Athabasca Oil Reports 2026 Third Quarter Results
| Three months ended September 30, | Nine months ended September 30, | |||||||||||||||
| ($ Thousands, unless otherwise noted) | 2026 | 2025 | 2026 | 2025 | ||||||||||||
| CORPORATE CONSOLIDATED(1) | ||||||||||||||||
| Petroleum and natural gas production (boe/d)(2) | 38,602 | 39,599 | 36,978 | 38,807 | ||||||||||||
| Petroleum, natural gas and midstream sales | $ | 461,045 | $ | 333,397 | $ | 1,199,934 | $ | 1,061,311 | ||||||||
| Operating Income(2) | $ | 217,281 | $ | 151,835 | $ | 529,893 | $ | 439,132 | ||||||||
| Operating Income Net of Realized Hedging(2)(3) | $ | 172,627 | $ | 144,650 | $ | 472,496 | $ | 430,698 | ||||||||
| Operating Netback ($/boe)(2) | $ | 58.65 | $ | 42.50 | $ | 52.27 | $ | 41.71 | ||||||||
| Operating Netback Net of Realized Hedging ($/boe)(2)(3) | $ | 46.60 | $ | 40.49 | $ | 46.61 | $ | 40.91 | ||||||||
| Capital expenditures | $ | 111,683 | $ | 96,190 | $ | 309,751 | $ | 232,589 | ||||||||
| Cash flow from operating activities | $ | 114,571 | $ | 157,414 | $ | 350,542 | $ | 382,199 | ||||||||
| per share - basic | $ | 0.24 | $ | 0.32 | $ | 0.73 | $ | 0.76 | ||||||||
| Adjusted Funds Flow(2) | $ | 160,988 | $ | 129,197 | $ | 412,038 | $ | 386,463 | ||||||||
| per share - basic | $ | 0.33 | $ | 0.26 | $ | 0.85 | $ | 0.77 | ||||||||
| ATHABASCA (THERMAL OIL) | ||||||||||||||||
| Bitumen production (bbl/d)(2) | 34,319 | 36,590 | 32,368 | 35,942 | ||||||||||||
| Petroleum, natural gas and midstream sales | $ | 455,514 | $ | 329,542 | $ | 1,179,120 | $ | 1,047,077 | ||||||||
| Operating Income(2) | $ | 195,583 | $ | 142,631 | $ | 457,216 | $ | 413,750 | ||||||||
| Operating Netback ($/bbl)(2) | $ | 59.08 | $ | 43.28 | $ | 51.49 | $ | 42.46 | ||||||||
| Capital expenditures | $ | 73,685 | $ | 64,965 | $ | 243,170 | $ | 171,451 | ||||||||
| Adjusted Funds Flow(2) | $ | 145,084 | $ | 121,131 | $ | 361,195 | $ | 364,581 | ||||||||
| Free Cash Flow(2) | $ | 71,399 | $ | 56,166 | $ | 118,025 | $ | 193,130 | ||||||||
| DUVERNAY ENERGY(1) | ||||||||||||||||
| Petroleum and natural gas production (boe/d)(2) | 4,283 | 3,009 | 4,610 | 2,865 | ||||||||||||
| Percentage Liquids (%)(2) | 77 | % | 75 | % | 80 | % | 73 | % | ||||||||
| Petroleum, natural gas and midstream sales | $ | 31,848 | $ | 15,840 | $ | 103,032 | $ | 46,985 | ||||||||
| Operating Income(2) | $ | 21,698 | $ | 9,204 | $ | 72,677 | $ | 25,382 | ||||||||
| Operating Netback ($/boe)(2) | $ | 55.07 | $ | 33.25 | $ | 57.76 | $ | 32.45 | ||||||||
| Capital expenditures | $ | 37,998 | $ | 31,225 | $ | 66,581 | $ | 61,138 | ||||||||
| Adjusted Funds Flow(2) | $ | 15,904 | $ | 8,066 | $ | 50,843 | $ | 21,882 | ||||||||
| Free Cash Flow(2) | $ | (22,094 | ) | $ | (23,159 | ) | $ | (15,738 | ) | $ | (39,256 | ) | ||||
| NET INCOME AND COMPREHENSIVE INCOME | ||||||||||||||||
| Net income and comprehensive income(4) | $ | 77,809 | $ | 69,640 | $ | 190,266 | $ | 198,514 | ||||||||
| per share - basic(4) | $ | 0.16 | $ | 0.14 | $ | 0.39 | $ | 0.39 | ||||||||
| per share - diluted(4) | $ | 0.16 | $ | 0.14 | $ | 0.39 | $ | 0.39 | ||||||||
| COMMON SHARES OUTSTANDING | ||||||||||||||||
| Weighted average shares outstanding - basic | 481,270,751 | 494,509,594 | 482,261,343 | 503,714,495 | ||||||||||||
| Weighted average shares outstanding - diluted | 484,874,847 | 497,929,426 | 486,109,732 | 507,263,981 |
| September 30, | December 31, | |||||
| As at ($ Thousands) | 2026 | 2025 | ||||
| LIQUIDITY AND BALANCE SHEET (CONSOLIDATED) | ||||||
| Cash and cash equivalents | $ | 305,007 | $ | 316,366 | ||
| Available credit facilities(5) | $ | 532,862 | $ | 126,595 | ||
| Face value of long-term debt | $ | 216,128 | $ | 201,209 |
| (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 loss of $44.7 million and $57.4 million for the three and nine months ended September 30, 2026 (three and nine months ended September 30, 2025 – loss of $7.2 million and $8.4 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) Q3 2026 Highlights and Operations Update
- Production: Third quarter production of 34,319 bbl/d (25,020 bbl/d at Leismer and 9,299 bbl/d at Hangingstone). Cash Flow: Operating Income of $195.6 million with an Operating Netback of $59.08/bbl. Adjusted Funds Flow of $145.1 million. Capital: $73.7 million of capital expenditures in Q3, with $54.1 million at Leismer.
