Athabasca Oil Corporation (TSX: ATH) (“Athabasca” or “the Company”) is pleased to announce its 2024 budget focused on profitable production growth and strong free cash flow generation. Athabasca provides investors unique positioning to top tier oil weighted assets (Thermal Oil and Duvernay) with a capital allocation framework aimed at maximizing cash flow per share growth and returning capital to shareholders.  

2024 Budget Highlights

Capital Program. Athabasca is planning capital expenditures of $175 million ($135 million Thermal Oil & $40 million Light Oil) with activity focused on completing the 28,000 bbl/d expansion project at Leismer, sustaining capital at Hangingstone and three Duvernay pads at Kaybob.

Profitable and Sustainable Growth. The Company plans to grow production to ~37,500 boe/d by year-end 2024, representing ~14% growth from year-end 2023. Annual production guidance is 35,000 – 36,000 boe/d (~98% Liquids). Growth will be weighted to the second half of the year with the Leismer expansion project expected to be completed mid-year and Duvernay production additions into the Fall. The portfolio of long reserve life assets underpins a low corporate decline rate of ~5% annually and the Company estimates sustaining capital at ~$150 million annually.

Managing for Strong Free Cash Flow. Athabasca anticipates generating ~$500 million of Adjusted Funds Flow and ~$325 million of Free Cash Flow (US$80/bbl WTI & US$15/bbl WCS heavy differential)1. During the timeframe of 2024 – 2026, Athabasca forecasts >$1 Billion in Free Cash Flow1, representing over 50% of its current equity market capitalization.  

Exposure to Improving Heavy Oil Pricing. Athabasca anticipates tightening of the WCS heavy differentials from current levels as the Trans Mountain Expansion pipeline (590,000 bbl/d) commences operations in 2024. Every $5/bbl WTI change impacts Adjusted Funds Flow by ~$55 million annually and every $5/bbl WCS change impacts Adjusted Funds Flow by ~$85 million annually.

Financial Resiliency. Athabasca’s long reserve life assets and strong balance sheet provide resiliency. The Company estimates 2023 year-end Liquidity of ~$455 million, including cash of ~$370 million. The principal balance on the Company’s senior secured second lien notes (the “Notes”) is US$157 million with an estimated year-end Net Cash position of ~$155 million. The Company’s low sustaining capital requirements are fully funded within cash flow to ~US$55/bbl WTI.

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  Pricing Assumptions: 2024 US$80 WTI, US$15 Western Canadian Select “WCS” heavy differential, C$3 AECO, and $0.75 C$/US$ FX. 2025-26 US$85 WTI, US$12.50 WCS heavy differential, C$3 AECO, and $0.75 C$/US$ FX.

Return of Capital Update

Athabasca commenced its return of capital commitment to shareholders in 2023 through an inaugural share buyback program. Since April, the Company has completed ~$137 million in buybacks (39 million shares at an average price of $3.51 per share). The Company has reduced its fully diluted share count by ~50 million shares or 7.5% to the end of November. In addition, a total of 92% of the warrants issued in October 2021 in connection with the Notes have been exercised to date with a remaining 6.7 million potential shares issuable (4.9 million potential shares assuming cashless exercise at a $3.50 share price).

In 2024, Athabasca plans to allocate 100% of Free Cash Flow to shareholders through share buybacks. The Company anticipates completing its current Normal Course Issuer Bid on March 15, 2024 with the intention to renew the program with the Toronto Stock Exchange for another 12 month period.

Asset Development

Capital Efficient Growth at Leismer

Production is expected to increase to ~28,000 bbl/d mid-year through a facility expansion project and the ramp-up of eight behind pipe wells that recently commenced steaming operations. This production level can be held with modest sustaining capital (~$6/bbl) for many years into the future.

The Company will drill an additional eight wells in 2024. Drilling is expected to commence in January with four redrill wells on Pad 4. Redrills target low-risk bypassed pay on mature pads with strong expected capital efficiencies of ~$6,500/bbl/d leveraging off existing pad infrastructure. In the second half of 2024, additional well pairs will be drilled on Pad 10 which is expected to accommodate a total of 15 future well pairs in some of the best reservoir in the Leismer development area.

Leismer has regulatory approved capacity for 40,000 bbl/d. The Company is operationally ready to execute phased expansions to reach this capacity within approximately three years at competitive capital efficiencies. These future growth projects will be contingent on less volatile WCS heavy differentials that are expected with the completion of the Trans Mountain Pipeline Expansion. Future expansions are expected to provide a continuous growth profile at the asset that is well within corporate cash flow and the Company will maintain its return of capital commitment and focus on balance sheet strength.  

Hangingstone Sustaining Operations

Activity at Hangingstone will include drilling two sustaining well pairs utilizing modern ~1,400 meter lateral length design with expected capital efficiencies of ~$15,000 bbl/d. These well pairs will support base production in 2025 and beyond with the objective of ensuring Hangingstone continues to deliver meaningful cash flow contributions to the Company.

Kaybob Duvernay Drilling

The Company is beginning activity to accelerate the value of its asset position in the Duvernay. Activity in 2024 will include nine gross wells at Kaybob. Athabasca has spud a two-well 100% working interest pad at Kaybob East that will be placed on production in Q2 2024. A three-well 30% working interest pad at Kaybob West is expected to spud in Q1 2024 and will be placed on production in Q2 2024. A four-well 30% working interest pad at Kaybob East is expected to spud in Q4 2024 and will be placed on production in 2025. The Duvernay program is expected to drive production and cash flow growth and will offset the volumes associated with the Montney non-core disposition completed in September 2023.

