Sable Offshore (NYSE: SOC) outlines SYU reserves, growth plans and cash flow

Rhea-AI Filing Summary

Sable Offshore Corp. released a detailed investor presentation and an independent reserve report for its Santa Ynez Unit (SYU) offshore California. The materials outline a large resource base, development plans, financial guidance and recent federal actions supporting continued operations.

Management estimates SYU holds 659 MMBoe of net estimated reserves with a PV-10 of $6,074MM at Brent strip pricing, and targets fully ramped gross production of about 62,000 Boe per day across its three platforms. Updated guidance for 2027 and 2028 calls for net production of 47.5–52.5 MBoe per day, largely oil, with low-cost workovers and perforation adds designed to maintain proved developed producing reserves.

The company projects 2027 adjusted EBITDA of $738–$985MM and unlevered free cash flow of $639–$866MM, and is pursuing a refinancing of its Exxon term loan ahead of its June 2026 maturity. The reserve engineers’ letter from Netherland, Sewell & Associates independently estimates proved, probable and possible developed reserves and future revenue as of May 31, 2026, using SEC-compliant methodology and constant prices.

Insights

Energy sector analyst

Large offshore reserves and strong projected cash flow are highlighted but depend on execution, refinancing and regulatory stability.

The presentation positions Sable Offshore as a single-asset offshore producer with substantial remaining resources in the Santa Ynez Unit. Management and Netherland, Sewell & Associates both present extensive proved, probable and possible developed reserves, with net estimated reserves of 659 MMBoe and PV-10 of $6,074MM at Brent strip pricing.

Operationally, Sable is ramping three platforms toward an estimated 62,000 gross Boe/d, relying first on low-cost workovers and perforation adds before moving to a larger drilling program. Guidance shows 2027 adjusted EBITDA of $738–$985MM and significant unlevered free cash flow from 2026–2028, assuming strip prices and planned capital spending.

Key dependencies include refinancing the $956MM Exxon term loan maturing in June 2026, executing a comprehensive hedging program on PDP volumes, and maintaining federal regulatory support for the Santa Ynez Pipeline System. Federal actions under PHMSA, DOJ and the Defense Production Act are described as important to protecting ongoing production and transportation from SYU.

8-K Event Classification

2 items: 7.01, 9.01

2 items

Item 7.01 Regulation FD Disclosure Disclosure

Material non-public information disclosed under Regulation Fair Disclosure, often investor presentations or guidance.

Item 9.01 Financial Statements and Exhibits Exhibits

Financial statements, pro forma financial information, and exhibit attachments filed with this report.

Key Figures

Net estimated reserves: 659 MMBoe PV-10 of reserves: $6,074MM Share price: $14.69/share +5 more

8 metrics

Net estimated reserves 659 MMBoe Management net estimated reserves at Brent strip pricing

PV-10 of reserves $6,074MM Net estimated reserves PV-10 at strip pricing

Share price $14.69/share SOC share price as of May 29, 2026

Fully diluted shares 157.9 million shares Fully diluted shares outstanding used for market cap

Net debt $904MM Total debt minus $52MM cash as of March 31, 2026

2027E adjusted EBITDA $738–$985MM Preliminary 2027 adjusted EBITDA guidance range

2027E unlevered FCF $639–$866MM 2027 unlevered free cash flow guidance range

Fully ramped gross production 62,000 Boe/d Estimated total fully ramped gross production from SYU platforms

Key Terms

PV-10, Proved Developed Producing (PDP), Defense Production Act, unlevered free cash flow, +2 more

6 terms

PV-10 financial

"At Brent strip pricing, the SYU has 659 MMBoe in net estimated reserves and a PV-10 of $6,074MM"

PV-10 is a valuation metric that estimates the present value of future oil and gas production cash flows, discounted at 10% and stated before income taxes. Think of it as the current price tag on a company’s proven reserves, calculated by shrinking future revenue streams to today’s dollars using a 10% rate. Investors use PV-10 to compare the relative worth of reserves and assess how much future production could contribute to a company’s value, much like comparing the upfront price of different rental properties based on expected future rent.

Proved Developed Producing (PDP) financial

"Maintain Proved Developed Producing (“PDP”) reserves and maintain production"

Defense Production Act regulatory

"the U.S. Department of Energy invoked the Defense Production Act (”DPA”) and ordered Sable to resume petroleum transportation"

A U.S. law that lets the federal government prioritize, allocate, and financially support the production and supply of goods and services needed for national defense or major emergencies. For investors, it can quickly change a company’s sales outlook and production plans by directing contracts, speeding approvals, or providing subsidies—like a city mayor telling factories which products to make during a crisis—so affected companies may see rapid revenue or cost shifts.

unlevered free cash flow financial

"3-Year Unlevered Free Cash Flow Guidance at Strip"

Unlevered free cash flow is the cash a company generates from its core business after paying operating costs and reinvesting in the business, but before any interest or debt repayments. It shows how much cash would be available to all providers of capital—owners and lenders alike—and helps investors compare underlying business performance and value companies without the distortion of different debt levels, like judging a car’s fuel efficiency before adding cargo weight.

costless collar financial

"plans to implement a costless collar and deferred premium put strategy to establish downside protection"

A costless collar is an options strategy used to protect the value of a stock position by buying a put (downside protection) and simultaneously selling a call (giving up some upside), with the premiums structured so the two trades roughly cancel out and require little or no net cash. For investors it acts like insurance paid for by agreeing to cap future gains: it limits potential losses while also setting a ceiling on how much profit can be realized.

Proved Developed Non-Producing financial

"Proved Developed Non-Producing 23,849.6 501.9 32,880.2 1,139,432.2 705,763.2"

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FALSE000183148100018314812026-05-292026-05-29

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

________________________

FORM 8-K

_________________________

CURRENT REPORT

PURSUANT TO SECTION 13 OR 15(D)

OF THE SECURITIES EXCHANGE ACT OF 1934

Date of Report (Date of earliest event reported): May 29, 2026

___________________________________

Sable Offshore Corp.

(Exact name of registrant as specified in its charter)

Delaware (State or other jurisdiction of incorporation or organization)			001-40111 (Commission File Number)			85-3514078 (I.R.S. Employer Identification Number)
845 Texas Avenue, Suite 2920
Houston, TX						77002
(Address of principal executive offices)						(Zip code)
(713) 579-6161
(Registrant's telephone number, including area code)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

☐			Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)
☐			Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)
☐			Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))
☐			Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Securities registered pursuant to Section 12(b) of the Act:

Title of each class

Trading Symbol

Name of each exchange on which registered

Common stock, par value $0.0001

SOC

New York Stock Exchange

Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities Act of 1933 (§230.405 of this chapter) or Rule12b-2 of the Securities Exchange Act.of 1934 (§240.12b-2 of this chapter).

Emerging growth company ☑   

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. ☐

Item 7.01    Regulation FD Disclosure.

On May 29, 2026, Sable Offshore Corp. (the “Company”) issued a press release announcing a new investor presentation would be posted to its corporate website before market open on Monday, June 1, 2026 and that the Company plans to host a conference call to discuss the new investor presentation today, Monday, June 1, 2026 at 10:00am CDT / 11:00am EDT.

On June 1, 2026, the Company posted the new investor presentation materials on its website, www.sableoffshore.com. The presentation materials are attached hereto as Exhibit 99.1 and incorporated herein by reference. These materials may also be used by the Company at today’s investor conference call, or at one or more presentations with analysts, investors or other stakeholders.

On June 1, 2026, Netherland, Sewell, & Associates, Inc. (“NSAI”), the Company's independent registered reserve engineers, issued a letter to the Company estimating proved, probable, and possible developed reserves and future revenue, as of May 31, 2026. The NSAI letter is attached hereto as Exhibit 99.2 and incorporated herein by reference. This letter may also be used by the Company at today's investor conference call, or at one or more presentations with analysts, investors or other stakeholders.

The information contained in this 8-K is summary information that is intended to be considered in the context of the Company’s Securities and Exchange Commission filings and other public announcements. The Company undertakes no duty or obligation to publicly update or revise this information, although it may do so from time to time.

The information furnished pursuant to this Item 7.01, including Exhibit 99.1 and 99.2, shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), or otherwise subject to the liabilities under that Section and shall not be deemed to be incorporated by reference in any filing made by the Company under the Securities Act of 1933, as amended (the “Securities Act”), or the Exchange Act.

