Athabasca Oil Announces 2024 Year-end Results including Record Cash Flow, Strong Return of Capital and Significant Reserves Growth

/EIN News/ -- CALGARY, Alberta, March 05, 2025 (GLOBE NEWSWIRE) -- Athabasca Oil Corporation (TSX: ATH) (“Athabasca” or the “Company”) is pleased to report its audited 2024 year-end results and reserves. Athabasca provides investors unique positioning to top tier liquids weighted assets (Thermal Oil and Duvernay) with a focus on maximizing cash flow per share growth by investing in competitive projects alongside a return of capital framework that will continue to direct 100% of Free Cash Flow to share buybacks in 2025.

Year-end 2024 Consolidated Corporate Results

• Production: Annual production of 36,815 boe/d (98% Liquids), representing 7% (14% per share) growth year over year. Strong production performance across all assets supported the Company achieving its upwardly revised annual guidance of 36,000 – 37,000 boe/d (July 2024).
• Record Cash Flow: Adjusted Funds Flow of $561 million ($1.02 per share), representing 102% per share growth year over year. Cash Flow from Operating Activities of $558 million. Free Cash Flow of $322 million from Athabasca (Thermal Oil).
• Capital Program: $268 million, within annual guidance of $270 million, highlighted by $164 million invested at Leismer for completing the 28,000 bbl/d expansion and advancing the 40,000 bbl/d expansion project and $73 million in Duvernay development.
• Pristine Balance Sheet: Net Cash position of $123 million; Liquidity of $481 million ($345 million of cash). Athabasca has $2.3 billion of tax pools (~80% high-value and immediately deductible).

Return of Capital Strategy

• Achieved Return of Capital Commitment in 2024: Athabasca (Thermal Oil) allocated ~100% of its Free Cash Flow (“FCF”) to return of capital in 2024 completing $317 million in share repurchases.
• Cumulative Return of Capital of ~$900 million: Since 2021, the Company has delivered a deliberate return of capital strategy, prioritizing ~$400 million of debt reduction followed by share buybacks of ~$500 million to date. The Company has reduced its fully diluted share count by ~18% since Q1 2023.
• Continued 100% of Free Cash Flow (Thermal Oil) Return to Shareholders through buybacks in 2025: The Company expects to utilize ~100% of its Normal Course Issuer Bid (“NCIB”) for the second straight year. Following the expiry of its current NCIB on March 17, 2025 the Company will renew a third annual NCIB with the Toronto Stock Exchange.
  

2024 Year-end Consolidated Reserves¹

• Differentiated Long-life Reserves: Athabasca holds 1.3 billion boe of Proved Plus Probable (“2P”) reserves and ~1 billion barrels of Contingent Resource (Best Estimate). This represents $6.4 billion² NPV10 of 2P reserves ($12.44 per share), an increase of 35% per share from 2023, and includes $3.8 billion² of Total Proved (“1P”) reserves ($7.28 per share), an increase of 34% per share from 2023.
• Thermal Oil Underpins Deep Value: An $813 million increase in 2P NPV10² to $5.8 billion is supported by well design driving improved capital efficiencies, lower operating costs at both producing projects and constructive heavy oil pricing. These reserves represent a ~30 year 1P and ~90 year 2P reserve life.
• Duvernay Value Capture: Duvernay Energy Corporation (“DEC”) 2P reserves increased by 170% to 73 mmboe, representing a NPV10² value of $614 million. Strong growth is attributed to establishing development on the newly operated lands and accelerated development on previous land positions. DEC has an estimated 444 gross drilling locations (204 net) across its ~200,000 acre (gross) land base.
  

