CALGARY, Alberta, May 06, 2026 (GLOBE NEWSWIRE) -- Athabasca Oil Corporation (TSX: ATH) (“Athabasca” or the “Company”) first quarter results demonstrate continued execution across its funded growth portfolio, with its Leismer expansion on track, strong Duvernay performance, and a balance sheet positioned to support disciplined capital allocation. In the current constructive oil price environment, the Company is well positioned to capture higher cash flow through its liquids-weighted asset base while continuing to prioritize per-share value creation.

Q1 2026 Consolidated Corporate Results

• Production: Average production of 40,242 boe/d (98% Liquids), representing 7% (14% per share) growth year-over-year.
• Cash Flow: Adjusted Funds Flow of $128 million ($0.27 per share). Cash flow from operating activities of $102 million. Free Cash Flow of $20 million from Athabasca (Thermal Oil) demonstrates the strength of its quality asset base.
• Strong Netbacks: Quarterly Operating Netback of $46/bbl per barrel in Thermal Oil and $47/boe in Duvernay Energy. Significant margin growth was realized in March, supported by higher oil prices, with Operating Netbacks increasing to greater than $65/boe in all operating areas.
• Capital Program: Total capital expenditures of $114 million, including $81 million at Leismer to support the expansion project and $22 million in Duvernay development.
• Best-in Class Balance Sheet: $60 million Net Cash position and $406 million of Liquidity (including $291 million of cash). Athabasca continues to prudently manage its capital structure as operations increase in scale and the Company is committed to maintaining a best-in-class balance sheet.
  

2026 Outlook Increased on Stronger Cash Flow and Exit-Rate Momentum

• Leismer Expansion On Track: The winter drilling program concluded in March with 12 new well pairs with 1,300 – 1,600 meter lateral lengths. These wells pairs will begin steaming in the second half of the year on a phased basis following the facility turnaround in May, driving strong production growth in the back half of 2027. The $300 million expansion project is expected to reach 40,000 bbl/d in late 2027 with a capital efficiency of $25,000/bbl/d. Capital for this project will be ~90% complete by the end of 2026.
• Hangingstone Resilience: Current production remains resilient at ~8,900 bbl/d. The Company is assessing capital efficient growth opportunities in 2027 to take advantage of available facility capacity.
• Accelerating Duvernay Momentum: Recent Duvernay wells continue to demonstrate strong production results and free condensate yields. A four well pad at 7-15-64-17 W5 (30% WI) was completed in March and brought on stream in April with average IP21s of 1,635 boe/d per well (91% Liquids). The Company is accelerating the timing of a three-well 100% working interest pad into Q3 2026. Production from the pad is expected to commence in the fourth quarter, contributing to an expected exit rate of ~6,000 boe/d. The capital budget for Duvernay Energy has increased to $79 million, including the three-well pad and operational readiness for a continued growth program in 2027. Continued strong results and a robust commodity price environment are enabling the strategy of self-funded growth.
• Exit Rate Momentum: Production growth will materialize in the second half of 2026 with an increased exit rate of ~45,000 boe/d, supported by the Leismer expansion project and additional Duvernay activity. Annual production is expected to be at the high end of guidance of 37,000 – 39,000 boe/d (98% Liquids), inclusive of a ~2,500 boe/d impact of planned turnarounds across its assets. Strong operational momentum is expected to continue into 2027 as Leismer ramps up to 40,000 bbl/d and growth in Duvernay continues.
• Increased Cash Flow Outlook: The Company has increased its consolidated 2026 Adjusted Funds Flow forecast to $550 – $575 million¹ reflecting higher oil prices. 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 2027 Adjusted Funds Flow by ~$19 million and ~$24 million, respectively.
  

Corner Readiness

• Corner Project: The asset is an exceptional project with a high-quality reservoir in the McMurray sands containing an estimated 353 mmbbl 2P reserves and 520 mmbbl contingent resource (best estimate). The project area is highly delineated with over 300 vertical well penetrations, 3D seismic coverage and regulatory approval in place for a 40,000 bbl/d development. Corner is adjacent to the Company’s Leismer asset with many operational synergies between the assets. Once developed, the asset is expected to rank among the best steam assisted gravity drainage (“SAGD”) assets in Alberta.
• Facility Development: Corner will be developed through a capital-efficient modular design with 15,000 bbl/d project phases. The Company has completed Class 3 cost estimates and is now evaluating lump sum bid proposals to enhance certainty over project cost and schedule.
• Operational Advancement: Recent field activity included road and pad-site clearing during the winter construction season. The Company has secured long-term gas supply and power contracts and is evaluating multiple options for diluent supply and dilbit egress.
• Sanction Ready: The Company anticipates the first 15,000 bbl/d phase to be sanctioned in the second half of 2026. Once sanctioned, the project is expected to reach first steam in 30 months, first oil in 34 months and a 15,000 bbl/d production rate by the end of 2029, with additional phases in subsequent years.
• Self-Funded: The initial phase of the project is expected to cost ~$35,000/bbl/d with the majority of the capital allocated in 2027/28, following the current Leismer expansion project. The Corner project is expected to be self-funded while maintaining a strong balance sheet and a continued focus on shareholder returns.
  