Forward-Looking Statements

The information in this press release include “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. When used in this press release, the words “could,” “should,” “will,” “may,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project,” “continue,” “plan,” “forecast,” “predict,” “potential,” “future,” “outlook,” and “target,” the negative of such terms and other similar expressions are intended to identify forward- looking statements, although not all forward-looking statements will contain such identifying words. These statements are based on the current beliefs and expectations of Sable’s management and are subject to significant risks and uncertainties. Actual results may differ materially from those described in the forward-looking statements. Factors that could cause Sable’s actual results to differ materially from those described in the forward-looking statements include: the ability to recommence full production of the SYU assets; the cost and time required therefor, and production levels once recommenced; availability of future financing; our ability to consummate a debt refinancing of our Senior Secured Term Loan and the timing and terms thereof; our financial performance; global economic conditions and inflation; increased operating costs; lack of availability of drilling and production equipment, supplies, services and qualified personnel; geographical concentration of operations; environmental and weather risks; regulatory changes and uncertainties; litigation, complaints and/or adverse publicity; privacy and data protection laws, privacy or data breaches, or loss of data; our ability to comply with laws and regulations applicable to our business; and other one-time events and other factors that can be found in Sable’s Annual Report on Form 10-K for the year ended December 31, 2025, which is filed with the Securities and Exchange Commission and is available on Sable’s website (www.sableoffshore.com) and on the Securities and Exchange Commission’s website (www.sec.gov). Except as required by applicable law, Sable undertakes no obligation to publicly release the result of any revisions to these forward-looking statements to reflect the impact of events or circumstances that may arise after the date of this press release.

Item 9.01    Financial Statements and Exhibits.

(d) Exhibits:

Exhibit No.						Description of Exhibits
99.1						Presentation Materials.
99.2						Reserve Letter of Netherland, Sewell, & Associates, Inc., dated June 1, 2026.
104						Cover Page Interactive Data File (embedded within the Inline XBRL document).

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

Sable Offshore Corp.

Date:

June 1, 2026

By:

/s/ Gregory D. Patrinely

Name:

Gregory D. Patrinely

Title:

Executive Vice President and Chief Financial Officer

Sable Offshore Corp. Investor Presentation June 2026

2 FORWARD LOOKING STATEMENTS The information in this presentation includes “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. When used in this presentation, the words “could,” “should,” “would,” “will,” “may,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project,” “continue,” “plan,” “forecast,” “predict,” “potential,” “future,” “outlook,” and “target,” the negative of such terms and other similar expressions are intended to identify forward-looking statements, although not all forward-looking statements will contain such identifying words. These statements are based on the current beliefs and expectations of Sable’s management and are subject to significant risks and uncertainties. Actual results may differ materially from those described in the forward-looking statements. Factors that could cause Sable’s actual results to differ materially from those described in the forward-looking statements include: the ability to recommence full production of the SYU assets; the cost and time required therefor, and production levels once recommenced; availability of future financing; our ability to consummate a debt refinancing of our Senior Secured Term Loan and the timing and terms thereof; our financial performance; global economic conditions and inflation; increased operating costs; lack of availability of drilling and production equipment, supplies, services and qualified personnel; geographical concentration of operations; environmental and weather risks; regulatory changes and uncertainties; litigation, complaints and/or adverse publicity; privacy and data protection laws, privacy or data breaches, or loss of data; our ability to comply with laws and regulations applicable to our business; and other one-time events and other factors that can be found in Sable’s Annual Report on Form 10-K for the year ended December 31, 2025, which is filed with the Securities and Exchange Commission and is available on Sable’s website (www.sableoffshore.com) and on the Securities and Exchange Commission’s website (www.sec.gov). Except as required by applicable law, Sable undertakes no obligation to publicly release the result of any revisions to these forward-looking statements to reflect the impact of events or circumstances that may arise after the date of this presentation. USE OF PROJECTIONS AND ESTIMATES This presentation contains financial projections and estimates for Sable, including with respect to its future capital expenditures, initial timing and production estimates and future cash costs. Sable’s auditors have not audited, reviewed, compiled or performed any procedures with respect to the projections and estimates for the purpose of their inclusion in this presentation, and, accordingly, no such auditors have expressed an opinion or provided any other form of assurance with respect thereto for the purpose of this presentation. These projections and estimates are for illustrative purposes only and should not be relied upon as being necessarily indicative of future results. The assumptions and estimates underlying the projected information are inherently uncertain and are subject to a wide variety of significant business, regulatory, economic and competitive risks and uncertainties that could cause actual results to differ materially from those contained in the projected information. Even if the assumptions and estimates are correct, projections and estimates are inherently uncertain due to a number of factors outside Sable’s control. Accordingly, there can be no assurance that the projected results are indicative of Sable’s future performance or that actual results will not differ materially from those presented in the projected information. Inclusion of the projected information in this presentation should not be regarded as a representation by any person, including, without limitation, Sable, that the results contained in the projected information will be achieved. NON-GAAP FINANCIAL INFORMATION This presentation includes certain non-GAAP measures that are more fully described in the appendices to the presentation. These financial measures should be reviewed in conjunction with the relevant GAAP financial measures and are not presented as alternative measures of GAAP. Other companies in our industry may define or calculate these measures differently than we do, limiting their usefulness as comparative measures. Because of these limitations, these non-GAAP financial measures should not be considered in isolation or as substitutes for performance measures calculated in accordance with GAAP. Reconciliations of these non-GAAP financial measures to their most directly comparable GAAP financial measures for each of the periods included in this presentation are included in the Appendices at the back of this presentation. Disclaimer

3 Unlocking value in the Santa Ynez Unit Sable Offshore Corp. (NYSE: SOC)  Sable Offshore (NYSE: SOC) is an exploration and production company based in Houston that operates the Santa Ynez Unit (“SYU”), an oil and gas production unit comprised of 16 federal leases and three offshore platforms and ancillary facilities ─ The SYU is a prolific asset with ~15,500 MMBoe originally in place, ~2,200 MMBoe ultimately recoverable and ~1,500 MMBoe of total remaining resources(1) ─ At Brent strip pricing, the SYU has 659 MMBoe in net estimated reserves and a PV-10 of $6,074MM(2)  SYU was originally developed and operated by ExxonMobil (“Exxon”) for over 30 years, but production was temporarily suspended in 2015 following a third-party onshore pipeline leak  Sable also operates the Santa Ynez Pipeline System (“SYPS”), an interstate pipeline system extending from the SYU to the inland oil sales point in Pentland, CA and includes the Las Flores Canyon Midstream Processing Facilities  Sable acquired the SYU and the SYPS in 2024, with Exxon providing seller financing and over the past few years has successfully worked to resume petroleum transportation through the SYPS and achieve first sales  In March 2026, the U.S. Department of Energy invoked the Defense Production Act (”DPA”) and ordered Sable to resume petroleum transportation through the SYPS. Sable achieved first sales within the same month  Platforms Harmony and Heritage began flowing in May 2025 and April 2026, respectively, with Platform Hondo expected to come online in Q3 2026  Sable is currently pursuing a refinancing of the Exxon term loan, which is currently scheduled to mature on June 26, 2026 Santa Ynez Unit LFC Midstream Processing Facilities (1) Management estimates are inherently uncertain and subject to numerous risks. Actual results may differ in a material amount from management estimates and projections. Resource figures reflect gross amounts, gross gas is pre-shrink. (2) For additional information, refer to p.13.

4 SYU History Premier offshore project developed by Exxon over 40+ years  Discovered in 1968, over the course of 14 years Exxon consolidated 16 offshore federal oil leases into a streamlined production unit known as SYU ─ SYU platform construction began in 1976 with Platform Hondo (online in 1981) followed by Platform Harmony and Platform Heritage (both online in 1994); both platforms Harmony and Heritage have dedicated rigs for future development ─ Production was initially processed in federal waters in an Offshore Storage and Treating Vessel (OS&T) from 1981 to 1994 ─ SYU platforms are located 5 to 9 miles offshore Santa Barbara County and include 112 wells (90 producers, 12 injectors, 10 idle); sizable inventory of infill drilling and additional step-out drilling opportunities(1)  Wholly owned midstream processing facilities at Las Flores Canyon (not visible from highway) SYU Development Background (1) Sable management have identified >100 infill drilling and step-out opportunities. Las Flores Canyon Facilities

5  SYU Federal Production ─ 16 Federal Leases, ─ Sable operated, 100% WI, 83.6% NRI  Marketing ─ Currently, Sable sells oil through the Santa Ynez Pipeline System from Platform Harmony, located in offshore federal waters, to the inland sales point at Pentland, CA, where oil is sent to the El Segundo Refinery Complex in L.A. ─ Gas sales to SoCalGas expected in the fourth quarter of 2026  Additional Marketing Optionality ─ From 1981-1994, sales were via an OS&T located in federal waters ─ Potential to install an oil sales buoy for direct sales of oil to additional markets ─ The buoy would be expected to be similar to the Long Beach and El Segundo buoys in the Los Angeles area ─ The buoy would require a number of other federal agency approvals ─ Potential installation by YE 2028 and preliminary cost estimate of $125MM Santa Ynez Unit Overview SYU Federal Production and Marketing Assets SYU leases are all located in Federal waters ~76,000 acres Note: Management estimates are inherently uncertain and subject to numerous risks. Actual results may differ in a material amount from management estimates and projections. “Marketing” refers to the transportation and sale of oil and gas downstream of the Santa Ynez Unit.

