the enactment of additional legislation similar to SB 237, or other state or local measures. Any such actions, or the threat thereof, could create additional uncertainty around our operations, increase our legal and compliance costs, and further impair our ability to transport petroleum through the SYPS, any of which could have a material adverse effect on our business, financial condition, results of operations, and our ability to service the notes.

The timing of returning wells to production is subject to risks that may cause delays and initial production rates are expected to decline.

We returned a number of wells to production on Platform Harmony beginning in May 2025 and Platform Heritage beginning in April 2026, and we expect to return a number of additional wells to production on Platforms Harmony, Heritage and Hondo. Operations on offshore platforms are subject to numerous risks and potential delays.

In addition, oil and natural gas wells typically exhibit a decline in production over time. Accordingly, initial production rates as our wells are brought back into production are expected to be higher than the rate of sustained production at such wells. There is substantial uncertainty regarding the amount and timing of production decline from recently reopened wells.

Our assumptions and estimates regarding the total costs associated with the OS&T Strategy may be inaccurate.

If pursued, we currently estimate remaining start-up expenses associated with the OS&T Strategy of approximately $475.0 million to recommence offshore oil sales, excluding corporate working capital. The expenditures will primarily be directed towards the procurement of a suitable vessel and necessary upgrade and installation costs with respect to such vessel and our platforms, and obtaining necessary regulatory approvals. This estimate of costs to recommence offshore oil sales considers currently available facts and presently enacted laws and regulations, but it is subject to uncertainties associated with the assumptions that we have made. For example, because the markets for OS&T vessels and vessel refurbishment and upgrading are competitive, and our estimates for the cost of procurement and planned upgrades are based on our understanding of the relevant markets and current supply of suitable vessels and contracts, the actual cost of such a vessel and the related upgrades may exceed our expectations. In addition, the costs of equipment, repairs and maintenance, the costs of operating personnel, the costs to obtain governmental approvals, and legal, consulting and other professional expenses could turn out to be higher than we have estimated. In addition, if we pursue the OS&T Strategy, we will need to procure additional financing, which may not be available on acceptable terms or at all. We also may experience increases in costs and delays. In addition, the New Senior Secured Credit Facilities limit our capital expenditures, our general and administrative costs and our ability to incur additional debt, and accordingly we may require consent of the lenders in order to complete the capital expenditures and general and administrative costs necessary to implement the OS&T strategy and/or incur additional indebtedness to fund such expenditures.

Our assumptions and estimates regarding the total costs associated with the Buoy Strategy may be inaccurate.

If we pursue the Buoy Strategy, we currently estimate remaining start-up expenses of approximately $125.0 million to recommence offshore oil sales via the Buoy Strategy, excluding corporate working capital. The expenditures will primarily be directed towards preparing for the implementation of the Buoy Strategy, including installation costs with respect to such buoy and laying flowlines from our platforms, obtaining necessary regulatory approvals and recommencing offshore oil sales. This estimate of costs to commence offshore oil sales via the Buoy Strategy considers currently available facts and presently enacted laws and regulations, but it is subject to uncertainties associated with the assumptions that we have made. For example, because our estimates for the cost of installation are based on our understanding of the relevant markets and current supply of materials and contracts, the actual cost of a buoy and the installation thereof may exceed our expectations. In addition, the costs of equipment, repairs and maintenance, the costs of operating personnel, the costs to obtain governmental approvals, and legal, consulting and other professional expenses could turn out to be higher than we have estimated. In addition, if we pursue the Buoy Strategy, we will need to procure additional financing, which may not be available on acceptable terms or at all. We also may experience increases in costs and delays.

We are subject to complex federal, state, local and other laws, regulations and permits that could adversely affect the cost, manner, ability or feasibility of conducting our operations.