2025 Guidance Maintained

• Athabasca (Thermal Oil): The Thermal Oil division underpins the Company’s strong Free Cash Flow outlook, with unchanged production guidance of 33,500 – 35,500 bbl/d and an unchanged ~$250 million capital budget. The program at Leismer includes the tie-in of six redrills and four new sustaining well pairs on Pad 10 early in 2025, along with continued pad and facility expansion work for the progressive expansion to 40,000 bbl/d. At Hangingstone two extended reach sustaining well pairs (~1,400 meter average laterals) that were drilled in 2024 will be placed on production in March.
• Duvernay Energy Corporation: The 2025 capital program of ~$85 million includes the completion of a 100% working interest (“WI”) three-well pad that was drilled in 2024 and the drilling and completion of a 30% WI four-well pad. Activity will also include spudding two additional multi-well pads in H2 2025 (one operated 100% WI pad and one 30% WI pad) with completions to follow in 2026. DEC is constructing gathering system infrastructure on its operated assets that will support exit production of ~5,500 boe/d this year and momentum into 2026.
• Significant Free Cash Flow: The Company forecasts consolidated Adjusted Funds Flow between $525 – $550 million³, including $475 - $500 million from its Thermal Oil assets. Every +US$1/bbl move in West Texas Intermediate (“WTI”) and Western Canadian Select (“WCS”) heavy oil impacts annual Adjusted Funds Flow by ~$10 million and ~$17 million, respectively. Athabasca forecasts generating ~$1.8 billion of Free Cash Flow³ from its Thermal Oil assets over five years (2025-29), representing ~70% of its current equity market capitalization.
• Competitive and Resilient Break-evens. Thermal Oil is competitively positioned with sustaining capital to hold production flat funded within cash flow at ~US$50/bbl WTI¹ and growth initiatives fully funded within cash flow below US$60/bbl WTI¹. The Company’s operating break-even is estimated at ~US$40/bbl WTI³. Every $0.01 change in the Canada/US exchange rate is ~$10 million in annual Adjusted Funds Flow, and a weakened Canadian dollar would help cushion the impact that any potential US tariffs may have on commodity pricing.
• Steadfast Focus on Cash Flow Per Share Growth: The Company forecasts ~20% compounded annual cash flow per share³ growth between 2025 – 2029 driven by investing in attractive capital projects and prioritizing share buybacks with Free Cash Flow.
  

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, Net Cash, Liquidity) and production disclosure.

¹ Consolidated reserves reflect gross reserves and financial metrics before taking into account Athabasca’s 70% equity interest in Duvernay Energy.
² Net present value of future net revenue before tax at a 10% discount rate (NPV 10 before tax) for 2024 is based on an average of McDaniel, Sproule and GLJ pricing as at January 1, 2025.
³ Pricing Assumptions: 2025 US$70 WTI, US$12.50 WCS heavy differential, C$2 AECO, and 0.725 C$/US$ FX; 2026-29 US$70 WTI, US$12.50 WCS heavy differential, C$3 AECO, and 0.725 C$/US$ FX.

Financial and Operational Highlights

	Three months ended December 31,								Year ended December 31,
($ Thousands, unless otherwise noted)	2024				2023				2024					2023
CORPORATE CONSOLIDATED(1)
Petroleum and natural gas production (boe/d)(2)		37,236				33,127				36,815				34,490
Petroleum, natural gas and midstream sales	$	352,456			$	315,929			$	1,442,091			$	1,268,525
Operating Income(2)	$	155,022			$	96,960			$	620,092			$	417,023
Operating Income Net of Realized Hedging(2)(3)	$	153,119			$	91,443			$	613,630			$	381,088
Operating Netback ($/boe)(2)	$	45.53			$	30.44			$	46.14			$	32.57
Operating Netback Net of Realized Hedging ($/boe)(2)(3)	$	44.97			$	28.71			$	45.66			$	29.76
Capital expenditures	$	92,944			$	38,752			$	268,042			$	139,832
Cash flow from operating activities	$	158,677			$	103,196			$	557,541			$	305,526
per share - basic	$	0.30			$	0.18			$	1.02			$	0.52
Adjusted Funds Flow(2)	$	143,737			$	81,830			$	560,935			$	295,236
per share - basic	$	0.27			$	0.14			$	1.02			$	0.51
ATHABASCA (THERMAL OIL)
Bitumen production (bbl/d)(2)		33,849				31,059				33,505				30,246
Petroleum, natural gas and midstream sales	$	346,716			$	309,078			$	1,419,670			$	1,204,245
Operating Income(2)	$	143,246			$	92,199			$	569,083			$	370,732
Operating Netback ($/bbl)(2)	$	46.30			$	30.78			$	46.54			$	32.93
Capital expenditures	$	74,268			$	29,371			$	194,902			$	118,975
Adjusted Funds Flow(2)	$	133,398							$	516,612
Free Cash Flow(2)	$	59,130							$	321,710
DUVERNAY ENERGY(1)
Petroleum and natural gas production (boe/d)(2)		3,387				2,068				3,310				4,244
Percentage Liquids (%)(2)	75		%		71		%		76		%		58		%
Petroleum, natural gas and midstream sales	$	20,179			$	12,659			$	83,194			$	91,062
Operating Income(2)	$	11,776			$	4,761			$	51,009			$	46,291
Operating Netback ($/boe)(2)	$	37.79			$	25.02			$	42.10			$	29.89
Capital expenditures	$	18,676			$	9,381			$	73,140			$	20,857
Adjusted Funds Flow(2)	$	10,339							$	44,323
Free Cash Flow(2)	$	(8,337	)						$	(28,817	)
NET INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS)
Net income (loss) and comprehensive income (loss)(4)	$	264,336			$	27,506			$	467,743			$	(51,220	)
per share - basic(4)	$	0.50			$	0.05			$	0.85			$	(0.09	)
per share - diluted(4)	$	0.50			$	0.03			$	0.85			$	(0.09	)
COMMON SHARES OUTSTANDING
Weighted average shares outstanding - basic		526,233,362				574,412,564				547,795,407				583,757,575
Weighted average shares outstanding - diluted		530,796,068				588,498,448				553,382,675				583,757,575