6 Field Name Prospect Name Oil (MMBbl) Gas (Bcf) Total (MMBoe) Santa Ynez Unit SYU 706 1,131 894 Mississippi Canyon 807 MARS-URSA 473 688 596 Mississippi Canyon 940 VITO 411 200 446 Mississippi Canyon 392 APPOMATTOX 319 165 348 Mississippi Canyon 778 THUNDER HORSE 245 179 277 Walker Ridge 678 SAINT MALO 244 58 255 Green Canyon 743 ATLANTIS 188 211 226 Keathley Canyon 875 LUCIUS 131 164 160 Green Canyon 826 MAD DOG 130 84 145 Green Canyon 654 SHENZI 130 50 139 Green Canyon 640 TAHITI/CAE/TONG 120 83 134 Green Canyon 244 TROIKA 57 92 73 Mississippi Canyon 776 N.THUNDER HORSE 55 55 65 Mississippi Canyon 84 KING/HORN MT. 48 36 54 Alaminos Canyon 857 GREAT WHITE 39 45 47 Garden Banks 171 SALSA 24 90 40 Grand Isle 43 22 89 38 Garden Banks 426 AUGER 19 62 30 Eugene Island 330 9 19 12 Ship Shoal 208 5 32 11 Viosca Knoll 956 RAM-POWELL 5 24 9 South Pass 61 4 4 5 Eugene Island 238 4 91 21 West Delta 73 4 9 5 West Delta 30 3 8 5 SYU is a Prolific Offshore Asset Cumulative Production Source: BOEM 2021 report on top producing OCS fields. SYU historical production figures via ExxonMobil. Note: “OCS” defined as Outer Continental Shelf, a legally defined geographic feature of the United States that covers offshore oil and gas reserves in Federal waters. Production and reserves figures reflect gross amounts, gross gas is pre-shrink. (1) Santa Ynez Unit EUR figures per Sable management. Assumes strip pricing as of May 19, 2026 and effective date of May 2026. For additional information, refer to p.13. Estimated Remaining Reserves(1) SYU is a top producer with the most remaining resource among current OCS producing fields Field Name Prospect Name Oil (MMBbl) Gas (Bcf) Total (MMBoe) Mississippi Canyon 807 MARS-URSA 1,504 1,922 1,846 West Delta 30 593 977 767 Bay Marchand 2 547 576 649 Santa Ynez Unit SYU 507 984 671 Eugene Island 330 462 1,902 800 Green Canyon 640 TAHITI/CAE/TONG 436 289 487 Green Canyon 743 ATLANTIS 395 266 442 Grand Isle 43 382 1,658 677 Green Canyon 654 SHENZI 328 130 351 Grand Isle 16 308 398 379 Mississippi Canyon 776 N.THUNDER HORSE 291 285 342 Garden Banks 426 AUGER 286 1,014 467 West Delta 73 280 692 403 Main Pass 41 274 1,560 552 South Pass 61 273 530 367 Mississippi Canyon 84 KING/HORN MT. 271 285 322 South Timbalier 21 259 427 335 Green Canyon 826 MAD DOG 233 68 245 Ship Shoal 208 228 1,403 477 Mississippi Canyon 778 THUNDER HORSE 203 148 230 South Pass 89 197 875 353 Mississippi Canyon 194 COGNAC 183 764 319 Alaminos Canyon 857 GREAT WHITE 182 331 240 Green Canyon 244 TROIKA 181 345 243 South Timbalier 135 170 628 282

7 SYU Total Recoverable Resources Significant production history and prolific resource potential Note: Management estimates are inherently uncertain and subject to numerous risks. Actual results may differ in a material amount from management estimates and projections. Resource figures reflect gross amounts, gross gas is pre-shrink. 15,459 MMBoe Primary Produced To Date: Remaining Primary Forecast: Heavy Oil Forecast: 2,183 MMBoe Total Remaining Resources: Recovery Factors Total Gross Recoverable Resources 14.1% Total Ultimate Recovery: 4.3% 671 MMBoe 1,512 MMBoe 5.8% 894 MMBoe 4.0% 618 MMBoe 9.8% Less: = = + SYU Original Boe in Place:

8 Initial production at Harmony and Heritage platforms has exceeded expectations SYU is Ramping Up to Full Production Production Restart: May 2025  Estimated fully ramped gross sales: ~22,000 Bo/d  Wells: 32(1)  Available well slots: 23-27(2) Platform Harmony Production Restart: April 2026  Estimated fully ramped gross sales: ~30,000 Bo/d  Wells: 44(1)  Available well slots: 15-17(2) Platform Heritage Estimated Production Restart: Q3 2026  Estimated fully ramped gross sales: ~10,000 Bo/d  Wells: 26(1)  Available well slots: 10(2) Platform Hondo (1) Includes both producers and injector wells (2) Available well slots include those either actively unused or available for opportunistic reclamation. Note: Management estimates are inherently uncertain and subject to numerous risks. Actual results may differ in a material amount from management estimates and projections. Fully ramped production represents gross production estimate with all existing producing wells online simultaneously. Resumed Petroleum Transportation: May 2025  Fully hydrotested to 150,000 Bo/d in May 2025  Resumed SYPS transportation in Platform Harmony to LFC Midstream Processing Facilities segments in May 2025  Resumed SYPS transportation in LFC Midstream Processing Facilities to Pentland segments and achieved first sales in March 2026 Santa Ynez Pipeline System Estimated Total Fully Ramped Production: 62,000 Gross Bo/d (52,000 Net Bo/d) SYU has a 30+ year history of slow base declines between 6-8% with low reinvestment rates required to maintain production

9 Development Plan Through 2029 to Maximize Free Cash Flow Development Plan Driven by High Quality Perf Adds Estimated PDP Reserve Booking Schedule (MMBoe) (10.2) (17.9) (18.1) (18.0) 9.3 17.1 18.8 18.1 129.4 128.5 127.7 128.4 128.5 27.9 48.9 49.4 49.3 2026 2027 2028 2029 2030 Estimated Beg. PDP Reserves Estimated Produced PDP Volumes Estimated PDP Additions from PDNP Perf Adds Estimated Daily Net Production (MBoe/d)  Low-cost development workover plan through 2029 averaging $0.64/Boe replacement cost  Maintain Proved Developed Producing (“PDP”) reserves and maintain production $4MM $0.43/Boe $10MM $0.56/Boe $15MM $0.81/Boe $12MM $0.66/Boe Note: Management estimates are inherently uncertain and subject to numerous risks. Actual results may differ in a material amount from management estimates and projections. (1) Includes Estimated PDP additions from both PDNP Perf Adds and PDNP ESPs. $15MM and $0.81/Boe replacement cost includes both Perf Add and ESP capex. (1)

10 Immediate Opportunity: Perf Adds and Additional ESPs Perf Adds Have Generated Strong Results at Low Costs  Perforation adds (“Perf Adds”) represent additional completions made uphole of existing perforations to extend the available productive reservoir  Through 2028, the Company’s priority is reducing debt and maintaining base production primarily through low-cost Perf Adds (~$800k/well), workovers, and ESP installations  Sable has executed two initial Perf Adds with exceptional performance well in excess of historical production forecasts (~900 / ~1,100 Bo/d actual vs. historical original perforations forecasts of ~250 / ~280 Bo/d, respectively)  Sable plans to develop 56 remaining Perf Add Development Workovers ─ Each Perf Add is forecasted to produce an incremental ~600 Bo/d to the base well production & results in a PDP oil reserves addition of 1.25MM net Bbls  ESPs are electric submersible pumps utilized for production optimization via artificial lift to maintain production levels  Sable plans to install up to 8 ESPs in 2028 for production support if necessary  Each ESP is forecasted to produce an incremental ~900 Bo/d to the base well production & results in a PDP Oil Reserves addition of 1.25MM net Bbls  2 Perf Adds completed and producing  5 Perf Adds completed, 4 remaining to be completed; all 9 expected to be producing by Q3 2026  YE26 Rem. Inv.: 47 2026E  10 Perf Adds expected to be completed  YE27 Rem. Inv.: 37 2027E  7 Perf Adds expected to be completed  YE28 Rem. Inv.: 30  8 ESPs expected to be completed 2028E  15 Perf Adds expected to be completed  YE29 Rem. Inv.: 15 2029E Further Production and Reserve Addition Support Note: Management estimates are inherently uncertain and subject to numerous risks. Actual results may differ in a material amount from management estimates and projections.

