Athabasca Oil hits Leismer expansion milestones, advances Corner Phase 1

CALGARY, Alberta, July 29, 2026 (GLOBE NEWSWIRE) -- Athabasca Oil Corporation (TSX: ATH) (“Athabasca” or the “Company”) reported second quarter results highlighted by continued execution of its funded growth strategy. The Company advanced the Leismer expansion and commenced the staged start-up of the next growth well pairs. Corner development activities are progressing as planned, with project sanction expected following confirmation of details under the Government of Alberta’s new fiscal framework to enable oil sands growth.

The Company remains focused on executing fully funded growth while maintaining balance-sheet strength and prioritizing per-share value creation. Q2 2026 Corporate Consolidated Results Production: Current corporate production of ~40,000 boe/d (July). Average quarterly production of 32,110 boe/d (97% Liquids), reflecting ~7,200 boe/d impact of planned turnarounds.

Cash Flow: Adjusted Funds Flow of $123 million ($0.25 per share). Cash flow from operating activities of $134 million. Free Cash Flow of $27 million from Athabasca (Thermal Oil).

Cash flow for the quarter was impacted by turnarounds and lower sales volumes in June related to third-party downtime. Approximately 7,800 bbl/d of June production was sold from inventory in July, with the associated financial contribution to be recognized in July. Strong Netbacks: Quarterly Operating Netback of $49/bbl in Thermal Oil and $70/boe in Duvernay Energy.

Capital Program: Total capital expenditures of $84 million, including $70 million at Leismer to support the expansion project and facility turnaround and $7 million in Duvernay development. Best-in-Class Balance Sheet: $62 million Net Cash position and $826 million of Liquidity. Athabasca closed a new $500 million four-year covenant-based credit facility, while Duvernay Energy increased its reserve-based facility to $75 million, expanding financial flexibility and lowering the Company’s cost of capital.

Leismer Expansion Timeline on Track: The planned facility turnaround was completed in May and included new tie-in points and setting of major equipment for the expansion. The Company has commenced steaming new wells and expects to bring 12 well pairs on production in a staged approach by early 2027. An additional nine well pairs and three redevelopment wells will be drilled during the upcoming winter season.

The asset is expected to exit 2026 at ~31,000 bbl/d and achieve 40,000 bbl/d by the end of 2027. Accelerating Activity: The total cost of the expansion project is estimated at $300 million ($25,000/bbl/d capital efficiency). The 2026 capital budget for Leismer has increased by ~$30 million to ~$270 million to reflect the acceleration of drilling activity into this year.

Drilling will commence in the fourth quarter with completions to follow in 2027. This accelerated activity is within the original expansion scope of work. Capital spending for the entire project is expected to be substantially complete by year-end 2026.

Corner Asset: Advancing a Top-Tier Growth Project 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. Operational Momentum: Athabasca has finalized a lump-sum proposal for a 15,000 bbl/d Phase 1 modular development, providing greater cost and schedule certainty. Site preparation, access road construction and detailed engineering work are proceeding.

The 2026 capital budget has increased to ~$55 million which maintains the development schedule of first steam in early 2029 and ramp-up to full production capacity by year-end 2029. Development Capital: Phase 1 capital is estimated at ~$560 million for the central processing facility, associated well pairs and site infrastructure ($36,500/bbl/d capital efficiency based on 15,300 bbl/d of capacity). The majority of Phase 1 expenditures are expected in 2027 and 2028, following the completion of the Leismer expansion capital spend.

The Company also expects to advance regional infrastructure and long-lead items to preserve the option to accelerate future phases toward the targeted 40,000 bbl/d project capacity. Sanction Timing: The Government of Alberta recently announced plans for a new fiscal framework to enable oil sands growth with program details expected later this year. Athabasca continues to advance Phase 1 through schedule-critical commitments and expects to sanction the project following confirmation of details under the new fiscal framework.

Corporate Consolidated 2026 Outlook and Exit-Rate Momentum Hangingstone Resilience: Production remains resilient at ~9,000 bbl/d. The Company is assessing capital-efficient growth opportunities in 2027 to take advantage of available facility capacity. Duvernay Development : 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 brought on stream in April with average IP30s of 1,501 boe/d per well (90% Liquids) and average IP60s of 1,266 boe/d per well (90% Liquids). The Company recently commenced drilling a three-well 100% working interest pad. Production from the pad is expected in the fourth quarter, contributing to an exit rate of ~6,000 boe/d.

Consolidated Outlook and Exit-Rate Momentum: Production growth will materialize in the second half of 2026 with an exit rate of ~45,000 boe/d, supported by the Leismer expansion project and 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 ~1,800 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.

The corporate consolidated capital budget has increased to ~$420 million, including ~$65 million of accelerated Thermal Oil activity, bringing the Thermal Oil budget to ~$340 million. The Duvernay Energy budget remains at ~$80 million. Long-Term Corporate 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.

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. Growth Funded within Cash Flow: Long-life, low-decline assets provide 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 ~US$45/bbl WTI and growth initiatives at Leismer and Corner are fully funded within cash flow at ~US$55/bbl WTI.

Exceptional Financial Resilience: 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 holds a $62 million Net Cash position and $826 million of Liquidity. The Company’s new $500 million four-year covenant-based credit facility expands financial flexibility at a lower cost of capital.

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 1 . Outstanding Shareholder Returns: The Company has returned ~$1.2 billion to shareholders since 2021, including $386 million of debt reduction and ~$775 million of share buybacks. Athabasca’s capital allocation framework remains anchored by a strong balance sheet, fully funded high-return growth and value-driven return of capital.