Our oil and natural gas development and production operations are subject to complex and stringent laws and regulations administered by governmental authorities vested with broad authority relating to the exploration for and the development, production and transportation of oil, natural gas, and NGLs. To conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities. We must comply with a number of requirements related to the SYPS, including Pipeline Segments 324 and 325, which include those 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. While we believe we are in compliance with the Consent Decree, State of California government agencies which are parties to the Consent Decree alleged that the Company has not satisfied its requirements, which may delay or interrupt our operations and limit our growth and revenue, or may impact our ability to service and repay or refinance the New Senior Secured Credit Facilities or the notes. In order to commence offshore oil sales pursuant to the OS&T Strategy or the Buoy Strategy, if pursued, we would need to obtain regulatory authorizations, including clearance from BOEM. We may incur substantial costs in order to maintain compliance with these existing laws and regulations, and we may experience delays in procuring required approvals, which may increase our costs or delay our ability to produce revenue. Failure to comply with laws and regulations or to obtain necessary regulatory clearances applicable to our operations, including any evolving interpretation and enforcement by governmental authorities, could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Our oil, natural gas, and NGLs development and production operations are also subject to stringent and complex federal, state and local laws and regulations governing the release or discharge of materials into or through the environment, worker health and safety aspects of our operations, or otherwise relating to property rights, environmental protection, resource protection, and damage to natural resources. These laws and regulations may impose numerous obligations applicable to our operations, including regulated drilling activities; operation, repair and maintenance of the Santa Ynez Pipeline System; potential installation and use of an OS&T or the Buoy; the restriction of types, quantities and concentrations of materials that can be released or discharged into or through the environment; required authorizations for, or the limitation or prohibition of, drilling, production and transportation activities on certain lands lying within wilderness, wetlands, seismically active, park and recreation areas and other protected or preserved areas; the application of specific health and safety criteria addressing worker protection; and the imposition of substantial liabilities for pollution and natural resources damages potentially resulting from our operations. The EPA, BOEM, BSEE, PHMSA, OSFM, Coastal Commission, CDFW, Regional Board, the SLC, State Parks and numerous other governmental authorities have the authority to enforce compliance with these laws and regulations and the permits or other authorizations issued by them, often requiring difficult and costly compliance measures or corrective actions. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil or criminal penalties, the imposition of investigatory or remedial obligations, injunctive and mitigation relief, the suspension or revocation of necessary permits, licenses and authorizations, the requirement that additional pollution controls be installed and, in some instances, the issuance of orders limiting or prohibiting some or all of our operations. We may also experience delays in obtaining or be unable to obtain required permits which may delay or interrupt our operations and limit our growth and revenue, or may impact our ability to service and repay or refinance the New Senior Secured Credit Facilities or the notes. On March 29, 2026, the Company initiated oil sales upon filling the SYPS, which accelerated the maturity date of the Existing Senior Secured Term Loan to June 26, 2026. On June 22, 2026, the Company and Exxon entered into the Existing Senior Secured Term Loan Amendment, which extended the maturity date of the Existing Senior Secured Term Loan to the earlier to occur of (a) July 24, 2026, and (b) the acceleration of the Existing Senior Secured Term Loan following any Event of Default (as defined therein).

Under certain environmental laws that impose strict as well as joint and several liability, we may be required to remediate or conduct other response actions at or in relation to contaminated properties currently owned or operated by us or facilities of third parties that received waste generated by our operations regardless of whether such contamination resulted from the conduct of others or from the consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. In addition, claims for damages to persons or property, including natural resources, may result from the environmental, health and safety impacts of our operations. Moreover, public interest in the protection of the environment has increased in recent years. New laws and regulations continue to be enacted, particularly at the state level, and environmental legislation and regulations applied to the crude oil and natural gas industry could continue, resulting in increased costs of doing business and consequently affecting profitability. Additionally, any changes in environmental regulations related to biodiversity protection could impose further operational constraints and costs. To the extent laws are 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.

Environmental groups may initiate litigation and take other actions to delay or prevent us from obtaining or maintaining required approvals.