11 Development Drilling and Workover Opportunities U pp er S ili ce ou s M as si ve C he rt Lo w er C al ca re ou s Existing Perfs Planned Perf Adds H eavy O il U pside SYU Cross Section Monterey Type Log Note: Type log is illustrative of Sable management’s interpretation of Gas Oil Contact, Planned Perf Adds, Existing Perfs, and Heavy Oil Upside based on petrophysical data analysis.

12 Longer Term Opportunity: Undrilled Inventory  Sable possesses a deep technical inventory of over 100 identified undrilled locations across the SYU ─ Technical opportunity inventory is based on 80-acre drainage area, maturing field from original 120-acre spacing  Future development strategy focuses on the high-quality Monterey Upper Siliceous reservoir in areas that have undergone increased diagenesis which leads to more fractures, allowing for greater storage of oil and increased permeability  Wellbores would be aligned to maximize contact with the primary fracture orientation for the field and average 2,000’+ gross perforations per well  SYU comprises several discrete fault bound accumulations; compartments defined by pressure compartments Undrilled Inventory Overview Top of Monterey Structure Legend Gas Oil Water Development Drilling Program Heritage Harmony Hondo

13 Reserves Summary(1)(2)(3) Reserves Estimate at Brent Strip / $80 / $100 Oil Pricing (1) Reserve report assumes June 2026 effective date. Brent strip pricing as of May 19, 2026 (2026: $92.73/Bbl, 2027: $81.59/Bbl, 2028: $76.84/Bbl, 2029: $74.46/Bbl, 2030+: $72.85/Bbl). (2) Management estimates are inherently uncertain. Actual results may differ in a material amount from management estimates and projections. (3) Net quantities shown herein are unrisked volumes and may represent levels of uncertainty as to their technical and commercial recovery. (4) Includes Netherland Sewell & Associates SEC May 31, 2026 Reserve Report with Sable management estimated initial two-year decline forecast intended to reflect field-wide historical decline rate as well as Sable management estimated lease operating expenses and field life extension from expected future development. Hondo wells included in PDP estimate as wells are expected to restart production in Q3 2026. (5) Management estimates include 11 Perf Add cases that are included in the Proved Developed Netherland Sewell & Associates May 31, 2026 Reserve Report (6) Management estimates are Sable engineered future technical PUD locations with guidance from Netherland Sewell & Associates via review of 25 drilling locations to provide Sable with feedback on technical methodology (7) Management estimates of Probable and Possible cases are mostly future well workover opportunities expected to be generated from newly drilled wells and technology driven producing methods Net Reserves (MMBoe) (Strip) PV-10 Reserves ($MM) (Strip) Reserves by Commodity (Strip) Net Estimated Reserves Oil Gas NGL Total Capex PV-10 Reserve Category (MMBbls) (MMcf) (MMBbls) (MMBoe) ($MM) Strip Pricing $80 Pricing $100 Pricing PDP Estimate(4) 136 63 1 148 $599 $2,332 $2,518 $4,017 PDNP Estimate(5) 33 18 0 36 322 681 772 1,075 PUD Estimate(6) 312 204 3 349 2,528 2,224 2,680 3,887 Probable Estimate (Workovers)(7) 31 31 0 36 50 647 709 936 Possible Estimate (Workovers)(7) 78 64 1 90 250 190 222 307 Total Net Reserve Estimate 590 381 6 659 $3,749 $6,074 $6,901 $10,222 Estimated Cash Flows ($MM) PDP 148 PDNP 36 PUD 349 PROB 36 POSS 90 PDP $2,332 PDNP $681 PUD $2,224 PROB $647 POSS $190 Oil 89% Gas 10% NGL 1%

14 Overview of 2020 Federal Consent Decree  Pipeline Segments 324 and 325 of the SYPS, which was purchased from ExxonMobil in 2024, are contractually subject to portions of a 2020 Federal Consent Decree that, among other things, contains requirements for resumption of petroleum transportation through those segments.  The Consent Decree was entered at a time that Pipeline Segments 324 and 325 had been redesignated from interstate to intrastate pipeline segments. California’s Office of State Fire Marshal (“OSFM”) was therefore designated under the Consent Decree as the agency responsible for overseeing the resumption of petroleum transportation through the segments.  December 17, 2024: OSFM approved Sable’s implementation of enhanced pipeline integrity standards for Pipeline Segments 324 and 325 by granting waivers of certain regulatory requirements related to cathodic protection and seam weld corrosion (“State Waivers”).  February 11, 2025: The Pipeline and Hazardous Materials Safety Administration (“PHMSA”) notified OSFM that PHMSA did not object to OSFM’s granting of the State Waivers.  May 2025: Sable completed over 200 anomaly repairs on Pipeline Segments 324 and 325 under direct oversight of OSFM personnel, as required by the Consent Decree and at a cost exceeding $215 million.  May 27, 2025: Sable conducted successful hydrotests on all sections of Pipeline Segments 324 and 325 as required by the Consent Decree.  October 22, 2025: OSFM sent a letter to Sable requesting that Sable complete additional anomaly repairs along Pipeline Segments 324 and 325 that Sable believes exceed the requirements of the State Waivers and past discussions with OSFM experts.  November 26, 2025: Sable notified PHMSA of its determination that the SYPS, including Pipeline Segments 324 and 325, constitutes an interstate pipeline facility under the Pipeline Safety Act, and requested that PHMSA exercise regulatory oversight over the SYPS.

15 Recent Federal Actions Related to Sable’s Continuing Operations Pipeline and Hazardous Materials Safety Administration (PHMSA) United States Department of Justice (DOJ) United States Department of Energy  PHMSA recognized the SYPS as an interstate pipeline system, asserting federal jurisdiction over safety of the SYPS and preempting State of California safety jurisdiction in December 2025.  PHMSA issued Emergency Special Permit to Sable and approved Restart Plan for the SYPS allowing Sable to transport oil through the entire system in December 2025.  After delegation of authority by the U.S. President, the Secretary of Energy issued a Defense Production Act (“DPA”) Order to Sable in March 2026 to “immediately prioritize and allocate pipeline transportation services for hydrocarbons from the SYU through the SYPS…” Department of Justice has asserted preemption against certain adverse state actions being taken against Sable.  December 2025: DOJ and Sable successfully defended against a request for Emergency Stay of PHMSA Restart Approval and the issuance of the Emergency Special Permit in the federal 9th Circuit Court of Appeals.  March 2026: DOJ moved to terminate the Consent Decree (“CD”) which was entered into by a prior operator of a portion of the SYPS. The CD contains requirements for resuming oil transportation through SYPS Segments 324 and 325. DOJ and Sable assert that all prerequisites to terminating the Consent Decree have been satisfied.  March 2026: DOJ and Sable successfully defended against an Ex Parte (Emergency) Motion to Enforce the Consent Decree filed by state agencies in Consent Decree litigation.  May 2026: DOJ and Sable jointly removed a state court lawsuit relating to prior OSFM restart actions taken prior to the assertion of PHMSA jurisdiction.  April/May 2026: DOJ filed a Statement of Interest and successfully, with Sable, defeated a motion for preliminary injunction in California State Parks litigation directed at Sable’s pipeline rights in the Gaviota State Park. DOJ subsequently moved to intervene in the litigation. Additional Capabilities to Strengthen the Ability to Continue to Monetize Federal Production from the Santa Ynez Unit  In the event that the SYPS becomes unavailable for use, with additional federal approval Sable could construct an offshore oil sales buoy in the vicinity of Platform Harmony to sell crude oil into additional markets directly via tanker. Preliminary estimate of cost is approximately $125MM.

16 Milestones Achieved and Next Steps  Complete repairs on the SYPS (May 2025)  Restart production at Platform Harmony (May 2025)  Complete successful hydrotests on the SYPS (May 2025)  Resume oil transportation through the SYPS to LFC Midstream Processing Facilities (May 2025)  Federal regulatory oversight of the SYPS confirmed (December 2025)  Defense Production Act Order (March 2026)  Resume petroleum transportation through Segments 324 and 325 of the SYPS (March 2026)  First Sales to Chevron from the SYPS (March 2026)  Restart production at Platform Heritage (April 2026)  Refinance Senior Secured Term Loan with new debt capital (Expected June 2026)  Commence commodity hedging program (Expected June 2026)  Restart production at Platform Hondo (Expected Q3 2026)  Potentially install oil sales buoy at the Santa Ynez Unit (YE 2028)  Continue to legally protect Sable’s vested interests and pursue all monetary damages Milestones Achieved Next Steps Note: Management estimates are inherently uncertain and subject to numerous risks. Actual results may differ in a material amount from management estimates and projections.