			December 31,				December 31,
As at ($ Thousands)			2024				2023
LIQUIDITY AND BALANCE SHEET
Cash and cash equivalents			$	344,836			$	343,309
Available credit facilities(5)			$	136,324			$	85,488
Face value of term debt(6)			$	200,000			$	207,648

^{(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 “Advisories and Other Guidance” section within this News Release for additional information on Non-GAAP Financial Measures and production disclosure.
(3)   Includes realized commodity risk management loss of $1.9 million and $6.5 million for the three months and year ended December 31, 2024 (three months and year ended December 31, 2023 – loss of $5.5 million and $35.9 million).
(4)    Net income (loss) and comprehensive income (loss) per share amounts are based on net income (loss) and comprehensive income (loss) attributable to shareholders of the Parent Company. In the calculation of diluted earnings per share for the three months ended December 31, 2023 earnings were reduced by $11.3 million to account for the impact to net income had the outstanding warrants been converted to equity.
(5)    Includes available credit under Athabasca's and Duvernay Energy's Credit Facilities and Athabasca's Unsecured Letter of Credit Facility.
(6)    The face value of the term debt at December 31, 2023 was US$157.0 million translated into Canadian dollars at the December 31, 2023 exchange rate of US$1.00 = C$1.3226.}

Athabasca (Thermal Oil) Year-end 2024 Highlights and Operations Update

• Production: Bitumen production averaged 33,505 bbl/d in 2024 representing 11% growth year over year (18% per share) supported by the Leismer facility expansion mid-year and Hangingstone’s resilient production base.
• Record Cash Flow: Adjusted Funds Flow of $517 million with an Operating Netback of $46.54/bbl. Operating Income of $569 million.
• Capital Program: $195 million of capital expenditures in 2024 focused on expansion projects at Leismer and sustaining operations at Hangingstone.
• Free Cash Flow: $322 million of Free Cash Flow supporting 100% return of capital commitment.

Leismer

Bitumen production for 2024 averaged 26,103 bbl/d, up 16% year over year (18% per share).

In Q4 2024, the Company completed drilling six extended redrills on Pad L1 and four well pairs at Pad L10. The redrills were placed onstream in February and support production of ~28,000 bbl/d. Steaming of the Pad L10 well pairs is expected to start in April with first production mid-year. Another six well pairs will be drilled in H2 2025.

Activity at Leismer continues to be focused on advancing progressive growth to 40,000 bbl/d by the end of 2027. The project cost is estimated at $300 million generating a capital efficiency of approximately $25,000/bbl/d. The $300 million includes an estimated $190 million for facility capital (majority spread over 2025 and 2026) and an estimated $110 million for growth wells. To date the Company has procured ~80% of the project and remains on budget and on schedule with the original sanction plans announced in July 2024. This winter the Company completed regional infrastructure to Pad L10 and L11 including lease site construction, delineation drilling and pipeline looping. Major facility equipment has been purchased and the Company is preparing to install two previously acquired steam generators in 2027.

Leismer is forecasted to remain pre-payout from a crown royalty perspective until late 2027³.

Hangingstone

Bitumen production for 2024 averaged 7,402 bbl/d and experienced no decline during the year. Non-condensable gas co-injection has aided in pressure support and reduced energy usage. Hangingstone’s steam oil ratio averaged 3.4 for 2024.

At Hangingstone two extended reach sustaining well pairs (~1,400 meter average laterals) were drilled in 2024. These wells commenced steaming in December and will be placed on production in March. These well pairs are expected to enhance the current production level and support base production long term.