Environmental groups have had increasing success in limiting oil and gas production by appealing to regulatory agencies, filing lawsuits and applying political pressure. We are required to obtain and maintain a series of permits or regulatory approvals from, federal and state agencies, including PHMSA and BOEM. The laws and procedures governing these and other permits and regulatory approvals often allow third parties, including environmental groups, to challenge the draft permits and/or permit approvals through the relevant agencies and other administrative appeal processes. These groups may also file lawsuits that delay or prevent the issuance of the approvals through an injunction and/or prevailing on the legal merits or a ruling that additional approval is required. In addition, these groups may leverage the increased public attention and concern with respect to climate change and other environmental and social impacts in order to encourage government officials to withhold or delay the necessary approvals or require additional approvals. There is no assurance that these groups will not be successful in delaying or preventing us from obtaining or maintaining the required approvals through litigation or other actions.

In order to commence offshore oil sales pursuant to the OS&T Strategy or the Buoy Strategy, we will require clearances and permitting, including from BOEM.

If we choose to implement the OS&T Strategy or the Buoy Strategy, we may experience delays in obtaining or be unable to obtain required permits, including authorizations necessary to recommence offshore oil sales pursuant to the OS&T Strategy or the Buoy Strategy, which may delay or interrupt our operations and limit our growth and revenue or may impact our ability to service and repay or refinance the New Senior Secured Credit Facilities or the notes. In particular, prior to implementation of the OS&T Strategy or the Buoy Strategy, regulatory authorizations are required, including clearance from BOEM. If we do not receive regulatory clearances in connection with the OS&T Strategy or the Buoy Strategy in a timely manner, we may not be able to reach commercial sales pursuant to the OS&T Strategy or the Buoy Strategy.

While the previous operator of the SYU was able to utilize the OS&T Strategy to process SYU production in federal waters from 1981 to 1994 under previously issued permits, there is no assurance that we will be able to successfully obtain the agency clearance or permits required to recommence oil sales pursuant to the OS&T Strategy or that no additional state or federal clearances or permits will be required in the future.

We are required to hedge our expected proved developed production pursuant to the terms of the New Senior Secured Credit Facilities, and such hedging activities may expose us to counterparty risk, limit potential gains from increasing commodity prices, and expose us to cash losses.

The New Senior Secured Credit Facilities required us to (x) hedge within five business days of the closing of the New Senior Secured Credit Facilities, reasonably anticipated production of crude oil from proved, developed and producing oil and gas properties for each calendar month through December 15, 2028 and (y) on a go forward basis, use commercially reasonable efforts to hedge substantially all of the anticipated production of crude oil from proved, developed and producing oil and gas properties through December 15, 2028, which may limit our ability to realize the benefits of higher commodity prices.

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 commodity hedging strategy may not protect us from significant declines in prices received for our future production. In addition, our commodity derivative contracts expose us to risk of financial loss if a counterparty fails to perform under a commodity derivative contract. We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform. Even if we do accurately predict sudden changes, our ability to negate the risk may be limited depending upon market conditions.

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 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 cessation of production due to regulatory or legal rulings or challenges or otherwise) 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 and financial condition.

Our indebtedness and liabilities could limit the cash flow available for our operations, expose us to risks that could adversely affect our business, financial condition and results of operations and impair our ability to satisfy our obligations under the notes.

As of June 30, 2026, on an as adjusted basis after giving effect to the 2026 Refinancing Transactions, we have (i) $1.02 billion principal amount of outstanding indebtedness, including $675.0 million principal amount of secured indebtedness under the Term Loan B which would rank effectively senior to the notes to the extent of the value of the collateral securing such indebtedness. In addition, upon consummation of the 2026 Refinancing Transactions, the Senior Revolver will permit secured indebtedness for secured hedging arrangements, which would rank effectively senior to the notes to the extent of the value of the collateral securing such indebtedness. Upon establishment of a borrowing base, any borrowings under the Senior Revolver would also rank effectively senior to the notes to the extent of the value of the collateral securing such indebtedness. We may also incur additional indebtedness to meet future financing needs. Our indebtedness could have significant negative consequences for our security holders and our business, results of operations and financial condition by, among other things:

•increasing our vulnerability to adverse economic and industry conditions;

•limiting our ability to obtain additional financing (which may include indebtedness that would be used for future capital expenditures, including with respect to the OS&T Strategy and the Buoy Strategy);

•requiring the dedication of a substantial portion of our cash flow from operations to service our indebtedness, which will reduce the amount of cash available for other purposes;

•limiting our flexibility to plan for, or react to, changes in our business;

•diluting the interests of our existing stockholders as a result of issuing shares of our common stock upon conversion of the notes; and

•placing us at a possible competitive disadvantage with competitors that are less leveraged than us or have better access to capital.

