Athabasca Oil Announces its 2026 Budget Focused on Production and Cash Flow Per Share Growth

CALGARY, Alberta, Dec. 11, 2025 (GLOBE NEWSWIRE) — Athabasca Oil Corporation (TSX: ATH) (“Athabasca” or the “Company”) is pleased to announce its 2026 budget with capital projects driving profitable growth within its core assets, along with a continued return of 100% of Free Cash Flow to shareholders.

Corporate Strategy – Differentiated Value Creation

Thermal Oil Scale. The Company’s Thermal Oil division provides an oil focused platform underpinning funded growth to >60,000 bbl/d by 2030 with Phase 1 of Corner. The Thermal Oil assets have a resource base of 1.2 billion barrels of proved plus probable reserves and 1 billion barrels of contingent resource, providing optionality to reach over 90,000 bbl/d with regulatory approvals in place. The Thermal Oil assets have an operating break-even of ~US$40/bbl WTI and growth initiatives at Leismer are fully funded within cash flow to ~US$48/bbl WTI.

Duvernay Value Proposition. Athabasca’s subsidiary company, Duvernay Energy Corporation (“DEC”), is designed to enhance value for shareholders by providing a clear path for self-funded production and cash flow growth in the Kaybob Duvernay resource play. DEC has an independent strategy and capital allocation framework with production expected at >15,000 boe/d by 2030 with ~20 years of future drilling inventory. Value crystallization for shareholders is expected once the asset has reached a material scale through its exceptional land base and drilling inventory.

Financial Resilience. Athabasca maintains a strong and differentiated balance sheet with a $93 million consolidated Net Cash position, including ~$335 million of cash. Athabasca (Thermal Oil) also has $2.1 billion in tax pools, including $1.6 billion of immediately deductible non-capital losses and exploration pools, sheltering cash taxes beyond 2030.

Exceptional Shareholder Returns. In 2026, Athabasca will continue to allocate 100% of Free Cash Flow generated in its Thermal Oil division to share buybacks. The Company has returned ~$1.1 billion to shareholders since 2021, including $386 million of debt reduction and $695 million of share buybacks (22% reduction in fully diluted shares at an average price of $4.77/sh). The Company sees significant intrinsic value in its shares underpinned by its net asset value. A differentiated balance sheet affords the Company strategic flexibility to augment its Free Cash Flow return of capital framework. Athabasca forecasts $1.1 billion of additional Free Cash Flow over the next five years while funding its growth initiatives at Leismer and Corner.

Focus on Per Share Metrics. Advancing attractive capital projects concurrent with a strong focus on share buybacks results in a >20% compounded annual cash flow per share² to 2030 and beyond.

2026 Corporate Consolidated Budget and Outlook

Consolidated Budget. Athabasca is planning capital expenditures of ~$310 million with average production of 37,000 – 39,000 boe/d (98% Liquids), inclusive of a ~2,500 boe/d impact of planned turnarounds across its assets. Growth will materialize in the second half of 2026 with an exit rate of ~43,000 boe/d, driven by the Leismer expansion project. Strong operational momentum is expected to continue into 2027 as Leismer ramps up to regulatory capacity and additional Duvernay production is added.

Cash Flow Outlook. The Company forecasts consolidated Adjusted Funds Flow between $425 – $450 million¹ in 2026. With operational momentum into 2027, Adjusted Funds Flow and Free Cash Flow are expected to grow significantly year over year. Every +US$1/bbl move in West Texas Intermediate (“WTI”) and Western Canadian Select (“WCS”) heavy oil impacts 2026 annual Adjusted Funds Flow by ~$10 million and ~$17 million, respectively.

Balance Sheet Management. Athabasca will prudently manage its capital structure as operations increase in scale. A Net Cash position currently provides the Company strategic flexibility for its business initiatives including multi-year capital projects and supplementing strategic share buybacks. Athabasca is committed to maintaining a best-in-class balance sheet with a targeted Net Debt to Adjusted Funds Flow metric less than 0.5x over the long-term.