Financial Overview

18 Current Capitalization Robust asset coverage due to high-value PDP wells and low-cost development opportunities Current Capitalization ($mm, unless otherwise noted) Net Reserves Coverage Leverage As of 3/31/26 PDP Estimate 1P Estimate 3P Estimate 2027E EBITDA Share Price (as of 5/29/26) ($/sh) $14.69 (x) FDSO (mm) 157.9 Total Market Capitalization $2,319 XOM Term Loan 956 Total Debt 956 2.4x 5.5x 6.4x 1.0x - 1.3x (-) Cash (52) (+) Net Debt $904 2.6x 5.8x 6.7x 0.9x - 1.2x Total Enterprise Value $3,223 Metric Reserve Estimate PV-10 @ Strip $2,332 $5,238 $6,074 2027E EBITDA $738 - $985 Note: Market data as of May 29, 2026. (1) Reserve report assumes May 31, 2026 effective date. Brent strip pricing as of May 19, 2026 (2026: $92.73/Bbl, 2027: $81.59/Bbl, 2028: $76.84/Bbl, 2029: $74.46/Bbl, 2030+: $72.85/Bbl). (2) Management estimates are inherently uncertain. Actual results may differ in a material amount from management estimates and projections. (3) Net quantities shown herein are unrisked volumes and may represent levels of uncertainty as to their technical and commercial recovery. (4) Includes Netherland Sewell & Associates SEC May 31, 2026 Reserve Report with Sable management estimated initial two-year decline forecast intended to reflect field-wide historical decline rate as well as Sable management estimated lease operating expenses and field life extension from expected future development. Hondo wells included in PDP estimate as wells are expected to restart production in Q3 2026. For additional information, refer to p.13. (5) Includes PDP, PDNP and PUD reserves estimates. For additional information, refer to p.13. (6) Includes PDP, PDNP, PUD, Probable and Possible reserves estimates. For additional information, refer to p.13. (7) Non-GAAP metric; for additional information, refer to p.27. (4) (1)(2)(3) (5) (6) (7)

19 Preliminary Financial Guidance (2026E – 2028E) Updated Financial Guidance Q2 – Q4 2026E FY 2027E FY 2028E Production & Realizations Gross Average Daily Production (MBoe/d) 42.5 - 47.5 55.0 - 60.0 57.5 – 62.5 Working Interest / Net Revenue Interest (%) 83.6% 83.6% 83.6% Net Average Daily Production (MBoe/d) 35.0 - 40.0 47.5 - 52.5 47.5 - 52.5 % Oil 100% 90% - 92% 90% - 92% Estimated Marketing and GP&T Deduct ($/Bbl) $19.00 - $21.00 $19.00 - $21.00 $19.00 - $21.00 Operating Costs ($ / Net Boe) Lease Operating Expense $20.00 - $22.00 $9.00 - $11.00 $9.00 - $11.00 General & Administrative 6.00 - 8.00 3.00 - 5.00 3.00 - 5.00 Severance and Ad Valorem Taxes (% of Rev.) 0.5% - 1.0% 0.5% - 1.0% 0.5% - 1.0% Capital Expenditures ($MM) Total Capex $170 - $195 $70 - $90 $60 - $80 Income Taxes (%) Income Tax 0% 5% - 15% 20% - 30% Note: Management estimates are inherently uncertain and subject to numerous risks. Actual results may differ in a material amount from management estimates and projections.

20 3-Year Unlevered Free Cash Flow Guidance at Strip Q2 – Q4 2026E FY 2027E FY 2028E Production Gross Average Daily Production (MBoe/d) 42.5 - 47.5 55 - 60 57.5 - 62.5 Working Interest / Net Revenue Interest (%) 83.60% 83.60% 83.60% Net Average Daily Production (MBoe/d) 35 - 40 47.5 - 52.5 47.5 - 52.5 Benchmark Brent Oil Price ($/Bbl) $97.18 $81.59 $76.84 Estimated Marketing and GP&T Deduct ($/Bbl) $19.00 - $21.00 $19.00 - $21.00 $19.00 - $21.00 Unhedged Realized Oil Price ($/Bbl) $76.18 - $78.18 $60.59 - $62.59 $55.84 - $57.84 Net Revenue ($MM) $733 - $860 $1,051 - $1,199 $971 - $1,111 Lease Operating Expense ($212) - ($220) ($172) - ($191) ($173) - ($191) General & Administrative ($66) - ($77) ($57) - ($87) ($58) - ($87) Severance and Ad Valorem Taxes ($4) - ($7) ($6) - ($11) ($6) - ($10) Adjusted EBITDA ($MM)(1) $434 - $580 $738 - $985 $701 - $937 Total Capex ($170) - ($195) ($70) - ($90) ($60) - ($80) Income Taxes -- ($48) - ($114) ($175) - ($205) Unlevered FCF ($MM)(1) $271 - $384 $639 - $866 $532 - $734 Unlevered FCF(1) at Midpoint of Guidance Range Unlevered FCF ($MM)(1) $328 $753 $633 Note: Assumes Brent strip pricing as of 5/19/2026 $/Bbl | $/MMcf: $97.18 | $81.59 | $76.84; $3.34 | $3.54 | $3.72; analysis based on guidance ranges from previous page. Management estimates are inherently uncertain and subject to numerous risks. Actual results may differ in a material amount from management estimates and projections. (1) Non-GAAP metric; for additional information, refer to p.27.

21 Hedging & Bonding Strategy Unlevered FCF(1) at Various Hedging Scenarios  Sable intends to hedge 100% of expected PDP oil production volumes through 2028  Sable plans to implement a costless collar and deferred premium put strategy to establish downside protection, while leaving long- term upside uncapped ─ Price floors will be established in the near-term ─ These floors will be offset by selling calls of which a portion will be done in the near-term with the remainder at future dates  Deliver contractual $350MM plugging and abandonment (“P&A”) bonding obligation via sureties and/or letters of credit ─ Sable is exempt from supplemental Federal P&A bonding due to the size of the reserves at the SYU Q2 – Q4 2026E FY 2027E FY 2028E Cumulative Total Expected Production Volumes (MBoe/d) 35.0 - 40.0 47.5 - 52.5 47.5 - 52.5 42.5 - 47.5 Total PDP Volumes (MBoe/d) 25.0 - 30.0 27.5 – 32.5 25.0 - 30.0 25.0 - 30.0 % of PDP Oil Hedged 100% 100% 100% 100% Hedged Volumes (MBbl/d) 20.0 - 25.0 25.0 - 30.0 20.0 - 25.0 22.5 - 27.5 Strip Pricing Case A: Unhedged $271 - $384 $639 - $866 $532 - $734 $1,442 - $1,984 Case B: 100% PDP Hedged $271 - $384 $639 - $866 $532 - $734 $1,442 - $1,984 $60 / BBL Case A: Unhedged ($76) - $37 $331 - $558 $381 - $583 $636 - $1,178 Case B: 100% PDP Hedged ($17) - $96 $431 - $658 $462 - $664 $877 - $1,419 $70 / BBL Case A: Unhedged $20 - $133 $489 - $716 $527 - $729 $1,036 - $1,578 Case B: 100% PDP Hedged $20 - $133 $489 - $716 $527 - $729 $1,036 - $1,578 $80 / BBL Case A: Unhedged $116 - $229 $631 - $858 $600 - $802 $1,347 - $1,889 Case B: 100% PDP Hedged $116 - $229 $631 - $858 $592 - $794 $1,339 - $1,881 Note: Assumes strip pricing as of 5/19/2026 $/bbl / $/mmcf: $97.18| $81.59 | $76.84; $3.34| $3.54 | $3.72; $ in millions; Assumes $/bbl hedge pricing of 2H 2026: $70 floor / $113.50 ceiling | 2027: $70 floor / $87.30 ceiling | 2028: $70 floor / $79.00 ceiling. Management estimates are inherently uncertain and subject to numerous risks. Actual results may differ in a material amount from management estimates and projections. (1) Non-GAAP metric; for additional information, refer to p.27.