Our business may not generate sufficient funds, and we may otherwise be unable to maintain sufficient cash reserves, to pay amounts due under our indebtedness, including the notes, and our cash needs may increase in the future.

Restrictive covenants in the New Senior Secured Credit Facilities or any future agreements governing our indebtedness could limit our growth and our ability to finance our operations, fund our capital needs, respond to changing conditions and engage in other business activities that may be in our best interests.

Restrictive covenants in the New Senior Secured Facilities 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 New Senior Secured Credit Facilities unless we obtain amendments or waivers from the applicable lenders.

These restrictions limit our ability to, subject to certain exceptions, among other things:

•engage in mergers, consolidations, liquidations, or dissolutions;

•create or incur debt or liens;

•make certain debt prepayments (including in respect of the Notes);

•pay dividends, distributions or certain other restricted payments;

•make investments, capital expenditures, general and administrative expenditures, acquisitions or loans;

•operate in certain geographical boundaries;

•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 New Senior Secured Credit Facilities, payments of dividends to us, or payment of debt owed to us and our subsidiaries; and

•create new subsidiaries or change the nature of our business.

The New Senior Secured Credit Facilities also contain representations and warranties, affirmative covenants, additional negative covenants and events of default (including a change of control), including in the case of the Term Loan B, amortization and repayments of principal with excess cash flow, subject to a minimum liquidity amount. The New Senior Secured Credit Facilities also require us to (x) hedge within five business days of the closing of the New Senior Secured Credit Facilities, 100% of reasonably anticipated production of crude oil from proved, developed and producing oil and gas properties for each calendar month through December 15, 2028 and (y) on a go forward basis, use commercially reasonable efforts to hedge substantially all of the anticipated production of crude oil from proved, developed and producing oil and gas properties through December 15, 2028, which may limit our ability to realize the benefits of higher commodity prices.

Third Amendment to Senior Secured Term Loan Agreement

On June 22, 2026, the Company entered into a third amendment (the “Third Amendment”) to the Senior Secured Term Loan Agreement (“Senior Secured Term Loan”) with Exxon Mobil Corporation (“Exxon” or “EM”), which, among other things, extended the maturity date of the Senior Secured Term Loan to the earlier of (i) July 24, 2026 or (ii) the occurrence of an event of default. In connection with the Third Amendment, the Company paid Exxon a $30.0 million amendment fee on June 22, 2026. Exxon also agreed to suspend and waive, until the amended maturity date, the $25.0 million minimum liquidity covenant that had been introduced under the Second Amendment to the Senior Secured Term Loan Agreement. Additionally, in connection with the Third Amendment, the Company obtained a limited waiver (the “Limited Waiver”) from Exxon and Mobil Pacific Pipeline Company under the Sable-EM Purchase Agreement, which defers the Company’s obligation to provide plugging and abandonment financial security under Section 11.18(c) of the Sable-EM Purchase Agreement until the earlier of (i) December 22, 2028, (ii) the date on which the new money secured financing to be entered into prior to the maturity date of Term Loan B (as defined below) for the primary purposes of refinancing the Senior Secured Term Loan is redeemed, repaid or otherwise refinanced, or (iii) the occurrence of an event of default. The Third Amendment and Limited Waiver were entered into to provide the Company with additional time and flexibility to complete its planned refinancing while preserving liquidity.