^{Footnote: Refer to the “Reader Advisory” section within this news release for additional information on Non‐GAAP Financial Measures (e.g. Adjusted Funds Flow, Free Cash Flow, Sustaining Capital, Net Cash) and production disclosure.
¹Pricing Assumptions: 2026+ US$65 WTI, US$12.50 WCS heavy differential, C$3 AECO, and 0.725 C$/US$ FX.
²The Company’s illustrative multi-year outlook assumes 100% of Free Cash Flow is directed to share buybacks up to a 10% Normal Course Issuer Bid limit at an implied share price of 6x Enterprise Value/Debt Adjusted Cash Flow in 2027 and beyond.}

Athabasca (Thermal Oil) – 2026 Budget Highlights

Capital Budget. The Thermal Oil budget is $273 million, inclusive of $25 million of turnaround capital, with activity focused on advancing the Leismer expansion.

Production Outlook. Annual Thermal Oil production guidance is 32,000 – 34,000 bbl/d, inclusive of a ~2,250 bbl/d impact of planned turnarounds. The Company is positioned for strong operational momentum exiting 2026 and through 2027 when production is expected to reach ~48,000 bbl/d.

Leismer Program. The capital program at Leismer is $240 million. Activity includes bringing on twelve new wells at Pad L10 and L11 to support growth and facility expansion work consisting of the addition of two steam generators, heat exchangers and increased fluid handling capacity. A three-week facility turnaround will be completed in May (four-year interval) when all tie-ins for the expansion project will also be completed. The new well pairs will begin steaming following the turnaround, positioning the asset for a strong exit rate. The $300 million expansion project will be substantially complete at the end of 2026 with production growth to 40,000 bbl/d by the end of 2027. Overall capital and schedule are on track with original expectations at a capital efficiency of ~$25,000/bbl/d.

Hangingstone Program. The capital program at Hangingstone is $17 million and activity includes a two-week turnaround (six-year interval) in April and routine maintenance. Hangingstone production will be maintained at ~8,000 bbl/d through the mid-term by utilizing existing plant capacity with attractive capital efficiencies of <$20,000/bbl/d for sustaining wells.

Corner Growth Preparation. The 2026 budget includes $16 million at Corner to advance project readiness. Development plans are focused on capital-efficient modular design with 15,000 bbl/d project phases. The project is expected to be self-funded while maintaining a strong balance sheet and a focus on shareholder returns. The Company anticipates Phase 1 to be sanctioned in 2026, contingent on a favorable macro environment, with the majority of the capital to follow the current Leismer expansion project. Phase 1 will provide substantial production growth starting in 2029. The full Corner development to 40,000 bbl/d is expected to have a capital efficiency of $30,000 – $35,000/bbl/d.

Duvernay Energy Corporation – 2026 Budget Highlights

Capital Budget. The DEC budget is ~$38 million and includes drilling a 100% working interest (“WI”) land retention well, drilling and completing a 30% WI four-well pad and readiness activity for future development pads. Accelerated operated activity in the second half of the year will be contingent on a favorable macro environment.

Production Outlook. Annual DEC production guidance is 4,500 – 5,000 boe/d (78% Liquids), representing ~35% annual growth.

Strong Well Results. DEC recently brought onstream a three-well pad (100% WI) at 04-18-064-16W5 (“04-18 pad”) with average lateral lengths of ~4,000 meters. The 4-18 pad had an average IP30 rate of ~1,125 boe/d per well (90% Liquids, primarily free condensate). A four-well pad (30% WI) at 16-27-064-17-W5 (“16-27 pad”) with average laterals of approximately 5,000 meters was placed on production in August. The 16-27 pad had an average IP30 rate of ~1,040 boe/d per well (89% Liquids, primarily free condensate) and an average IP90 rate of ~945 boe/d per well (86% Liquids, primarily free condensate). DEC is pleased by the strong production results of both pads with initial rates and free condensate yields exceeding management type curves.

Growth Plans. Development will be self-funded within DEC through utilization of 100% of its annual Adjusted Funds Flow and its balance sheet. The Company has a de-risked drilling inventory of 444 gross wells with self-funded growth potential to in excess of ~15,000 boe/d (75% Liquids) by 2030¹. DEC provides short cycle growth opportunities with flexible development plans aligned to commodity prices. Value crystallization for shareholders is expected once the asset has reached a material scale through its exceptional land base and drilling inventory.

Enhanced Market Access

Athabasca continues to diversify its end market access for its current development plans providing protection to local market differential volatility and certainty for long-term egress. The Company has now secured 57,000 bbl/d of blended long-term capacity to markets outside of Edmonton, including 47,000 bbl/d of capacity with exposure to the US Gulf Coast (PADD III) and 10,000 bbl/d to the US Midwest (PADD II).