Corporate Consolidated Strategy

• Thermal Oil Growth: The Company’s Thermal Oil division provides an oil focused platform underpinning funded growth to >60,000 bbl/d by 2030 including 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 within current regulatory approvals.
• Low Break-evens: Long-life, low decline assets afford Athabasca with a sustaining capital and growth advantage. The Company’s Thermal Oil assets have an operating break-even of ~US$40/bbl WTI, a sustaining break-even of ~$US45/bbl WTI and growth initiatives at Leismer and Corner are fully funded within cash flow at ~US$55/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 growth to >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 with Net Cash position: Athabasca is committed to maintaining a best-in-class balance sheet and the Company will prudently manage its capital structure as operations increase in scale. Athabasca (Thermal Oil) also has $2.1 billion in tax pools, including $1.5 billion of immediately deductible non-capital losses, sheltering cash taxes to 2030.
• Exceptional Shareholder Returns: The Company has returned ~$1.1 billion to shareholders since 2021, including $386 million of debt reduction and ~$750 million of share buybacks. Athabasca’s capital allocation framework remains anchored by a strong balance sheet, fully funded high-return growth and value-driven share buybacks, with incremental activity evaluated against share buybacks on a risk-adjusted per-share return basis. In 2026, Athabasca is committed to returning 100% of Free Cash Flow to shareholders through share buybacks and has purchased $40 million in stock year-to-date. Athabasca forecasts $1.5 billion^1,2 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 share buybacks results in a >20% compounded annual growth rate in cash flow per share¹ to 2030 and beyond.

Annual Shareholders Meeting

Athabasca will be hosting its Annual General Meeting of Shareholders (“Meeting”) on Thursday, May 7, 2026 at 9:00 am (MT). The Meeting will be hosted virtually and shareholders and guests can listen via live webcast with details available at:

       https://www.atha.com/investors/presentation-events.html

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.
¹ 2026 strip pricing (April 27): US$80.96 WTI, US$14.48 WCS diff, C$1.65 AECO, 0.73C$/US$ FX.Pricing Assumptions: 2027+ US$70 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 8x Enterprise Value/Debt Adjusted Cash Flow in 2027 and beyond.

Financial and Operational Highlights

(1) Corporate Consolidated and Duvernay Energy reflect gross production and financial metrics before taking into consideration Athabasca's 70% equity interest in Duvernay Energy.
(2) Refer to the “Reader Advisory” section within this News Release for additional information on Non-GAAP Financial Measures and production disclosure.
(3) Includes realized commodity risk management gain of $0.8 million for the three months ended March 31, 2026 (three months ended March 31, 2025 – loss of $1.6 million).
(4) Net income and comprehensive income per share amounts are based on net income and comprehensive income attributable to shareholders of the Parent Company. 
(5) Includes available credit under Athabasca's and Duvernay Energy's Credit Facilities and Athabasca's Unsecured Letter of Credit Facility.

Athabasca (Thermal Oil) Q1 2026 Highlights and Operations Update

• Production: First quarter production of 35,629 bbl/d (26,683 bbl/d at Leismer and 8,946 bbl/d at Hangingstone).
• Cash Flow: Operating Income of $152.7 million with an Operating Netback of $46/bbl. Adjusted Funds Flow of $112.2 million. March Operating Netback of $67/bbl.
• Capital: $92 million of capital expenditures in Q1, with $81 million at Leismer.
• Free Cash Flow: $20 million of Free Cash Flow supporting corporate return of capital commitment.

Leismer

In Q1 2026, the Company drilled six well pairs on Pad 10. The wells were completed in April, and steaming will commence in a staged sequence following the planned turnaround in May, along with the six well pairs on Pad L11 that were drilled in 2025. An exit rate of ~31,000 bbl/d is anticipated for 2026, with all wells expected to be converted to production by early 2027. These wells in conjunction with additional drilling next winter will drive strong production momentum, supporting progressive growth to 40,000 bbl/d by late 2027. The wells were drilled as extended-reach laterals (1,300 – 1,600 meter laterals) and modern completion technologies that incorporated flow control devices and steam splitters to support temperature conformance along the laterals.