At Kaybob East and Two Creeks, the Company has extended production history from 27 wells derisking an inventory of 290 gross future locations. The wells have consistently supported the Company’s type curve expectations with IP365’s averaging ~550 boe/d per well, ~85% Liquids (latest 12 wells since 2020) demonstrating the significant potential of the asset. The area continues to be active with industry drilling programs underway.

Strategic Positioning

Athabasca is focused on driving shareholder value through strong multi‐year cash flow per share growth. The Company’s long life, low decline asset base provides a platform to drive profitable liquids weighted growth supported by financial resiliency to execute on return of capital initiatives.

Pre-payout Thermal Oil Differentiation. Strong margins and Free Cash Flow are supported by a Thermal Oil pre-payout Crown royalty structure, with royalty rates between 5 – 9% anticipated to last into 20271. Leismer has regulatory approved capacity of 40,000 bbl/d. In addition, Athabasca has a fully de-risked asset at Corner which also has regulatory approval for 40,000 bbl/d with reservoir quality equivalent to or better than Leismer. The Company has updated its Corner development plans and is prepared to explore external funding options with stability in commodity prices.

Light Oil Optionality. Athabasca has exposure to ~155,000 gross Duvernay acres across Kaybob West, Kaybob North, Kaybob East and Two Creeks with ~500 future well locations serviced by strategic operated infrastructure. The Company has strong confidence in the Duvernay’s deliverability with extended production history on its acreage and regional industry results. The Company’s development plans are aimed at accelerating the transition of resource value to cash flow growth.

Excellent Exposure to Commodity Upside. Athabasca maintains excellent exposure to upside in commodity prices with 25% of rolling 12-month production volumes hedged in accordance with its debt agreements. The Company has hedged ~9,000 bbl/d in Q1 2024 with an average WTI collar of US$50 – US$126/bbl. Every $5/bbl WTI change impacts Adjusted Funds Flow by ~$55 million annually and every US$5/bbl WCS differential change impacts Adjusted Funds Flow by ~$85 million annually.

Differentiated Tax Pools. The Company has ~$2.8 billion in tax pools, including ~$2.3 billion of immediately deductible non‐capital loses and exploration pools. The Company does not anticipate paying cash taxes until 2030 ($85/bbl WTI & $12.50/bbl WCS differential flat long-term pricing).

Emissions Reduction and Carbon Capture. The Company has a target of a 30% reduction in emissions intensity by 2025 from 2015 levels. Athabasca has also partnered with Entropy Inc. to implement carbon capture and storage (“CCS”) at Leismer, using Entropy’s proprietary CCS technology. This project is not expected to be sanctioned until the Federal government provides fiscal and regulatory policy that ensure CCS projects are economically viable. Our annual ESG report can be found on the Company’s website (

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 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”, “forecast”, “continue”, “estimate”, “expect”, “may”, “will”, “project”, “target”, “should”, “believe”, “predict”, “pursue”, “potential”, “view” and “contemplate” and similar expressions 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 and, except as required by applicable securities laws, the Company undertakes no obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events. In particular, this News Release contains forward-looking information pertaining to, but not limited to, the following: the Company’s 2024 capital expenditures, production and financial guidance, 2024-26 Free Cash Flow outlook, financial metrics for Thermal Oil projects, timing for development projects in Thermal Oil and Light Oil Divisions, return of capital strategy, timing for future cash taxes, and other matters.

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 funds flow, and free cash flow outlook; 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 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, 2022 (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 Revised Annual Information Form (“AIF”) dated May 11, 2023 and Management’s Discussion and Analysis dated October 31, 2023, 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; continued impact of the COVID-19 pandemic; ability to finance capital requirements; climate change and carbon pricing risk; regulatory environment and changes in applicable law; gathering and processing facilities, pipeline systems and rail; statutes and regulations regarding the environment; political uncertainty; state of capital markets; anticipated benefits of acquisitions and dispositions; abandonment and reclamation costs; changing demand for oil and natural gas products; royalty regimes; foreign exchange rates and interest rates; reserves; hedging; operational dependence; operating costs; project risks; 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; 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; and risks related to our debt and securities.

Also included in this News Release are estimates of Athabasca's 2024 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 financial outlook 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 financial outlook, 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 in this News Release 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, 2022. 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, 2022 and based on average pricing of McDaniel, Sproule and GLJ as of January 1, 2023.

The 500 gross total Duvernay drilling locations referenced include: 5 proved undeveloped locations and 77 probable undeveloped locations for a total of 82 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, 2022 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 “Adjusted Funds Flow”, “Free Cash Flow”, and “sustaining capital” 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. 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 Debt/Cash and Liquidity are supplementary financial measures.

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 is calculated by adjusting for changes in non‐cash working capital and settlement of provisions from cash flow from operating activities. The Free Cash Flow measure is calculated by subtracting Capital Expenditures from Adjusted Funds Flow.

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

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

Production volumes details

This News Release makes reference to Athabasca's forecasted total average daily production between 35,000 - 36,000 boe/d for 2024. Athabasca expects that approximately 91% of that production will be comprised of bitumen, 2% shale gas, 6% tight oil, 0% condensate natural gas liquids and 1% other natural gas liquids.

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

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