2026 Refinancing Transactions

On July 2, 2026, the Company consummated a series of transactions to refinance the Senior Secured Term Loan and strengthen its capital structure and liquidity position (collectively, the “2026 Refinancing Transactions” or the “Refinancing”). The Refinancing consisted of the following components:

•Convertible Notes Offering. The Company issued $345.0 million aggregate principal amount of 6.5% Convertible Senior Notes due 2031 (the “Convertible Notes”) in an underwritten public offering, resulting in net proceeds of approximately $332.5 million.

•Concurrent Common Stock Offering. The Company issued 37,337,662 shares of Common Stock in an underwritten public offering, resulting in net proceeds of approximately $107.0 million (the “Common Stock Offering”).

•New Senior Secured Credit Facilities. The Company entered into (i) a new $675.0 million senior secured Term Loan B credit facility (the “Term Loan B”), which was fully drawn at closing, and (ii) a new senior secured reserve-based revolving credit facility of up to $500.0 million (the “Senior Revolver”), which was undrawn at closing. The Term Loan B and the Senior Revolver are collectively referred to as the “New Senior Secured Credit Facilities.” Both facilities mature on December 15, 2028 and are secured by first-priority liens on substantially all of the Company’s assets.

The Company used the net proceeds of the Convertible Notes and the Common Stock Offering, together with borrowings under the Term Loan B, to repay in full the Company’s Senior Secured Term Loan, and to pay related fees and expenses, with the remainder available for general corporate purposes.

Subsequently on March 13, 2026, the United States Secretary of Energy, Chris Wright, issued an order (the “DPA Order”) pursuant to that delegated authority in order to address the energy scarcity and supply disruption risks that have left the region and U.S. military forces dependent on foreign oil. The DPA Order states that “[a]n affordable and reliable domestic supply of energy is a fundamental requirement for the national and economic security of any nation.” It observes that the nation’s energy “problems are most pronounced in our Nation’s West Coast, ‘where dangerous State and local policies jeopardize our Nation’s core national defense and security needs, and devastate the prosperity of not only local residents but the entire United States population.’” The DPA Order also states that the SYU is a “critical energy resource on the West Coast” but “cannot be used to address the shortages identified in EO 14156 and the resulting vulnerabilities, including adversarial dependence” because “California agencies have deployed an array of state measures [ ] to block pipeline operations.” Accordingly, the DPA Order directs Sable “to immediately prioritize and allocate pipeline transportation services for hydrocarbons from the SYU through the SYPS” and “immediately commence performance under contracts or orders for services…for hydrocarbon transportation capacity in the SYPS[.]” The DPA Order requires Sable to “comply with this order immediately and maintain such compliance until such time as the conditions necessitating the issuance of this order abate or until Sable is directed otherwise.”

On March 14, 2026, the Company resumed transportation of oil through Pipeline Segments 324 and 325 of the Santa Ynez Pipeline System, pursuant to the DPA Order (as defined above).

On March 30, 2026, the State of California filed a Complaint for Declaratory and Injunctive Relief alleging that the DPA Order violates provisions of the Administrative Procedure Act and the U.S. Constitution. The matter is captioned State of California v. Chris Wright, et al., Case No. 2:26-cv-03396, in U.S. District Court, Central District of California. The Court held a hearing on the State’s Motion for Preliminary Injunction on June 8, 2026, and ordered supplemental briefing, which was completed by the parties on June 18, 2026. On June 29, 2026, Defendants Chris Wright and the U.S. Department of Energy filed a Motion to Dismiss, in which Sable and PPC joined. On July 20, 2026, the State filed a First Amended Complaint which mooted the pending Motion to Dismiss. The parties submitted, and are currently awaiting entry of, a stipulation for briefing a renewed Motion to Dismiss addressed to the First Amended Complaint. On July 30, 2026, the Court issued a scheduling order setting a briefing schedule for a Motion to Dismiss the First Amended Complaint with a hearing scheduled on September 28, 2026.

Offshore Buoy Alternative

Sable is evaluating the installation of an oil sales buoy (the “Buoy”) to provide access to additional markets for federal crude oil produced from the SYU in the Pacific Outer Continental Shelf Area (the “Buoy Strategy”).