At the central processing facility, construction has advanced significantly, with work now underway on four major storage tanks. Additional key equipment and pipe rack modules have been delivered to site, and mechanical connections are progressing with a focus on increasing the capacity of inlet emulsion processing, heat integration and steam generation systems. Steam capacity is expected to increase to 110,000 bbl/d in H2 2026. The Company has commenced a three-week facility turnaround which will include recurring maintenance on a four-year frequency and scope for the tie-in of new equipment for the expansion project. The $300 million expansion project includes an estimated $190 million for facility capital and an estimated $110 million for growth wells, with a capital efficiency of ~$25,000/bbl/d. Capital exposure for the expansion project is expected to be substantially complete by year-end 2026. The project remains on budget and on schedule with the original sanction plans announced in July 2024.

Hangingstone

In March 2025, two extended reach sustaining well pairs (~1,400 meter average laterals) were placed on production supporting current production of ~8,900 bbl/d (April). Current well pair performance remains strong between 800 – 1,100 bbl/d per well. Hangingstone continues to deliver meaningful cash flow contributions. The Company is assessing capital efficient growth opportunities in 2027 to take advantage of available facility capacity. The Company has a planned two-week turnaround that will be completed in June.

Corner

Corner is expected to be the first greenfield project in the high-quality McMurray fairway to be sanctioned since 2013. The asset is a top-tier SAGD project, underpinned by high-quality reservoir characterized by pay packages averaging ~20 meters thick and oil saturations of ~84%. The Company is expecting initial steam-to-oil ratios of ~2.5x. Given the high-quality reservoir, the initial project phase will be developed off a single pad, utilizing extended-reach laterals and modern completion technologies. The asset will leverage substantial strategic infrastructure shared with Leismer, including the regional aerodrome, roads, camp facilities and experienced personnel.

The Corner asset will be developed through a capital-efficient modular design with 15,000 bbl/d project phases. The project approach will include a proven templated and highly modular central processing plant, connected to well pads with above ground pipelines. This approach allows low risk development and reduction of site construction costs. The initial phase of development will require only a single pad of wells to achieve full capacity. Future development is expected to be self-funded while maintaining a strong balance sheet and a focus on shareholder returns. Phase 1 is expected to have a capital efficiency of ~$35,000/bbl/d.

Activity in the first quarter of 2026 included central processing facility, road and pad-site preparation during the winter construction season. The Company is finalizing cost estimates and advancing execution planning, including the use of lump-sum contracting strategies where appropriate to improve cost and schedule certainty. Planning for local pipeline connections and utility services have progressed and the Company has secured critical path contracts including gas feedstock and diversified long-term egress options. The Company anticipates Phase 1 to be sanctioned in the second half of 2026 with the majority of the capital to follow the current Leismer expansion project.

Duvernay Energy Corporation Q1 2026 Highlights and Operations Update

• Production: Production of 4,613 boe/d (81% Liquids).
• Cash Flow: Operating Income of $19.6 million with an Operating Netback of $47/boe. Adjusted Funds Flow of $15.8 million. March Operating Netback of $65/boe.
• Capital: $21.8 million of capital expenditures including drilling and completions on a four-well pad (30% working interest), the drilling of a land retention well (100% working interest), and construction of regional infrastructure.
• Increased 2026 Capital Program. Increased to $79 million to include an additional three-well 100% working interest pad and additional operational readiness for activity in 2027.

A four-well 30% pad at 7-15-64-17W5 (30% working interest) with average laterals of ~4,500 meters was completed in March and brought on stream in April with average IP21s of 1,635 boe/d per well (91% Liquids). The Company is pleased by the strong production results and free condensate yields resulting in exceptional netbacks. In the first quarter of 2026, the Company also drilled a 3,860 meter 100% working interest land retention well, securing land tenure of ~32 sections in its northern Duvernay land position.

Supported by stronger commodity prices and continued confidence in asset performance, the Company is accelerating the timing of a three-well pad at 5-17-64-16W5 (100% working interest) into Q3 2026. Production from the pad is expected to commence in the fourth quarter, contributing to an expected exit rate of ~6,000 boe/d.

DEC has an independent strategy and capital allocation framework with self-funded production growth to >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.

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; 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, netbacks, market access, exemption from U.S. tariffs, 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 prices; 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, 2025 (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 4, 2026 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; 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; evolving corporate governance, sustainability and reporting framework; limitations of 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 – 2030 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, 2025. 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, 2025 and based on average pricing of McDaniel, Sproule and GLJ as of January 1, 2026.

The 432 gross Duvernay drilling locations referenced include: 95 proved undeveloped locations and 88 probable undeveloped locations for a total of 183 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, 2025 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", “Corporate Consolidated Adjusted Funds Flow per Share”, "Athabasca (Thermal Oil) Adjusted Funds Flow", "Duvernay Energy Adjusted Funds Flow", “Corporate Consolidated Free Cash Flow”, "Athabasca (Thermal Oil) Free Cash Flow", "Duvernay Energy Free Cash Flow", “Corporate Consolidated Operating Income", "Corporate Consolidated Operating Income Net of Realized Hedging", "Athabasca (Thermal Oil) Operating Income", "Duvernay Energy Operating Income", "Corporate Consolidated Operating Netback", "Corporate Consolidated Operating Netback Net of Realized Hedging", "Athabasca (Thermal Oil) Operating Netback", "Duvernay Energy Operating Netback" and “Cash Transportation and Marketing Expense” 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. Net Cash and Liquidity 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.