Leismer
The Company's expansion project continues to advance. Two new steam generators were commissioned in October, and will provide steam generation capacity for the full ramp-up to 40,000 bbl/d. Seven well pairs are currently being steamed. An additional five well pairs will commence steaming in Q4.
The winter drilling program commenced in September and will include nine well pairs and three redevelopment well pairs. A total new well count of 24 well pairs along with commissioning of additional facility equipment through H1 2027 will support growth to 40,000 bbl/d by year-end 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. The project remains on budget and on schedule with the original sanction plans announced in July 2024.
Hangingstone
Hangingstone production continues to be stable at ~9,300 bbl/d, delivering meaningful cash flow contributions to the Company.
Corner
The Company continues to progress the 15,000 bbl/d Phase 1 project including site preparation, access road construction and detailed engineering work. Sanction timing remains subject to assessment of the Government of Alberta's new fiscal framework and the pending transaction with Cenovus.
Duvernay Energy Corporation Q3 2026 Highlights and Operations Update
- Production: Production of 4,283 boe/d (77% Liquids). Cash Flow: Operating Income of $21.7 million with an Operating Netback of $55.07/boe. Adjusted Funds Flow of $15.9 million. Capital: $38.0 million of capital expenditures including drilling and completions on a three-well pad (100% working interest), and construction of regional infrastructure.
During the quarter the Company drilled and completed a three-well pad at 5-17-64-16W5 (100% working interest). Production from the pad is expected to commence in early November. The Company is advancing readiness for an additional operated multi-well pad for this winter.
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 .
| For more information, please contact: | |
| Matthew Taylor | Robert Broen |
| Chief Financial Officer | President and CEO |
| 1-403-817-9104 | 1-403-817-9190 |
| ... | ... |
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: the Purchase Price per Athabasca share to be received pursuant to the Transaction; the anticipated benefits of the Transaction to Athabasca shareholders, including but not limited to near-term liquidity and value certainty and participation in future upside of Cenovus; the form of consideration and elections under the Transaction; the implied value of the Transaction and Athabasca management's 2026 exit production and Debt Adjusted Funds Flow forecast; the anticipated timing for closing of the Transaction; the expectation that Cenovus is better positioned to manage ongoing fiscal, regulatory and market-access risk; the expectation that the Transaction provides significant and immediate recognition of the value embedded in Athabasca's standalone growth plans; the anticipated accelerated development of Athabasca's assets under Cenovus's ownership, including the advancement of Corner Phases 2 and 3 and further Leismer expansions relative to the timelines contemplated in Athabasca's standalone plans; the anticipated ramp-up of production at Leismer, including the timing of steaming of well pairs, the winter drilling program and the expectation that the Leismer expansion will remain on budget and on schedule; the development of the Corner Phase 1 project; Duvernay Energy's development plans, including the timing of production from new well pads and the construction of regional infrastructure; the expectations that consolidating Cenovus and Athabasca assets in the McMurray fairway will generate significant operational and development synergies to enhance asset value; the expectations that the consolidated ownership of Duvernay Energy under Cenovus as a result of the Transaction will simplify development planning, accelerate development, drive growth, capture value and complement Cenovus's conventional business; the anticipated timing for holding of the shareholder meeting; the expected timing of the mailing of the management information circular; and other similar statements.