Egress has been secured at competitive transportation rates, without balance sheet encumbrances, and will support the Company’s development plans across its Thermal Oil portfolio. Athabasca anticipates that it will have enough egress capacity to support its growth initiatives, regardless of new pipeline initiatives that are undertaken by Industry.

Executive Addition

Athabasca is pleased to announce the appointment of Mr. Paul Vander Valk as Vice President, Projects & Well Delivery. Mr. Vander Valk is a professional engineer, holds a MBA and has ~30 years of major projects and oil and gas industry experience. Mr. Vander Valk has held the role of Director, Projects & Well Delivery at Athabasca for the past three years. Prior to joining Athabasca, he was the Chief Operating Officer for Harvest, and held several positions with Cenovus including Vice President, Production Systems. As the Company prepares to sanction Corner, its third major Thermal development area, it is bolstering its Executive team to support the execution of ongoing growth initiatives.

About Athabasca Oil Corporation

Athabasca Oil Corporation is a Canadian energy company with a focused strategy on the development of thermal and light oil assets. Situated in Alberta’s Western Canadian Sedimentary Basin, the Company has amassed a significant land base of extensive, high quality resources. Athabasca’s light oil assets are held in a private subsidiary (Duvernay Energy Corporation) in which Athabasca owns a 70% equity interest. Athabasca’s common shares trade on the TSX under the symbol “ATH”. For more information, visit www.atha.com.

_{Reader Advisory:}

_{This News Release contains forward-looking information that involves various risks, uncertainties and other factors. All information other than statements of historical fact is forward-looking information. The use of any of the words “anticipate”, “plan”, “project”, “continue”, “maintain”, “may”, “estimate”, “expect”, “will”, “target”, “forecast”, “could”, “intend”, “potential”, “guidance”, “outlook” and similar expressions suggesting future outcome are intended to identify forward-looking information. The forward-looking information is not historical fact, but rather is based on the Company’s current plans, objectives, goals, strategies, estimates, assumptions and projections about the Company’s industry, business and future operating and financial results. This information involves known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking information. No assurance can be given that these expectations will prove to be correct and such forward-looking information included in this News Release should not be unduly relied upon. This information speaks only as of the date of this News Release. In particular, this News Release contains forward-looking information pertaining to, but not limited to, the following: our strategic plans; the allocation of future capital; timing and quantum for shareholder returns including share buybacks; the terms of our NCIB program; our drilling plans; our growth plans; capital efficiencies; production growth to expected production rates and estimated sustaining capital amounts; timing of Leismer’s and Hangingstone’s pre-payout royalty status; applicability of tax pools; Adjusted Funds Flow and Free Cash Flow over various periods; type well economic metrics; number of drilling locations; forecasted daily production and the composition of production; break-even metrics, market access, our outlook in respect of the Company’s business environment, including in respect of commodity pricing; and other matters.}

_{In addition, information and statements in this News Release relating to “Reserves” and “Resources” are deemed to be forward-looking information, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves and resources described exist in the quantities predicted or estimated, and that the reserves and resources described can be profitably produced in the future. With respect to forward-looking information contained in this News Release, assumptions have been made regarding, among other things: commodity prices; the regulatory framework governing royalties, taxes and environmental matters in the jurisdictions in which the Company conducts and will conduct business and the effects that such regulatory framework will have on the Company, including on the Company’s financial condition and results of operations; the Company’s financial and operational flexibility; the Company’s financial sustainability; Athabasca’s cash flow break-even commodity price; the Company’s ability to obtain qualified staff and equipment in a timely and cost-efficient manner; the applicability of technologies for the recovery and production of the Company’s reserves and resources; future capital expenditures to be made by the Company; future sources of funding for the Company’s capital programs; the Company’s future debt levels; future production levels; the Company’s ability to obtain financing and/or enter into joint venture arrangements, on acceptable terms; operating costs; compliance of counterparties with the terms of contractual arrangements; impact of increasing competition globally; collection risk of outstanding accounts receivable from third parties; geological and engineering estimates in respect of the Company’s reserves and resources; recoverability of reserves and resources; the geography of the areas in which the Company is conducting exploration and development activities and the quality of its assets. Certain other assumptions related to the Company’s Reserves and Resources are contained in the report of McDaniel & Associates Consultants Ltd. (“McDaniel”) evaluating Athabasca’s Proved Reserves, Probable Reserves and Contingent Resources as at December 31, 2024 (which is respectively referred to herein as the “McDaniel Report”).}