22 Sable management team is an award-winning, safe, and prudent California Operator Two commendations from the Air Pollution Control District for Emissions Reductions and Use of Innovative Emissions Control Technology at the Arroyo Grande Oil Field  “Due to PXP’s generosity and civic mindedness … [using] their facility, nearly 200 firefighters have received important Survival Training” – Ron Lawrence, Central Regional Training / Safety Captain LA County Fire Department  “The Culver City Fire Department is forever grateful to Plains Exploration & Production Co. for their continued training support and expertise” – Tim Wilson, Captain / Training Officer, Culver City Fire Dept. Health, Safety, and Environmental Highlights Risk Management Partner to Local Communities Offshore California Highlights  Sable Management has a track record of excellence as a safe and responsible steward of California’s onshore and offshore resources  As PXP, owned / operated offshore Point Arguello (Harvest Platform, Hermosa Platform, and Hidalgo Platform) and Point Pedernales (Irene Platform)  Onshore operations included Arroyo Grande, Los Angeles Basin, and San Joaquin Valley assets 2011: Occupational Excellence Achievement Award for 21 PXP locations 2009-2010: Perfect Record Award for operating 11,390 employee hours without occupational injury or illness involving days away from work 2009: National Industry Leadership Award 2007-2008: Occupational Excellence Achievement Awards for Outstanding Safety Practices Occupational Excellence Achievement Awards for Outstanding Safety Practices 2008-2004: Recipient of the Environmental Lease Maintenance Award 2006: Recipient of the Clean Lease Awards Division of Oil, Gas and Geothermal Resources (DOGGR) Lease Maintenance Award for Outstanding Safety and Lease Maintenance 12 years and 13 years in a row at Packard and San Vicente 2004: Received Santa Barbara County’s First and Only “Resolution for Good Operator” Recognizing PXP’s Outstanding Operating Performance 2008: Santa Barbara County Commendation for Outstanding Maintenance Practices at LOGP 2004: Ranked MMS’s Best Operator in the Pacific OCS for Safety of Platform and Pipeline Operations Onshore California Highlights 2010: Occupational Excellence Achievement Award for PXP’s California Los Angeles Basin San Vicente and Packard locations 2006: U.S. Bureau of Land Management Operator of the Year Award 2006: Best Management Practices National Award in Habitat Conservation (1) (1) Minerals Management Service (MMS) was reorganized into Bureau of Ocean Energy Management (BOEM) and Bureau of Safety and Environmental Enforcement (BSEE) in 2011. Platform Hondo Platform Harmony Platform Heritage CA Dept. of Conservation

23 Key Investment Highlights  SYU has a 30+ year history of slow base declines between 6-8%  Shallow decline profile reduces reinvestment rate required to maintain projected production Shallow Decline  Modest reinvestment required in the near-term as Sable capitalizes on production optimization operations including workovers, Perf Adds, and ESP installations Primed for Low-Cost Production Growth  In the near-term, Sable will target Perf Adds with minimal capex, while focusing on deleveraging with 100+ locations still to be drilled  Highly-economic development opportunities from infill and step-out locations with decades of performance history Large Development Inventory Opportunity  100% operated with favorable 16.4% royalty burden  Owned midstream infrastructure ensures safe and reliable transit to marketing hub High Operational Control  47.5 – 52.5 MBoe/d estimated net production in 2027E & 2028E  Substantial production base that is ~90% oil with decades of productive history Large Production Base  Oil sales linked to Brent Crude pricing  LA refinery complex seeks domestic oil production to offset import disruptions Access to Infrastructure & End Markets Premier asset and experienced management team drive stakeholder value  Defense Production Act order requires oil transportation through the SYPS  Interstate pipeline determination requires federal regulatory oversight of the SYPS  Federal offshore development permitting regime through U.S. Department of the Interior Transition to Federal Oversight  Outstanding HS&E and operational track record in CaliforniaHS&E Stewardship  Sable management targeting long-term leverage ratios of ~1.0xConservative Financial Policy (1) Management estimates are inherently uncertain and subject to numerous risks. Actual results may differ in a material amount from management estimates and projections.

Appendix

25 California: Energy Island in Crisis The domestic energy market in California is struggling and needs local production for stabilization Refinery Closures Source: EIA, California Energy Commission. (1) 1.5 MMBbl/d of California petroleum consumption per EIA. (2) List of countries that import oil into California is illustrative and not comprehensive. Commentary  Policy decisions have caused energy infrastructure closures and production decreases across all major segments: exploration & production, midstream transport, and refining and marketing  Given the absence of domestic energy supply, California has relied on foreign nations to import the required oil supply to meet the 1.5 MMBbl/d of demand(1)  California is in desperate need of increased local oil output, but a decades-long underinvestment in the supply chain due to the regulatory environment offers very little opportunity for immediate solutions outside of Sable  California consumers and the 40+ United States Military installations in state are vulnerable Dependence on Unreliable Foreign Producers Crude Oil Production Shortfall – 500 1,000 1,500 2,000 2,500 – 10 20 30 40 50 1982 1991 1999 2008 2016 2025 O pe ra tin g R ef in in g C ap ac ity (M B bl /d ) # of O pe ra tin g R ef in er ie s # of Operating Refineries Operating Refining Capacity (MBbl/d) (66%) Decrease (27%) Decrease – 200 400 600 800 1,000 1,200 1982 1989 1996 2003 2010 2017 2025 California Crude Oil Production (MBbl/d) (75%) Decrease 23% 16% 61% 2025 Source of CA Oil Supply California Alaska Foreign –% 20% 40% 60% 80% 100% 1982 1989 1996 2003 2010 2017 2025 Source of California Oil Supply (%) California Alaska Foreign (2) (2)

26 California: Exposed to Unreliable Foreign Markets Imports carry risk of geopolitical conflicts, infrastructure fragility and a structural shift in trade policy The Middle East Provides ~29%(1) of Foreign Oil Imports to California Source: EIA, California Energy Commission. (1) Represents percent of 2025 volumes. % of South American Imports by Country(1)  Conflict in Iran has renewed threats to the Strait of Hormuz, a critical transit point for ~29%1 of California’s foreign oil  Following a national vote to halt drilling in Block 43, Ecuador’s production faces a projected 34% decline in that region  Guerrilla attacks in Colombia remain a persistent threat to infrastructure, including explosive attacks on the Bicentenario pipeline  Foreign oil imports carry “geopolitical tax” driven by transit risk and local instability; increasing local production eliminates price premiums associated with global supply shocks and stabilizes the state’s energy against foreign interference South American Imports are not Risk-Free and Represent ~56%(1) of Foreign Oil Imports to California 61.0% 27.3% 11.7% Iraq Saudi Arabia UAE  Transit Vulnerability: Consistent attacks on regional production and the credible threat of a Strait of Hormuz disruption place nearly one-third of California's foreign supply at risk of immediate severance  Individual Risks: Beyond the current conflict, each Middle Eastern nation is at risk of supply disruptions as a result of treaty expirations, additional history of regional conflicts and infrastructure fragility  Safe-Haven Pricing: The March 2026 war escalation strengthened the dollar and spreads, making Middle Eastern barrels significantly more expensive for California refiners compared to domestic alternatives 32.0% 24.4% 21.2% 15.7% 6.7%  Operational Tail Risk (Brazil – 32.0%): High dependency on Petrobras' offshore fleet exposes California to systemic maintenance delays and state-owned enterprise related risks  Territorial Risk (Guyana – 24.4%): Escalating territorial claim by Venezuela over the Essequibo region, which comprises ~70% of Guyana's territory and nearly all of its offshore oil blocks  Referendum Risk (Ecuador – 21.2%): The 2023 Yasuni vote demonstrates that South American supply can be terminated by popular vote or judicial decree, regardless of long-term export contracts  Infrastructure Sabotage (Colombia – 6.7%): Frequent bombings of the Bicentenario and Caño Limón-Coveñas pipelines prove that South American supply is subject to asymmetric warfare and domestic civil unrest Brazil Guyana Ecuador Argentina Colombia % of Middle Eastern Imports by Country(1) Imports are at risk of significant disruption, as evidenced by recent history and current affairs

27 Non-GAAP Reconciliation Q2 – Q4 2026E FY 2027E FY 2028E Non-GAAP Item Reconciliation Net income (loss) $192 - $256 $287 - $382 $259 - $346 Addback: Interest expense, net(1) $96 - $129 $129 - $173 $129 - $173 Addback: Income tax expense (benefit) $22 - $29 $107 - $143 $98 - $131 EBIT $310 - $414 $523 - $698 $486 - $650 Addback: DD&A, ARO accretion $82 - $110 $142 - $190 $145 - $194 EBITDA $392 - $524 $665 - $888 $631 - $844 Addback: Share-based comp $42 - $56 $73 - $97 $70 - $93 Adjusted EBITDA $434 - $580 $738 - $985 $701 - $937 Payments for capital expenditures ($163) - ($196) ($73) - ($88) ($64) - ($77) Income tax (excludes deferred taxes) -- ($26) - ($31) ($105) - ($126) Unlevered free cash flow $271 - $384 $639 - $866 $532 - $734 Note: Management estimates are inherently uncertain and subject to numerous risks. Actual results may differ in a material amount from management estimates and projections. (1) Estimated interest expense assumes status quo capital structure