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: the timely completion of the Transaction and the satisfaction of the conditions to which the Transaction is subject to; the approval of the Transaction at the shareholder meeting; Athabasca's standalone plan; regulatory and government approvals for the Transaction, including approval of the Court of King's Bench of Alberta and receipt of applicable regulatory and stock exchange approvals, in each case on the anticipated timelines; the realization of anticipated benefits of the Transaction including significant operational and development synergies; 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 production levels; the Company's ability to obtain financing and/or enter into joint venture arrangements, on acceptable terms as permitted under the Agreement; 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 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, 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 Athabasca's 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. 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. Further information regarding the assumptions and risks inherent in the making of forward- looking statements and in respect of the Transaction will be found in the management information circular, along with Athabasca's other public disclosure documents, including the Company's AIF dated March 4, 2026, which are available on SEDAR+ at.
Also included in this News Release are estimates of Athabasca's 2026 exit production and Debt Adjusted Fund Flow, 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.
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 that is available on SEDAR+ at.
Reserves Values 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 ERCE and GLJ as of January 1, 2026, and the Duvernay Energy Corporation minority interest.
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",”Debt Adjusted Funds 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" and "Duvernay Energy Operating Netback" 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.
| Three months ended September 30, 2026 | |||||||||
| ($ Thousands) | Athabasca (Thermal Oil) | Duvernay Energy (1) | Corporate Consolidated (1) | ||||||
| Cash flow from operating activities | $ | 97,575 | $ | 16,996 | $ | 114,571 | |||
| Changes in non-cash working capital | 47,471 | (1,078 | ) | 46,393 | |||||
| Settlement of provisions | 38 | (14 | ) | 24 | |||||
| ADJUSTED FUNDS FLOW | 145,084 | 15,904 | 160,988 | ||||||
| Capital expenditures | (73,685 | ) | (37,998 | ) | (111,683 | ) | |||
| FREE CASH FLOW | $ | 71,399 | $ | (22,094 | ) | $ | 49,305 |
| (1) | Duvernay Energy and Corporate Consolidated reflect gross financial metrics before taking into consideration Athabasca's 70% equity interest in Duvernay Energy. |
| Nine months ended September 30, 2026 | |||||||||
| ($ Thousands) | Athabasca (Thermal Oil) | Duvernay Energy (1) | Corporate Consolidated (1) | ||||||
| Cash flow from operating activities | $ | 298,290 | $ | 52,252 | $ | 350,542 | |||
| Changes in non-cash working capital | 60,661 | (1,464 | ) | 59,197 | |||||
| Settlement of provisions | 2,244 | 55 | 2,299 | ||||||
| ADJUSTED FUNDS FLOW | 361,195 | 50,843 | 412,038 | ||||||
| Capital expenditures | (243,170 | ) | (66,581 | ) | (309,751 | ) | |||
| FREE CASH FLOW | $ | 118,025 | $ | (15,738 | ) | $ | 102,287 |
| (1) | Duvernay Energy and Corporate Consolidated reflect gross financial metrics before taking into consideration Athabasca's 70% equity interest in Duvernay Energy. |
| Three months ended September 30, 2025 | |||||||||
| ($ Thousands) | Athabasca (Thermal Oil) | Duvernay Energy (1) | Corporate Consolidated (1) | ||||||
| Cash flow from operating activities | $ | 151,690 | $ | 5,724 | $ | 157,414 | |||
| Changes in non-cash working capital | (30,673 | ) | 2,337 | (28,336 | ) | ||||
| Settlement of provisions | 114 | 5 | 119 | ||||||
| ADJUSTED FUNDS FLOW | 121,131 | 8,066 | 129,197 | ||||||