_{Actual results could differ materially from those anticipated in this forward-looking information as a result of the risk factors set forth in the Company’s Annual Information Form (“AIF”) dated March 5, 2025 available on SEDAR at www.sedarplus.ca, including, but not limited to: weakness in the oil and gas industry; exploration, development and production risks; prices, markets and marketing; market conditions; trade relations and tariffs; climate change and carbon pricing risk; statutes and regulations regarding the environment including deceptive marketing provisions; regulatory environment and changes in applicable law; gathering and processing facilities, pipeline systems and rail; reputation and public perception of the oil and gas sector; environment, social and governance goals; political uncertainty; state of capital markets; ability to finance capital requirements; access to capital and insurance; abandonment and reclamation costs; changing demand for oil and natural gas products; anticipated benefits of acquisitions and dispositions; royalty regimes; foreign exchange rates and interest rates; reserves; hedging; operational dependence; operating costs; project risks; supply chain disruption; financial assurances; diluent supply; third party credit risk; indigenous claims; reliance on key personnel and operators; income tax; cybersecurity; advanced technologies; hydraulic fracturing; liability management; seasonality and weather conditions; unexpected events; internal controls; limitations and insurance; litigation; natural gas overlying bitumen resources; competition; chain of title and expiration of licenses and leases; breaches of confidentiality; new industry related activities or new geographical areas; water use restrictions and/or limited access to water; relationship with Duvernay Energy Corporation; management estimates and assumptions; third-party claims; conflicts of interest; inflation and cost management; credit ratings; growth management; impact of pandemics; ability of investors resident in the United States to enforce civil remedies in Canada; and risks related to our debt and securities. All subsequent forward-looking information, whether written or oral, attributable to the Company or persons acting on its behalf are expressly qualified in their entirety by these cautionary statements.}

_{Also included in this News Release are estimates of Athabasca’s 2026 outlook which are based on the various assumptions as to production levels, commodity prices, currency exchange rates and other assumptions disclosed in this News Release. To the extent any such estimate constitutes a financial outlook, it was approved by management and the Board of Directors of Athabasca and is included to provide readers with an understanding of the Company’s outlook. Management does not have firm commitments for all of the costs, expenditures, prices or other financial assumptions used to prepare the financial outlook or assurance that such operating results will be achieved and, accordingly, the complete financial effects of all of those costs, expenditures, prices and operating results are not objectively determinable. The actual results of operations of the Company and the resulting financial results may vary from the amounts set forth herein, and such variations may be material. The outlook and forward-looking information contained in this New Release was made as of the date of this News release and the Company disclaims any intention or obligations to update or revise such outlook and/or forward-looking information, whether as a result of new information, future events or otherwise, unless required pursuant to applicable law.}

_{Oil and Gas Information}

_{“BOEs” may be misleading, particularly if used in isolation. A BOE conversion ratio of six thousand cubic feet of natural gas to one barrel of oil equivalent (6 Mcf: 1 bbl) is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. As the value ratio between natural gas and crude oil based on the current prices of natural gas and crude oil is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value.}

_{Initial Production Rates} 

_{Test Results and Initial Production Rates: The well test results and initial production rates provided herein should be considered to be preliminary, except as otherwise indicated. Test results and initial production rates disclosed herein may not necessarily be indicative of long-term performance or of ultimate recovery.}

_{Reserves Information}

_{The McDaniel Report was prepared using the assumptions and methodology guidelines outlined in the COGE Handbook and in accordance with National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities, effective December 31, 2024. There are numerous uncertainties inherent in estimating quantities of bitumen, light crude oil and medium crude oil, tight oil, conventional natural gas, shale gas and natural gas liquids reserves and the future cash flows attributed to such reserves. The reserve and associated cash flow information set forth above are estimates only. In general, estimates of economically recoverable reserves and the future net cash flows therefrom are based upon a number of variable factors and assumptions, such as historical production from the properties, production rates, ultimate reserve recovery, timing and amount of capital expenditures, marketability of oil and natural gas, royalty rates, the assumed effects of regulation by governmental agencies and future operating costs, all of which may vary materially. For those reasons, estimates of the economically recoverable reserves attributable to any particular group of properties, classification of such reserves based on risk of recovery and estimates of future net revenues associated with reserves prepared by different engineers, or by the same engineers at different times, may vary. The Company’s actual production, revenues, taxes and development and operating expenditures with respect to its reserves will vary from estimates thereof and such variations could be material. Reserves figures described herein have been rounded to the nearest MMbbl or MMboe. For additional information regarding the consolidated reserves and information concerning the resources of the Company as evaluated by McDaniel in the McDaniel Report, please refer to the Company’s AIF.}