In 2026, Athabasca is committed to returning 100% of Free Cash Flow to shareholders through share buybacks and has repurchased ~$70 million of common shares year-to-date. Athabasca forecasts $1.5 billion 1,2 of additional Free Cash Flow over the next five years after 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% compound annual growth rate in cash flow per share 1 to 2030 and beyond.

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.

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 Pricing Assumptions: 2026 strip pricing (July 23) US$83.39 WTI, US$14.37 WCS heavy differential, C$1.91 AECO, 0.72 C$/US$ FX. 2027+ US$70 WTI, US$12.50 WCS heavy differential, C$3 AECO, and 0.725 C$/US$ FX. 2 The 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 Athabasca (Thermal Oil) Q2 2026 Highlights and Operations Update Production: Second quarter production of 27,173 bbl/d (18,274 bbl/d at Leismer and 8,899 bbl/d at Hangingstone), reflecting planned turnaround activity at both assets. Cash Flow: Operating Income of $109.0 million with an Operating Netback of $48.73/bbl.

Adjusted Funds Flow of $103.9 million. Cash flow for the quarter was impacted by turnarounds and lower sales volumes in June related to third-party downtime. Approximately 7,800 bbl/d of June production was sold from inventory in July, with the associated financial contribution to be recognized in July.

Capital: $77.4 million of capital expenditures in Q2, with $70.2 million at Leismer. Leismer During the quarter, the Company completed a three-week facility turnaround on budget and on schedule. The turnaround included recurring maintenance on a four-year frequency and scope for the tie-in of new equipment for the expansion project.

The Company also completed six well pairs on Pad L10 and recently commenced steaming operations on the next growth well pairs. A total of 12 well pairs will be placed on production over the next six months supporting a 2026 exit rate of ~31,000 bbl/d. The wells feature extended-reach laterals of approximately 1,300–1,600 meters and modern completion technologies, including flow-control devices and steam splitters designed to improve temperature conformance along the laterals.

The Company will commence drilling nine additional well pairs this upcoming winter including five well pairs on Pad 10 and four well pairs on Pad 11. Three redevelopment wells will also be drilled. These wells are part of the original expansion project scope and will drive progressive growth to ~40,000 bbl/d by late 2027.

At the central processing facility, construction continues to advance with completion and start-up of the first stage of debottlenecking equipment, completion of all required mechanical and electrical tie-ins during turnaround, continued equipment delivery and progression of tank construction in the field. Work on the steam-generation and associated blowdown systems has advanced significantly with targeted completion in October. Steam capacity is expected to increase to 110,000 bbl/d in the fourth quarter of 2026, with a further increase to 130,000 bbl/d expected in the first quarter of 2027.

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 ~9,000 bbl/d. Current well pair performance remains strong between 850 – 1,150 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 and regulatory approval for 12,000 bbl/d. The Company completed a planned turnaround 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 a high-quality reservoir characterized by pay packages averaging ~20 meters thick and oil saturations of ~84%. The Company expects initial steam-to-oil ratios of ~2.5x. Given the high-quality reservoir, the initial project phase will be developed from 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. Phase 1 capital is estimated at ~$560 million, including site preparations, facilities, drilling and completions and regional infrastructure. This represents a capital efficiency of ~$36,500/bbl/d (15,300 bbl/d capacity).

The Corner asset will be developed through a capital-efficient modular design with 15,000 bbl/d project phases. The project approach includes a proven templated and modular central processing plant, connected to well pads with above ground pipelines, enabling a low-risk development approach while reducing site construction costs. The initial phase of development will require only a partial pad of wells to achieve full capacity.

The Company has finalized a lump-sum proposal for a 15,000 bbl/d Phase 1 central processing facility, providing greater cost and schedule certainty. Site preparation, access road construction and detailed engineering work are proceeding. The 2026 capital budget has increased to ~$55 million which maintains the development schedule of first steam in early 2029 and a ramp-up to full production capacity by year-end 2029.

The Government of Alberta recently announced plans for a new fiscal framework to enable oil sands growth with program details expected later this year. Athabasca continues to advance Phase 1 through schedule-critical commitments and expects to sanction the project following confirmation of details under the new framework. Duvernay Energy Corporation Q2 2026 Highlights and Operations Update Production: Production of 4,937 boe/d (82% Liquids).

Cash Flow: Operating Income of $31.4 million with an Operating Netback of $69.94/boe. Adjusted Funds Flow of $19.2 million. Capital: $6.7 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.

A four-well pad at 7-15-64-17W5 (30% working interest) with average laterals of ~4,500 meters was brought on stream in April with average IP30s of 1,501 boe/d per well (90% Liquids) and IP60s of 1,266 boe/d (90% Liquids). The Company is pleased by the strong production results and free condensate yields resulting in exceptional netbacks. In July, the Company commenced drilling a three-well pad at 5-17-64-16W5 (100% working interest).

Production from the pad is expected to commence in the fourth quarter, contributing to an 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; execution, timing and anticipated benefits of the Company’s Leismer expansion and Corner development; the expected timing and availability of the Government of Alberta’s fiscal framework for oil sands growth, and the anticipated impact of such framework on the Company’s development and sanction decisions; 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 News 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.

Reserves 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.

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: 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).

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 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.

Globe Newswire July 29, 2026 - 5:12 PM PDT News by QuoteMedia www.quotemedia.com