Sable has not started any preparations or installations of the Buoy. Sable estimates that the total capital required to install the Buoy would be approximately $125.0 million. See “Risk Factors—Risks Associated with Our Operations—In order to commence operations pursuant to the OS&T Strategy or the Buoy Strategy, we will require clearances and permitting, including from BOEM.”

Preparations for the OS&T Strategy, if implemented, would include the acquisition of a suitable OS&T vessel, certain refitting and upgrades to the vessel and the SYU equipment, transportation of the vessel to SYU, and related installation. Sable estimates that the total capital required to execute the OS&T Strategy would be approximately $475.0 million. See “Risk Factors—Risks Associated with Our Operations—In order to commence operations pursuant to the OS&T Strategy or the Buoy Strategy, we will require clearances and permitting, including from BOEM.”

Commodity prices have been highly volatile during the six months ended June 30, 2026, driven primarily by geopolitical developments in the Middle East. Benchmark crude oil prices began 2026 near multi-year lows, with Brent trading in the low-$60s per barrel amid a well-supplied global market and moderate demand growth. Prices rose sharply following the outbreak of armed conflict between the United States and Iran in late February 2026 and the related disruption to shipping through the Strait of Hormuz, with Brent crude briefly exceeding $118 per barrel — its highest level since the onset of the COVID-19 pandemic — before briefly moderating as the conflict de-escalated and a temporary ceasefire took hold. As of the date of this filing, Brent and WTI crude oil prices have remained elevated and volatile relative to pre-conflict levels, and renewed armed conflict and increased risk to Strait of Hormuz shipping lanes in July 2026 illustrate the continued sensitivity of global crude prices to developments in the region.

In July 2026, the Company entered into a series of costless collar arrangements covering approximately 28.0 mbo/d for the period from July 1, 2026 through December 31, 2026 (with a $65.00 put and $89.39 call), approximately 25.0 mbo/d for the period from January 1, 2027 through December 31, 2027 (with a $65.00 put and $80.00 call), and approximately 21.0 mbo/d for the period from January 1, 2028 through December 31, 2028 (with a $65.00 put and $73.17 call), in order to manage its exposure to fluctuations in crude oil prices.

The following table presents our oil and NGL revenues and sales volumes for the three and six months ended June 30, 2026 and 2025. The Company had no natural gas revenue or sales volumes for the periods presented.

The Company initiated oil sales in March 2026, following the completion of filling the SYPS on March 29, 2026. Accordingly, no sales volumes or revenues were recognized for the three and six months ended June 30, 2025.

Income tax expense. Income tax expense for the three months ended June 30, 2026 was $27.0 million, compared to an income tax expense of $7.8 million for the three months ended June 30, 2025. The Company’s effective tax rate was negative 72.4 percent for the three months ended June 30, 2026. The effective tax rate for the three months ended June 30, 2026 reflects the cumulative effect of a change in the estimated annual effective tax rate, which the Company had estimated to be zero as of March 31, 2026. In accordance with ASC 740-270-35-2, the effect of a change in the estimated annual effective tax rate is recognized in the interim period in which the change occurs, resulting in a disproportionate rate for the current quarter relative to the year-to-date rate. The Company recognized a discrete tax expense of $2.2 million for the three months ended June 30, 2026, resulting from a tax shortfall on stock-based compensation vesting for which the related deduction did not fully offset the associated book expense. The effective tax rate also differed from the U.S. federal statutory tax rate of 21% primarily due to changes in valuation allowance on the deferred tax assets and disallowed expenses.

Six Months Ended June 30, 2026 vs. the Six Months Ended June 30, 2025.

The following table presents selected unaudited condensed consolidated financial results of operations for the six months ended June 30, 2026 and 2025.

Revenue. The Company recognized $138.0 million in oil and natural gas liquids sales and $0.4 million in other revenue for the six months ended June 30, 2026, compared to no revenue recognized for the six months ended June 30, 2025, as oil sales did not commence until March 2026.