Hangingstone continues to deliver meaningful cash flow contributions with minimal capital to the Company and also has a pre-payout crown royalty structure to beyond 2030³.

Corner

The Company’s Corner asset is a large de-risked top-tier oil sands asset adjacent to Leismer with 351 million barrels of 2P reserves and 520 million barrels of Contingent Resource (Best Estimate Unrisked). There are over 300 delineation wells and ~80% seismic coverage with reservoir qualities similar or better than Leismer. The asset has a 40,000 bbl/d regulatory approval for development with the existing pipeline corridor passing through the Corner lease. The Company is updating its development plans and is finalizing facility cost estimates, including modular optionality. Athabasca intends to explore external funding options and does not plan to fund an expansion utilizing existing cash flow or balance sheet resources.

Duvernay Energy Corporation Year-end 2024 Highlights and Operations Update

• Production: Production averaged 3,310 boe/d (76% Liquids) in 2024, supported by two pads (5 gross, 2.9 net wells) placed on production.
• Cash Flow: Adjusted Funds Flow of $44 million in 2024 with an Operating Netback of $42.10/boe. Operating Income was $51 million in 2024. DEC has no long-term debt and ended the year with a cash position of $26 million.
• Capital Program: $73 million of capital, fully funded within cash flow and cash on hand in DEC.
  

Production from wells drilled in 2024 continue to validate DEC’s type curve expectations. The five new wells placed on production have average IP30’s of ~1,200 boe/d per well (86% liquids) and IP90s of ~940 boe/d (86% Liquids) per well.

DEC drilled a three-well 100% working interest pad at 4-18-64-16W5 in Q4 2024. The wells were cased with average laterals of ~4,100 meters per well. This operated pad of wells is expected to be completed post-breakup in 2025. Winter activity has been focused on strategic gathering system investments connecting its newly operated assets with its existing operated infrastructure on the joint venture acreage supporting near-term development plans. DEC has secured a regional term water license and is commencing water sourcing in advance of the completion activities this summer.

Marketing Access Strategy and Resilience to United States (“US”) Trade Tariffs

• Long Term Market Access: Athabasca has diversified its long term end market access which includes ~7,200 bbl/d of capacity on the Keystone pipeline by 2028, providing direct exposure to the US Gulf Coast. The Company has recently contracted, through an intermediary, 10,000 bbl/d of capacity on the Enbridge Express system, providing capacity to PADD II with no associated balance sheet commitments. The start-up of the Trans Mountain pipeline expansion has provided excess egress capacity out of Canada, driving tighter and less volatile WCS heavy differentials. Industry market access is expected to be further supported by expansions on the Enbridge and Trans Mountain Pipeline systems along with the possible revival of new pipeline projects.
• Athabasca is Resilient: The Company is well positioned to withstand macro volatility including proposed US Trade Tariffs with operational flexibility, financial durability and a robust cash flow outlook. Athabasca’s capital program is designed to provide flexible growth at Leismer and DEC has no near-term land expiries with flexible development plans. The Company’s balance sheet is in a $123 million Net Cash position with tenure on Canadian denominated term debt until 2029. Every $0.01 change in the Canada/US exchange rate is ~$10 million in annual Adjusted Funds Flow, and a weakened Canadian dollar would help cushion the impact that any potential US tariffs may have on commodity pricing.

Differentiated Long-life Reserves¹

• Strong Reserve Growth: 22% increase year over year in 2P reserve value to $6.4 billion NPV10² ($12.44 per share, 35% increase) and 21% increase in 1P reserves to $3.8 billion² ($7.28 per share, 34% increase). Athabasca maintains a deep inventory with a ~30 year 1P and ~90 year 2P reserve life.
• Massive Resource Base: 1.3 billion boe of 2P reserves, anchored by 1.2 billion barrels of 2P Thermal Reserves, plus an additional ~1 billion barrels of Contingent Resources (best estimate).
• Duvernay Energy: Significant reserve additions from ~46,000 acres of 100% working interest land, driving a 128% year over year increase in 2P reserve value to $614 million NPV10².
  

Athabasca’s independent reserves evaluator, McDaniel & Associates Consultants Ltd. (“McDaniel”), prepared the year-end reserves evaluation effective December 31, 2024. Reserves are reported on a consolidated basis and reflecting gross reserves and financial metrics before taking into account Athabasca’s 70% equity interest in Duvernay Energy.