| Capital expenditures | (64,965 | ) | (31,225 | ) | (96,190 | ) | |||
| FREE CASH FLOW | $ | 56,166 | $ | (23,159 | ) | $ | 33,007 |
| (1) | Duvernay Energy and Corporate Consolidated reflect gross financial metrics before taking into consideration Athabasca's 70% equity interest in Duvernay Energy. |
| Nine months ended September 30, 2025 | |||||||||
| ($ Thousands) | Athabasca (Thermal Oil) | Duvernay Energy (1) | Corporate Consolidated (1) | ||||||
| Cash flow from operating activities | $ | 366,259 | $ | 15,940 | $ | 382,199 | |||
| Changes in non-cash working capital | (2,521 | ) | 5,932 | 3,411 | |||||
| Settlement of provisions | 843 | 10 | 853 | ||||||
| ADJUSTED FUNDS FLOW | 364,581 | 21,882 | 386,463 | ||||||
| Capital expenditures | (171,451 | ) | (61,138 | ) | (232,589 | ) | |||
| FREE CASH FLOW | $ | 193,130 | $ | (39,256 | ) | $ | 153,874 |
| (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:
| Three months ended September 30, | Nine months ended September 30, | |||||||||||
| ($ Thousands, unless otherwise noted) | 2026 | 2025 | 2026 | 2025 | ||||||||
| Petroleum and natural gas sales | $ | 31,848 | $ | 15,840 | $ | 103,032 | $ | 46,985 | ||||
| Royalties | (4,022 | ) | (1,271 | ) | (11,382 | ) | (5,824 | ) | ||||
| Operating expenses | (5,032 | ) | (4,280 | ) | (15,708 | ) | (12,936 | ) | ||||
| Transportation and marketing | (1,096 | ) | (1,085 | ) | (3,265 | ) | (2,843 | ) | ||||
| DUVERNAY ENERGY OPERATING INCOME | $ | 21,698 | $ | 9,204 | $ | 72,677 | $ | 25,382 |
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:
| Three months ended September 30, | Nine months ended September 30, | |||||||||||
| ($ Thousands, unless otherwise noted) | 2026 | 2025 | 2026 | 2025 | ||||||||
| Heavy oil (blended bitumen) and midstream sales | $ | 455,514 | $ | 329,542 | $ | 1,179,120 | $ | 1,047,077 | ||||
| Cost of diluent | (158,528 | ) | (122,011 | ) | (452,514 | ) | (421,208 | ) | ||||
| Total bitumen and midstream sales | 296,986 | 207,531 | 726,606 | 625,869 | ||||||||
| Royalties | (37,825 | ) | (10,592 | ) | (88,129 | ) | (35,987 | ) | ||||
| Operating expenses - non-energy | (26,901 | ) | (23,884 | ) | (75,545 | ) | (75,581 | ) | ||||
| Operating expenses - energy | (13,052 | ) | (9,153 | ) | (38,734 | ) | (36,281 | ) | ||||
| Transportation and marketing(1) | (23,625 | ) | (21,271 | ) | (66,982 | ) | (64,270 | ) | ||||
| ATHABASCA (THERMAL OIL) OPERATING INCOME | $ | 195,583 | $ | 142,631 | $ | 457,216 | $ | 413,750 |
| (1) | Transportation and marketing excludes non-cash costs of $0.6 million and $1.7 million for the three and nine months ended September 30, 2026 (three and nine months ended September 30, 2025 - $0.6 million and $1.7 million). |
Corporate Consolidated Operating Income and Corporate Consolidated Operating Income Net of Realized Hedging and Operating Netbacks
The non-GAAP measures of Corporate Consolidated Operating Income including or excluding realized hedging in this News Release are calculated by adding or subtracting realized gains (losses) on commodity risk management contracts (as applicable), royalties, the cost of diluent blending, operating expenses and cash transportation & marketing expenses from petroleum, natural gas and midstream sales which is the most directly comparable GAAP measure. The Corporate Consolidated Operating Netbacks including or excluding realized hedging per boe are non-GAAP ratios calculated by dividing Corporate Consolidated Operating Income including or excluding hedging by the total sales volumes and are presented on a per boe basis. The Corporate Consolidated Operating Income and Corporate Consolidated Operating Netbacks including or excluding realized hedging measures allow management and others to evaluate the production results from the Company's Duvernay Energy and Athabasca (Thermal Oil) assets combined together including the impact of realized commodity risk management gains or losses (as applicable).