June 1, 2026 Mr. Brian K. Broussard Sable Offshore Corp. 845 Texas Avenue, Suite 2920 Houston, Texas 77002 Dear Mr. Broussard: In accordance with your request, we have estimated the proved, probable, and possible developed reserves and future revenue, as of May 31, 2026, to the Sable Offshore Corp. (Sable) interest in certain oil and gas properties located in the Santa Ynez Unit (SYU), federal waters offshore California. Sable resumed the transportation of hydrocarbons through the Santa Ynez Pipeline System (SYPS) and initiated oil sales from the SYU on March 29, 2026. Discussion of legal risks associated with hydrocarbon transportation and sales is set forth in Sable’s 10-Q quarterly financial report filed with the U.S. Securities and Exchange Commission on May 6, 2026. We completed our evaluation on or about the date of this letter. It is our understanding that the proved reserves estimated in this report constitute all of the proved reserves owned by Sable. The estimates in this report have been prepared in accordance with the definitions and regulations of the U.S. Securities and Exchange Commission (SEC) and conform to the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas, except that future income taxes are excluded and, as requested, overhead expenses are excluded. Definitions are presented immediately following this letter. This report has been prepared for Sable's use in filing with the SEC; in our opinion the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for such purpose. We estimate the net reserves and future net revenue to the Sable interest in these properties, as of May 31, 2026, to be: Net Reserves Future Net Revenue(1) (M$) Oil NGL Gas Present Worth Category (MBBL) (MBBL) (MMCF) Total at 10% Proved Developed Producing 66,609.6 686.7 44,988.1 685,995.7 766,540.7 Proved Developed Non-Producing 23,849.6 501.9 32,880.2 1,139,432.2 705,763.2 Total Proved Developed 90,459.2 1,188.6 77,868.2 1,825,427.9 1,472,303.9 Probable Developed 28,695.9 387.3 25,369.4 1,039,765.8 607,926.8 Possible Developed 40,607.2 593.9 38,909.3 1,612,952.8 850,339.6 Totals may not add because of rounding. (1) Future net revenue is after deducting estimated abandonment costs. The oil volumes shown include crude oil only. Oil and natural gas liquids (NGL) volumes are expressed in thousands of barrels (MBBL); a barrel is equivalent to 42 United States gallons. Gas volumes are expressed in millions of cubic feet (MMCF) at standard temperature and pressure bases. Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production status. Our study indicates that as of May 31, 2026, there are no proved undeveloped reserves for these properties. No study was made to determine whether probable or possible undeveloped reserves might be established for these properties. The estimates of reserves and future revenue included herein have not

been adjusted for risk. This report does not include any value that could be attributed to interests in undeveloped acreage. Gross revenue is Sable's share of the gross (100 percent) revenue from the properties prior to any deductions. Future net revenue is after deductions for Sable's share of property taxes, capital costs, abandonment costs, and operating expenses but before consideration of any income taxes. The future net revenue has been discounted at an annual rate of 10 percent to determine its present worth, which is shown to indicate the effect of time on the value of money. Future net revenue presented in this report, whether discounted or undiscounted, should not be construed as being the fair market value of the properties. Prices used in this report are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period June 2025 through May 2026. For oil and NGL volumes, the average Brent spot price of $75.72 per barrel is adjusted for quality and market differentials. For gas volumes, the average Henry Hub spot price of $3.599 per MMBTU is adjusted for energy content, transportation fees, and market differentials. The adjusted product prices of $56.06 per barrel of oil, $59.21 per barrel of NGL, and $3.061 per MCF of gas are held constant throughout the lives of the properties. Operating costs used in this report are based on operating expense records of Exxon Mobil Corporation, the previous operator of the properties, as provided by Sable, and include only direct lease- and field-level costs. Operating costs have been divided into field-level costs, per-well costs, and per-unit-of-production costs and include the costs associated with operating the oil export pipeline. As requested, these costs do not include the headquarters general and administrative overhead expenses of Sable. Operating costs are not escalated for inflation. Capital costs used in this report were provided by Sable and are based on authorizations for expenditure, actual costs from recent activity, and internal planning budgets. Capital costs are included as required for commissioning of offshore and onshore facilities, workovers, and facility integrity projects. Based on our understanding of future development plans, a review of the records provided to us, and our knowledge of similar properties, we regard these estimated capital costs to be reasonable. Abandonment costs used in this report are Sable's estimates of the costs to abandon the wells, platforms, offshore and onshore facilities, and pipelines, net of any salvage value. Capital costs and abandonment costs are not escalated for inflation. For the purposes of this report, we did not perform any field inspection of the properties, nor did we examine the mechanical operation or condition of the wells and facilities. We have not investigated possible environmental liability related to the properties; therefore, our estimates do not include any costs due to such possible liability. Additionally, we have made no specific investigation of any firm transportation contracts that may be in place for these properties; our estimates of future revenue include the effects of such contracts only to the extent that the associated fees are accounted for in the historical field-level accounting statements. The reserves shown in this report are estimates only and should not be construed as exact quantities. Proved reserves are those quantities of oil and gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be economically producible; probable and possible reserves are those additional reserves which are sequentially less certain to be recovered than proved reserves. Estimates of reserves may increase or decrease as a result of market conditions, future operations, changes in regulations, or actual reservoir performance. In addition to the primary economic assumptions discussed herein, our estimates are based on certain assumptions including, but not limited to, that the properties will be developed consistent with current development plans as provided to us by Sable, that the properties will be operated in a prudent manner, that no governmental regulations or controls will be put in place that would impact the ability of the interest owner to recover the reserves, and that our projections of future production will prove consistent with actual performance. If the reserves are recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts. Because of governmental policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary from assumptions made while preparing this report.

For the purposes of this report, we used technical and economic data including, but not limited to, well logs, geologic maps, well test data, production data, historical price and cost information, and property ownership interests. The reserves in this report have been estimated using deterministic methods; these estimates have been prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards). We used standard engineering and geoscience methods, or a combination of methods, including performance analysis and analogy, that we considered to be appropriate and necessary to categorize and estimate reserves in accordance with SEC definitions and regulations. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarily represent only informed professional judgment. The data used in our estimates were obtained from Sable, public data sources, and the nonconfidential files of Netherland, Sewell & Associates, Inc. (NSAI) and were accepted as accurate. Supporting work data are on file in our office. We have not examined the titles to the properties or independently confirmed the actual degree or type of interest owned. The technical persons primarily responsible for preparing the estimates presented herein meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the SPE Standards. John R. Cliver, a Licensed Professional Engineer in the State of Texas, has been practicing consulting petroleum engineering at NSAI since 2009 and has over 5 years of prior industry experience. Edward C. Roy III, a Licensed Professional Geoscientist in the State of Texas, has been practicing consulting petroleum geoscience at NSAI since 2008 and has over 11 years of prior industry experience. We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these properties nor are we employed on a contingent basis. Sincerely, NETHERLAND, SEWELL & ASSOCIATES, INC. Texas Registered Engineering Firm F-2699 By: Richard B. Talley, Jr., P.E. Chairman and Chief Executive Officer By: By: John R. Cliver, P.E. 107216 Edward C. Roy III, P.G. 2364 Senior Vice President Vice President Date Signed: June 1, 2026 Date Signed: June 1, 2026 JRC:WKE

DEFINITIONS OF OIL AND GAS RESERVES Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a) Definitions - Page 1 of 6 The following definitions are set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Section 210.4-10(a). Also included is supplemental information from (1) the 2018 Petroleum Resources Management System approved by the Society of Petroleum Engineers, (2) the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas, and (3) the SEC's Compliance and Disclosure Interpretations. (1) Acquisition of properties. Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease bonuses and options to purchase or lease properties, the portion of costs applicable to minerals when land including mineral rights is purchased in fee, brokers' fees, recording fees, legal costs, and other costs incurred in acquiring properties. (2) Analogous reservoir. Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an "analogous reservoir" refers to a reservoir that shares the following characteristics with the reservoir of interest: (i) Same geological formation (but not necessarily in pressure communication with the reservoir of interest); (ii) Same environment of deposition; (iii) Similar geological structure; and (iv) Same drive mechanism. Instruction to paragraph (a)(2): Reservoir properties must, in the aggregate, be no more favorable in the analog than in the reservoir of interest. (3) Bitumen. Bitumen, sometimes referred to as natural bitumen, is petroleum in a solid or semi-solid state in natural deposits with a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis. In its natural state it usually contains sulfur, metals, and other non-hydrocarbons. (4) Condensate. Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature. (5) Deterministic estimate. The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure. (6) Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be recovered: (i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. Supplemental definitions from the 2018 Petroleum Resources Management System: Developed Producing Reserves – Expected quantities to be recovered from completion intervals that are open and producing at the effective date of the estimate. Improved recovery Reserves are considered producing only after the improved recovery project is in operation. Developed Non-Producing Reserves – Shut-in and behind-pipe Reserves. Shut-in Reserves are expected to be recovered from (1) completion intervals that are open at the time of the estimate but which have not yet started producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe Reserves are expected to be recovered from zones in existing wells that will require additional completion work or future re-completion before start of production with minor cost to access these reserves. In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well. (7) Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to: (i) Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves. (ii) Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly.