	Duvernay Energy1							Thermal Oil								Corporate
	2023					2024				2023				2024				2023				2024
Reserves (mmboe)
Proved Developed Producing		4				6				77				74				82				80
Total Proved		11				41				404				404				415				445
Proved Plus Probable		27				73				1,216				1,209				1,243				1,282
NPV10 BT ($million)2
Proved Developed Producing	$58				$81				$1,713				$1,749				$1,771				$1,830
Total Proved	$142				$345				$2,969				$3,421				$3,111				$3,766
Proved Plus Probable	$269				$614				$5,011				$5,824				$5,280				$6,438

Numbers in the table may not add precisely due to rounding.

For additional information regarding Athabasca’s reserves and resources estimates, please see “Independent Reserve and Resource Evaluations” in the Company’s 2024 Annual Information Form which is available on the Company’s website or on SEDAR at www.sedarplus.ca.  

¹ Consolidated reserves reflect gross reserves and financial metrics before taking into account Athabasca’s 70% equity interest in Duvernay Energy.
² Net present value of future net revenue before tax at a 10% discount rate (NPV 10 before tax) for 2024 is based on an average of McDaniel, Sproule and GLJ pricing as at January 1, 2025.

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.

For more information, please contact:

Matthew Taylor	Robert Broen
Chief Financial Officer	President and CEO
1-403-817-9104	1-403-817-9190
mtaylor@atha.com	rbroen@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 and capital efficiencies; production growth to expected production rates and estimated sustaining capital amounts; timing of Leismer’s and Hangingstone’s pre-payout royalty status; applicability of tax pools and the timing of tax payments; 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; our outlook in respect of the Company’s business environment, including in respect of commodity pricing; and other matters.

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

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

Also included in this News Release are estimates of Athabasca's 2025 outlook which are based on the various assumptions as to production levels, commodity prices, currency exchange rates and other assumptions disclosed in this News Release. To the extent any such estimate constitutes a financial outlook, it was approved by management and the Board of Directors of Athabasca and is included to provide readers with an understanding of the Company’s outlook. Management does not have firm commitments for all of the costs, expenditures, prices or other financial assumptions used to prepare the financial outlook or assurance that such operating results will be achieved and, accordingly, the complete financial effects of all of those costs, expenditures, prices and operating results are not objectively determinable. The actual results of operations of the Company and the resulting financial results may vary from the amounts set forth herein, and such variations may be material. The outlook and forward-looking information contained in this New Release was made as of the date of this News release and the Company disclaims any intention or obligations to update or revise such outlook and/or forward-looking information, whether as a result of new information, future events or otherwise, unless required pursuant to applicable law.

Oil and Gas Information

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

Initial Production Rates 

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

Reserves Information

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

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

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

Non-GAAP and Other Financial Measures, and Production Disclosure

The "Corporate Consolidated Adjusted Funds Flow", “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.

Adjusted Funds Flow, Adjusted Funds Flow Per Share and Free Cash Flow

Adjusted Funds Flow and Free Cash Flow are non-GAAP financial measures and are not intended to represent cash flow from operating activities, net earnings or other measures of financial performance calculated in accordance with IFRS. The Adjusted Funds Flow and Free Cash Flow measures allow management and others to evaluate the Company’s ability to fund its capital programs and meet its ongoing financial obligations using cash flow internally generated from ongoing operating related activities. Adjusted Funds Flow per share is a non-GAAP financial ratio calculated as Adjusted Funds Flow divided by the applicable number of weighted average shares outstanding. Adjusted Funds Flow and Free Cash Flow are calculated as follows:

	Three months ended December 31, 2024											Three months ended December 31, 2023
($ Thousands)	Athabasca (Thermal Oil)			Duvernay Energy(1)				Corporate Consolidated(1)				Corporate Consolidated
Cash flow from operating activities	$	144,810			$	13,867			$	158,677			$	103,196
Changes in non-cash working capital		(11,504	)			(3,675	)			(15,179	)			(21,973	)
Settlement of provisions		92				147				239				607
ADJUSTED FUNDS FLOW		133,398				10,339				143,737				81,830
Capital expenditures		(74,268	)			(18,676	)			(92,944	)			(38,752	)
FREE CASH FLOW	$	59,130			$	(8,337	)		$	50,793			$	43,078