| Three months ended September 30, | Nine months ended September 30, | |||||||||||
| ($ Thousands, unless otherwise noted) | 2026 | 2025 | 2026 | 2025 | ||||||||
| Petroleum, natural gas and midstream sales(1) | $ | 487,362 | $ | 345,382 | $ | 1,282,152 | $ | 1,094,062 | ||||
| Royalties | (41,847 | ) | (11,863 | ) | (99,511 | ) | (41,811 | ) | ||||
| Cost of diluent(1) | (158,528 | ) | (122,011 | ) | (452,514 | ) | (421,208 | ) | ||||
| Operating expenses | (44,985 | ) | (37,317 | ) | (129,987 | ) | (124,798 | ) | ||||
| Transportation and marketing(2) | (24,721 | ) | (22,356 | ) | (70,247 | ) | (67,113 | ) | ||||
| Operating Income | 217,281 | 151,835 | 529,893 | 439,132 | ||||||||
| Realized loss on commodity risk mgmt. contracts | (44,654 | ) | (7,185 | ) | (57,397 | ) | (8,434 | ) | ||||
| OPERATING INCOME NET OF REALIZED HEDGING | $ | 172,627 | $ | 144,650 | $ | 472,496 | $ | 430,698 |
| (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 and $1.7 million for the three and nine months ended September 30, 2026 (three and nine months ended September 30, 2025 - $0.6 million and $1.7 million). |
Debt Adjusted Funds Flow
Debt Adjusted Funds Flow is a financial measure contained in this News Release that does not have a standardized meaning prescribed by IFRS and is considered to be a non-GAAP financial measure. It is not intended to represent cash flow from operating activities, net earnings or other measures of financial performance calculated in accordance with IFRS. The Debt Adjusted Funds Flow measure allows 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 excluding interest costs related to debt instruments. This non-GAAP financial measure 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
Net Cash is a supplementary financial measure and is defined as current assets less current liabilities less the face value of long-term debt, excluding risk management contracts.
Liquidity
Liquidity is a supplementary financial measure and is defined as cash and cash equivalents plus available credit capacity.
Production volumes details
| Three months ended September 30, | Nine months ended September 30, | ||||||||||||
| Production | 2026 | 2025 | 2026 | 2025 | |||||||||
| Duvernay Energy: | |||||||||||||
| Oil and condensate NGLs(1) | bbl/d | 3,016 | 2,053 | 3,338 | 1,834 | ||||||||
| Other NGLs | bbl/d | 303 | 196 | 362 | 268 | ||||||||
| Natural gas(2) | mcf/d | 5,787 | 4,563 | 5,460 | 4,578 | ||||||||
| Total Duvernay Energy | boe/d | 4,283 | 3,009 | 4,610 | 2,865 | ||||||||
| Total Thermal Oil bitumen | bbl/d | 34,319 | 36,590 | 32,368 | 35,942 | ||||||||
| Total Company production | boe/d | 38,602 | 39,599 | 36,978 | 38,807 |
| (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. |
Liquids is defined as bitumen, tight oil, light crude oil, medium crude oil and natural gas liquids.
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.
Footnote: Refer to the“Reader Advisory” section within this news release for additional information on Non‐GAAP Financial Measure (e.g. Adjusted Funds Flow, Free Cash Flow, Sustaining Capital, Debt Adjusted Funds Flow, Net Cash) and production disclosures.
Notes: 1. Metrics based on $5.7 billion enterprise value to Athabasca management's 2026 exit production and Debt Adjusted Funds Flow forecast. 2026 strip commodity prices (Sept. 28): US$85 WTI, US$15.50 Western Canadian Select heavy differential, C$1.80 AECO, 0.72 C$/US$ FX. 2. After-Tax Net Asset Value per Share calculated as at December 31, 2025 as evaluated by Athabasca's independent reserves evaluator McDaniel as Proved plus Probable after-tax NPV10, adjusted for Net Cash as at June 30, 2026, and the Duvernay Energy minority interest divided by common shares.
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