Operating and maintenance expenses. Operating and maintenance expenses were $181.5 million for the six months ended June 30, 2026, representing an increase of $96.7 million, or 114%, compared to $84.8 million for the six months ended June 30, 2025. The increase was primarily attributable to resumption-related activities, including one-time platform commissioning expenses. Platform Harmony commenced initial production in May 2025, such that the six months ended June 30, 2025 reflected only approximately one month of associated operating costs, whereas the six months ended June 30, 2026 reflected a full six months of Platform Harmony operating costs. In addition, Platform Heritage recommenced production in April 2026 and contributed a full quarter of operating costs during the six months ended June 30, 2026, with no comparable costs recognized for the six months ended June 30, 2025. The increase was also attributable $18.5 million of start-up related demurrage charges and $24.0 million of operator rights expenditures which were recognized for the six months ended June 30, 2026. Additionally, during the six months ended June 30, 2026, non-reoccurring expenses were incurred associated with platform commissioning activities, which the Company does not expect to recur in future periods. Operating and maintenance expenses are expected to remain elevated as compared to prior periods until all production wells are online.

Depletion, depreciation, amortization and accretion. Depletion, depreciation, amortization and accretion was $36.0 million for the six months ended June 30, 2026, representing an increase of $29.8 million, or 481%, compared to $6.2 million for the six months ended June 30, 2025. The increase was primarily attributable to the initial depletion expense recognized following the Company’s commencement of oil sales in March 2026. For the six months ended June 30, 2025, depletion, depreciation, amortization and accretion primarily consisted of accretion expense related to asset retirement obligations, as depletion expense had not yet commenced. During the six months ended June 30, 2026, the Company recognized $33.5 million of depletion, depreciation and amortization associated with the SYU assets, $5.2 million of which was capitalized to Inventory and linefill within Oil and gas properties on the unaudited condensed consolidated balance sheet, as the associated production was used to increase the volumes held within the SYPS and the storage tanks at LFC as of June 30, 2026 (refer to Note 2 — Significant Accounting Policies for additional details regarding linefill). Depletion, depreciation, amortization and accretion expense is expected to increase in future periods as production volumes and sales activity increase.

General and administrative expenses. G&A expenses were $106.6 million for the six months ended June 30, 2026, an increase of $8.9 million, or 9% compared to $97.7 million for the six months ended June 30, 2025. The increase in G&A expenses was primarily attributable to a $15.1 million increase in share-based compensation expense and a $14.5 million increase in legal expenses related to ongoing legal and regulatory matters. The increase was partially offset by a $21.8 million decrease in other compensation costs. Upon the Company's achievement of first production in May 2025, the Company made certain related restart incentive compensation payments and initiated accruing annual incentive compensation based on management’s expectations, both of which were recognized during the six months ended June 30, 2025.

Total other expense, net. Total other expense, net was $48.6 million for the six months ended June 30, 2026, an increase of $18.4 million compared to total other expense, net of $30.2 million for the six months ended June 30, 2025. The increase in total other expense, net was primarily attributable to a $35.7 million increase in interest expense, due to the increase in the Company’s Senior Secured Term Loan interest rate from 10% to 15% in accordance with the terms of the Second Amendment, as well as due to the amortization of additional debt issuance costs recognized in connection with the Third Amendment. This increase was partially offset by $4.7 million increase in other income, net, and a $22.0 million favorable change in the fair value of the warrant liabilities, driven by a shorter remaining term, a decrease in the market price of the Company’s common stock, and changes in market volatility.

Income tax expense. Income tax expense for the six months ended June 30, 2026 was $27.0 million, representing an increase of $8.3 million compared to $18.7 million for the six months ended June 30, 2025. The Company’s effective tax rate was negative 11.5% for the six months ended June 30, 2026. The effective tax rate differed from the U.S. federal statutory tax rate of 21% primarily due to changes in valuation allowance on the deferred tax assets and disallowed expenses. The Company recognized a discrete tax expense of $2.2 million for the six months ended June 30, 2026, resulting from a tax shortfall on stock-based compensation vesting for which the related deduction did not fully offset the associated book expense.