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

	Year ended December 31, 2024											Year ended December 31, 2023
($ Thousands)	Athabasca (Thermal Oil)			Duvernay Energy(1)				Corporate Consolidated(1)				Corporate Consolidated
Cash flow from operating activities	$	511,828			$	45,713			$	557,541			$	305,526
Changes in non-cash working capital		3,056				(1,541	)			1,515				525
Settlement of provisions		1,728				151				1,879				1,762
Long-term deposit		—				—				—				(12,577	)
ADJUSTED FUNDS FLOW		516,612				44,323				560,935				295,236
Capital expenditures		(194,902	)			(73,140	)			(268,042	)			(139,832	)
FREE CASH FLOW	$	321,710			$	(28,817	)		$	292,893			$	155,404

^{(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 December 31,								Year ended December 31,
($ Thousands, unless otherwise noted)	2024				2023				2024				2023
Petroleum and natural gas sales	$	20,179			$	12,659			$	83,194			$	91,062
Royalties		(2,753	)			(2,180	)			(11,035	)			(12,583	)
Operating expenses		(4,729	)			(5,009	)			(17,116	)			(24,997	)
Transportation and marketing		(921	)			(709	)			(4,034	)			(7,191	)
DUVERNAY ENERGY OPERATING INCOME	$	11,776			$	4,761			$	51,009			$	46,291

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 December 31,								Year ended December 31,
($ Thousands, unless otherwise noted)	2024				2023				2024				2023
Heavy oil (blended bitumen) and midstream sales	$	346,716			$	309,078			$	1,419,670			$	1,204,245
Cost of diluent		(137,817	)			(137,438	)			(549,808	)			(518,219	)
Total bitumen and midstream sales		208,899				171,640				869,862				686,026
Royalties		(12,413	)			(15,695	)			(75,064	)			(60,865	)
Operating expenses - non-energy		(20,699	)			(23,767	)			(93,144	)			(87,116	)
Operating expenses - energy		(11,526	)			(17,651	)			(49,713	)			(81,769	)
Transportation and marketing(1)		(21,015	)			(22,328	)			(82,858	)			(85,544	)
ATHABASCA (THERMAL OIL) OPERATING INCOME	$	143,246			$	92,199			$	569,083			$	370,732

^{(1)   Transportation and marketing excludes non-cash costs of $0.6 million and $2.2 million for the three months and year ended December 31, 2024 (three months and year ended December 31, 2023 - $0.6 million and $2.2 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 December 31,								Year ended December 31,
($ Thousands, unless otherwise noted)	2024				2023				2024				2023
Petroleum, natural gas and midstream sales(1)	$	366,895			$	321,737			$	1,502,864			$	1,295,307
Royalties		(15,166	)			(17,875	)			(86,099	)			(73,448	)
Cost of diluent(1)		(137,817	)			(137,438	)			(549,808	)			(518,219	)
Operating expenses		(36,954	)			(46,427	)			(159,973	)			(193,882	)
Transportation and marketing(2)		(21,936	)			(23,037	)			(86,892	)			(92,735	)
Operating Income		155,022				96,960				620,092				417,023
Realized loss on commodity risk mgmt. contracts		(1,903	)			(5,517	)			(6,462	)			(35,935	)
OPERATING INCOME NET OF REALIZED HEDGING	$	153,119			$	91,443			$	613,630			$	381,088

^{(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 $2.2 million for the three months and year ended December 31, 2024 (three months and year ended December 31, 2023 - $0.6 million and $2.2 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 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

		Three months ended December 31,								Year ended December 31,
Production		2024				2023				2024				2023
Duvernay Energy:
Oil(1)	bbl/d		2,103				1,208				2,202				1,396
Condensate NGLs	bbl/d		—				—				—				528
Oil and condensate NGLs	bbl/d		2,103				1,208				2,202				1,924
Other NGLs	bbl/d		422				258				329				525
Natural gas(2)	mcf/d		5,172				3,612				4,677				10,769
Total Duvernay Energy	boe/d		3,387				2,068				3,310				4,244
Total Thermal Oil bitumen	bbl/d		33,849				31,059				33,505				30,246
Total Company production	boe/d		37,236				33,127				36,815				34,490

^{(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 average daily Thermal Oil production of 33,500 ‐ 35,500 bbl/d for 2025. Athabasca expects that 100% of that production will be comprised of bitumen. Duvernay Energy’s forecasted total average daily production of ~4,000 boe/d for 2025 is expected to be comprised of approximately 68% tight oil, 23% shale gas and 9% NGLs.

Liquids is defined as bitumen, light crude oil, medium crude oil and natural gas liquids.

Reserve Life Index is calculated as year-end reserves divided by Q4 2024 production.

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.