DEFINITIONS OF OIL AND GAS RESERVES Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a) Definitions - Page 2 of 6 (iii) Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems. (iv) Provide improved recovery systems. (8) Development project. A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project. (9) Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive. (10) Economically producible. The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point of oil and gas producing activities as defined in paragraph (a)(16) of this section. (11) Estimated ultimate recovery (EUR). Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date. (12) Exploration costs. Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory- type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to in part as prospecting costs) and after acquiring the property. Principal types of exploration costs, which include depreciation and applicable operating costs of support equipment and facilities and other costs of exploration activities, are: (i) Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are sometimes referred to as geological and geophysical or "G&G" costs. (ii) Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defense, and the maintenance of land and lease records. (iii) Dry hole contributions and bottom hole contributions. (iv) Costs of drilling and equipping exploratory wells. (v) Costs of drilling exploratory-type stratigraphic test wells. (13) Exploratory well. An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well as those items are defined in this section. (14) Extension well. An extension well is a well drilled to extend the limits of a known reservoir. (15) Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field which are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms "structural feature" and "stratigraphic condition" are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc. (16) Oil and gas producing activities. (i) Oil and gas producing activities include: (A) The search for crude oil, including condensate and natural gas liquids, or natural gas ("oil and gas") in their natural states and original locations; (B) The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas from such properties; (C) The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as: (1) Lifting the oil and gas to the surface; and (2) Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and

DEFINITIONS OF OIL AND GAS RESERVES Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a) Definitions - Page 3 of 6 (D) Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction. Instruction 1 to paragraph (a)(16)(i): The oil and gas production function shall be regarded as ending at a "terminal point", which is the outlet valve on the lease or field storage tank. If unusual physical or operational circumstances exist, it may be appropriate to regard the terminal point for the production function as: a. The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery, or a marine terminal; and b. In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a purchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas. Instruction 2 to paragraph (a)(16)(i): For purposes of this paragraph (a)(16), the term saleable hydrocarbons means hydrocarbons that are saleable in the state in which the hydrocarbons are delivered. (ii) Oil and gas producing activities do not include: (A) Transporting, refining, or marketing oil and gas; (B) Processing of produced oil, gas, or natural resources that can be upgraded into synthetic oil or gas by a registrant that does not have the legal right to produce or a revenue interest in such production; (C) Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and gas can be extracted; or (D) Production of geothermal steam. (17) Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. (i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates. (ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project. (iii) Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves. (iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects. (v) Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir. (vi) Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations. (18) Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. (i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

DEFINITIONS OF OIL AND GAS RESERVES Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a) Definitions - Page 4 of 6 (ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir. (iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves. (iv) See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section. (19) Probabilistic estimate. The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence. (20) Production costs. (i) Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. They become part of the cost of oil and gas produced. Examples of production costs (sometimes called lifting costs) are: (A) Costs of labor to operate the wells and related equipment and facilities. (B) Repairs and maintenance. (C) Materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities. (D) Property taxes and insurance applicable to proved properties and wells and related equipment and facilities. (E) Severance taxes. (ii) Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation, refining, and marketing activities. To the extent that the support equipment and facilities are used in oil and gas producing activities, their depreciation and applicable operating costs become exploration, development or production costs, as appropriate. Depreciation, depletion, and amortization of capitalized acquisition, exploration, and development costs are not production costs but also become part of the cost of oil and gas produced along with production (lifting) costs identified above. (21) Proved area. The part of a property to which proved reserves have been specifically attributed. (22) Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. (i) The area of the reservoir considered as proved includes: (A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data. (ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty. (iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty. (iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

DEFINITIONS OF OIL AND GAS RESERVES Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a) Definitions - Page 5 of 6 (B) The project has been approved for development by all necessary parties and entities, including governmental entities. (v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. (23) Proved properties. Properties with proved reserves. (24) Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease. (25) Reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. (26) Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project. Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations). Excerpted from the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas: 932-235-50-30 A standardized measure of discounted future net cash flows relating to an entity's interests in both of the following shall be disclosed as of the end of the year: a. Proved oil and gas reserves (see paragraphs 932-235-50-3 through 50-11B) b. Oil and gas subject to purchase under long-term supply, purchase, or similar agreements and contracts in which the entity participates in the operation of the properties on which the oil or gas is located or otherwise serves as the producer of those reserves (see paragraph 932-235-50-7). The standardized measure of discounted future net cash flows relating to those two types of interests in reserves may be combined for reporting purposes. 932-235-50-31 All of the following information shall be disclosed in the aggregate and for each geographic area for which reserve quantities are disclosed in accordance with paragraphs 932-235-50-3 through 50-11B: a. Future cash inflows. These shall be computed by applying prices used in estimating the entity's proved oil and gas reserves to the year-end quantities of those reserves. Future price changes shall be considered only to the extent provided by contractual arrangements in existence at year-end. b. Future development and production costs. These costs shall be computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. If estimated development expenditures are significant, they shall be presented separately from estimated production costs. c. Future income tax expenses. These expenses shall be computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pretax net cash flows relating to the entity's proved oil and gas reserves, less the tax basis of the properties involved. The future income tax expenses shall give effect to tax deductions and tax credits and allowances relating to the entity's proved oil and gas reserves. d. Future net cash flows. These amounts are the result of subtracting future development and production costs and future income tax expenses from future cash inflows.

DEFINITIONS OF OIL AND GAS RESERVES Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a) Definitions - Page 6 of 6 e. Discount. This amount shall be derived from using a discount rate of 10 percent a year to reflect the timing of the future net cash flows relating to proved oil and gas reserves. f. Standardized measure of discounted future net cash flows. This amount is the future net cash flows less the computed discount. (27) Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs. (28) Resources. Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations. (29) Service well. A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion. (30) Stratigraphic test well. A stratigraphic test well is a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as "exploratory type" if not drilled in a known area or "development type" if drilled in a known area. (31) Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. (i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. (ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time. From the SEC's Compliance and Disclosure Interpretations (October 26, 2009): Although several types of projects — such as constructing offshore platforms and development in urban areas, remote locations or environmentally sensitive locations — by their nature customarily take a longer time to develop and therefore often do justify longer time periods, this determination must always take into consideration all of the facts and circumstances. No particular type of project per se justifies a longer time period, and any extension beyond five years should be the exception, and not the rule. Factors that a company should consider in determining whether or not circumstances justify recognizing reserves even though development may extend past five years include, but are not limited to, the following:  The company's level of ongoing significant development activities in the area to be developed (for example, drilling only the minimum number of wells necessary to maintain the lease generally would not constitute significant development activities);  The company's historical record at completing development of comparable long-term projects;  The amount of time in which the company has maintained the leases, or booked the reserves, without significant development activities;  The extent to which the company has followed a previously adopted development plan (for example, if a company has changed its development plan several times without taking significant steps to implement any of those plans, recognizing proved undeveloped reserves typically would not be appropriate); and  The extent to which delays in development are caused by external factors related to the physical operating environment (for example, restrictions on development on Federal lands, but not obtaining government permits), rather than by internal factors (for example, shifting resources to develop properties with higher priority). (iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty. (32) Unproved properties. Properties with no proved reserves.

FAQ

What does Sable Offshore Corp. (SOC) highlight about Santa Ynez Unit reserves?

Sable Offshore highlights net estimated reserves of 659 MMBoe at Santa Ynez Unit, with a PV-10 value of about $6.07 billion at Brent strip pricing. These estimates include proved, probable and possible cases and are supported by an independent reserve report from Netherland, Sewell & Associates.

What production levels does Sable Offshore (SOC) target for the Santa Ynez Unit?

Sable targets fully ramped gross production of about 62,000 Boe per day from the Harmony, Heritage and Hondo platforms. For 2027 and 2028, guidance calls for net production of 47.5–52.5 MBoe per day, with 90–92% of volumes expected to be oil, assuming current plans.

What financial guidance does Sable Offshore (SOC) provide for 2027–2028?

For 2027, Sable guides to adjusted EBITDA of $738–$985 million and unlevered free cash flow of $639–$866 million. For 2028, it projects adjusted EBITDA of $701–$937 million and unlevered free cash flow of $532–$734 million, based on strip pricing and planned capital spending.

How is Sable Offshore (SOC) addressing its debt and leverage profile?

As of March 31, 2026, Sable shows total debt of $956 million, net debt of $904 million and total enterprise value of $3,223 million. The company is pursuing a refinancing of the Exxon term loan maturing June 26, 2026 and targets long-term leverage ratios around 1.0x.

What is Sable Offshore’s (SOC) hedging strategy through 2028?

Sable plans to hedge 100% of expected proved developed producing oil volumes through 2028 using costless collars and deferred premium puts. The goal is to establish downside price protection while leaving longer-term upside uncapped, with specific floor and ceiling prices outlined for 2026–2028.

What recent federal actions support Sable Offshore’s (SOC) pipeline operations?

Federal agencies have recognized the Santa Ynez Pipeline System as an interstate pipeline under PHMSA, issued an emergency special permit and approved a restart plan. The U.S. Department of Energy also issued a Defense Production Act order in March 2026 directing Sable to prioritize transportation of hydrocarbons from Santa Ynez Unit.

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