_{Reserve Values (i.e. Net Asset Value) is calculated using the estimated net present value of all future net revenue from our reserves, before income taxes discounted at 10%, as estimated by McDaniel effective December 31, 2024 and based on average pricing of McDaniel, Sproule and GLJ as of January 1, 2025.}

_{The 444 gross Duvernay drilling locations referenced include: 87 proved undeveloped locations and 85 probable undeveloped locations for a total of 172 booked locations with the balance being unbooked locations. Proved undeveloped locations and probable undeveloped locations are booked and derived from the Company’s most recent independent reserves evaluation as prepared by McDaniel as of December 31, 2024 and account for drilling locations that have associated proved and/or probable reserves, as applicable. Unbooked locations are internal management estimates. Unbooked locations do not have attributed reserves or resources (including contingent or prospective). Unbooked locations have been identified by management as an estimation of Athabasca’s multi-year drilling activities expected to occur over the next two decades based on evaluation of applicable geologic, seismic, engineering, production and reserves information. There is no certainty that the Company will drill all unbooked drilling locations and if drilled there is no certainty that such locations will result in additional oil and gas reserves, resources or production. The drilling locations on which the Company will actually drill wells, including the number and timing thereof is ultimately dependent upon the availability of funding, commodity prices, provincial fiscal and royalty policies, costs, actual drilling results, additional reservoir information that is obtained and other factors.}

_{Non-GAAP and Other Financial Measures, and Production Disclosure}

_{The “Corporate Consolidated Adjusted Funds Flow”, “Athabasca (Thermal Oil) Adjusted Funds Flow”, “Duvernay Energy Adjusted Funds Flow”, “Corporate Consolidated Free Cash Flow”, “Athabasca (Thermal Oil) Free Cash Flow” and “Duvernay Energy Free Cash Flow” financial measures contained in this News Release do not have standardized meanings which are prescribed by IFRS and they are considered to be non-GAAP financial measures or ratios. These measures may not be comparable to similar measures presented by other issuers and should not be considered in isolation with measures that are prepared in accordance with IFRS. Sustaining Capital and Net Cash are supplementary financial measures. The Leismer and Hangingstone operating results are supplementary financial measures that when aggregated, combine to the Athabasca (Thermal Oil) segment results.}

_{Adjusted Funds Flow and Free Cash Flow}

_{Adjusted Funds Flow and Free Cash Flow are non-GAAP financial measures and are not intended to represent cash flow from operating activities, net earnings or other measures of financial performance calculated in accordance with IFRS. The Adjusted Funds Flow and Free Cash Flow measures allow management and others to evaluate the Company’s ability to fund its capital programs and meet its ongoing financial obligations using cash flow internally generated from ongoing operating related activities.}

_{Sustaining Capital}

_{Sustaining Capital is managements’ assumption of the required capital to maintain the Company’s production base.}

_{Net Cash}

_{Net Cash is defined as the face value of term debt, plus accounts payable and accrued liabilities, plus current portion of provisions and other liabilities plus income tax payable less current assets, excluding risk management contracts.}

_{Production volumes details}

_{This News Release also makes reference to Athabasca’s forecasted average daily Thermal Oil production of 32,000 – 34,000 bbl/d for 2026. Athabasca expects that 100% of that production will be comprised of bitumen. Duvernay Energy’s forecasted total average daily production of 4,500 – 5,000 boe/d for 2026 is expected to be comprised of approximately 68% tight oil, 23% shale gas and 10% NGLs.}

_{Liquids is defined as bitumen, tight oil, light crude oil, medium crude oil and natural gas liquids.}

_{Break Even is an operating metric that calculates the US$WTI oil price required to fund operating costs (Operating Break-even), sustaining capital (Sustaining Break-even), or growth capital (Total Capital) within Adjusted Funds Flow.}

_{Enterprise Value to Debt Adjusted Cash Flow is a valuation metric calculated by dividing Enterprise Value (Market Capitalization plus Net Debt) divided by Cash Flow before interest costs.}