(1) Duvernay Energy and Corporate Consolidated reflect gross financial metrics before taking into consideration Athabasca's 70% equity interest in Duvernay Energy.

(1) Duvernay Energy and Corporate Consolidated reflect gross financial metrics before taking into consideration Athabasca's 70% equity interest in Duvernay Energy.

Duvernay Energy Operating Income and Operating Netback

The non-GAAP measure Duvernay Energy Operating Income in this News Release is calculated by subtracting the Duvernay Energy royalties, operating expenses and transportation & marketing expenses from petroleum and natural gas sales which is the most directly comparable GAAP measure. The Duvernay Energy Operating Netback per boe is a non-GAAP financial ratio calculated by dividing the Duvernay Energy Operating Income by the Duvernay Energy production. The Duvernay Energy Operating Income and the Duvernay Energy Operating Netback measures allow management and others to evaluate the production results from the Company’s Duvernay Energy assets.

The Duvernay Energy Operating Income is calculated using the Duvernay Energy Segments GAAP results, as follows:

Athabasca (Thermal Oil) Operating Income and Operating Netback

The non-GAAP measure Athabasca (Thermal Oil) Operating Income in this News Release is calculated by subtracting the Athabasca (Thermal Oil) segments cost of diluent blending, royalties, operating expenses and cash transportation & marketing expenses from heavy oil (blended bitumen) and midstream sales which is the most directly comparable GAAP measure. The Athabasca (Thermal Oil) Operating Netback per bbl is a non-GAAP financial ratio calculated by dividing the respective projects Operating Income by its respective bitumen sales volumes. The Athabasca (Thermal Oil) Operating Income and the Athabasca (Thermal Oil) Operating Netback measures allow management and others to evaluate the production results from the Athabasca (Thermal Oil) assets. The Athabasca (Thermal Oil) Operating Income is calculated using the Athabasca (Thermal Oil) Segments GAAP results, as follows:

(1) Transportation and marketing excludes non-cash costs of $0.6 million for the three months ended March 31, 2026 (three months ended March 31, 2025 - $0.6 million).

Corporate Consolidated Operating Income and Corporate Consolidated Operating Income Net of Realized Hedging and Operating Netbacks

The non-GAAP measures of Corporate Consolidated Operating Income including or excluding realized hedging in this News Release are calculated by adding or subtracting realized gains (losses) on commodity risk management contracts (as applicable), royalties, the cost of diluent blending, operating expenses and cash transportation & marketing expenses from petroleum, natural gas and midstream sales which is the most directly comparable GAAP measure. The Corporate Consolidated Operating Netbacks including or excluding realized hedging per boe are non-GAAP ratios calculated by dividing Corporate Consolidated Operating Income including or excluding hedging by the total sales volumes and are presented on a per boe basis. The Corporate Consolidated Operating Income and Corporate Consolidated Operating Netbacks including or excluding realized hedging measures allow management and others to evaluate the production results from the Company’s Duvernay Energy and Athabasca (Thermal Oil) assets combined together including the impact of realized commodity risk management gains or losses (as applicable).

(1) Non-GAAP measure includes intercompany NGLs (i.e. condensate) sold by the Duvernay Energy segment to the Athabasca (Thermal Oil) segment for use as diluent that is eliminated on consolidation.
(2) Transportation and marketing excludes non-cash costs of $0.6 million for the three months ended March 31, 2026 (three months ended March 31, 2025 - $0.6 million).

Cash Transportation and Marketing Expense

The Cash Transportation and Marketing Expense financial measures contained in this News Release are calculated by subtracting the non-cash transportation and marketing expense as reported in the Consolidated Statement of Cash Flows from the transportation and marketing expense as reported in the Consolidated Statement of Income (Loss) and are considered to be non-GAAP financial measures.

Net Cash

Net Cash is defined as the face value of long-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.

Liquidity

Liquidity is defined as cash and cash equivalents plus available credit capacity.

Production volumes details

(1) Comprised of 99% or greater of tight oil, with the remaining being light and medium crude oil.
(2) Comprised of 99% or greater of shale gas, with the remaining being conventional natural gas.

This News Release also makes reference to Athabasca's forecasted total 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 approximately 5,000 boe/d for 2026 is expected to be comprised of approximately 69% tight oil, 22% shale gas and 9% 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.