Athabasca Oil Announces Creation of “Duvernay Energy Corporation” with Cenovus Energy to Accelerate Value in the Prolific Kaybob Duvernay Play

Duvernay Energy Land Map

• Athabasca and Cenovus combine Kaybob assets to create pure-play Duvernay entity
• Exposure to ~200,000 gross acres including a newly operated 100% WI position of ~46,000 acres
• Leverages significant prior de-risking activity to date on Athabasca’s Duvernay assets  
• Debt-free entity seeded with $40 million cash and a $50 million credit facility
• Production of ~2,000 boe/d with a self-funded development plan to ~25,000 boe/d (~75% Liquids)
• Athabasca Thermal Oil budget & Return of Capital commitment of 100% Free Cash Flow remain intact
• Athabasca and Duvernay Energy will be positioned as two separate companies with independent capital allocation frameworks

CALGARY, Alberta, Dec. 19, 2023 (GLOBE NEWSWIRE) — Athabasca Oil Corporation (TSX: ATH) (“Athabasca” or “the Company”) is pleased to announce it has entered into transaction agreements (“Transaction”) to create Duvernay Energy Corporation (“Duvernay Energy”) with Cenovus Energy Inc. (“Cenovus”). Duvernay Energy will be a standalone self-funded entity that will drive strong, high netback cash flow and production growth and is expected to unlock significant value. The transaction is aligned with Athabasca’s strategy to maximize cash flow per share growth and return capital to shareholders.

Transaction Overview

Athabasca and Cenovus will jointly contribute assets into Duvernay Energy. Athabasca will own a 70% equity interest in Duvernay Energy with Cenovus owning the remaining 30% equity interest. Athabasca will manage Duvernay Energy through a management and operating services agreement. Duvernay Energy’s Board of Directors will include three members nominated by Athabasca and one member nominated by Cenovus.

On inception, Duvernay Energy will have strong Liquidity including seed capital of $40 million and a $50 million new credit facility led by ATB Financial. Athabasca’s $22 million seed capital contribution to Duvernay Energy will be within its previous $175 million 2024 capital guidance ($135 million Thermal Oil and $40 million Light Oil). Athabasca is also contributing ~$20 million in expenditures related to Q4 2023 drilling operations on a 100% working interest multi-well pad and long lead inventory for future activity.

The Transaction will have an effective date of January 1, 2024, is expected to close in the first quarter of 2024 and is subject to customary closing conditions and regulatory approvals, including Competition Act approval. On closing the Company will provide updated guidance for Duvernay Energy and Athabasca.

Duvernay Energy Assets

Duvernay Energy will be positioned with unparalleled pure-play exposure to the prolific Kaybob Duvernay resource play. Duvernay Energy’s assets will be primarily located in the volatile oil region.

In addition to the Company’s existing joint venture assets, Duvernay Energy has exposure to ~46,000 acres of 100% working interest operated lands contiguous to its existing Duvernay assets. This acreage includes new lands strategically acquired by Athabasca through Crown land sales over the last 18 months and Cenovus’s contribution of Kaybob acreage. In total, Duvernay Energy will have exposure to ~200,000 gross acres in the liquids rich and oil windows with ~500 gross future well locations. The assets are serviced by existing infrastructure including two operated oil batteries with a gas pipeline network connected to both the Pembina Gas Infrastructure KA facility and the Keyera Simonette facility. Liquids are directly connected to the Pembina Peace liquids system. Duvernay Energy will also own an 8.1% working interest in the 7-4-63-16W5 gas facility.

Current production from Duvernay Energy is ~2,000 boe/d (~75% Liquids) with a defined and self-funded development plan outlined in the section below.  

Duvernay Energy Land Map

Duvernay Energy Development Plans

Duvernay Energy’s development plans will leverage off significant de-risking activity on its acreage (74 horizontal wells) and on adjacent competitor activity. Duvernay Energy will execute a self-funded development plan that will target growth to ~25,000 boe/d (~75% Liquids) in the late 2020s with an inventory to support a stable production profile thereafter for approximately twenty years.

The Company has extended production history with well results consistently supporting type curve expectations. At Kaybob East and Two Creeks, IP365’s have averaged ~550 boe/d per well (85% Liquids) on the last 12 wells. Latest well design will include lateral lengths up to 4,500 meters that are expected to yield stronger initial rates, larger reserves and improved capital efficiencies. Individual well costs are estimated to be $10 – 14 million, depending on pad size, lateral length and proppant loading.

The 2024 development program will include 12 gross wells (7.1 net wells) with a capital budget of ~$82 million. The program is expected to be funded from the $40 million seed capital contribution and cash flow from Duvernay Energy. The plan is expected to drive strong production momentum with production forecasted to average ~6,000 boe/d in 2025. 2024 activity consists of:

• 100% working interest activity: A recently spudded two-well pad at Kaybob East will be placed on production in Q2 2024. An additional two multi-well pads will spud mid-year and are expected to be placed on-stream in early 2025.
• 30% working interest Joint Venture activity: A three-well pad at Kaybob West is expected to spud in Q1 2024 and will be placed on production in Q2 2024. An additional four-well pad at Kaybob East is expected to spud in Q4 2024 and will be placed on production in 2025.

Long-term development is expected to be funded within cash flow and is flexible for a range of commodity prices. The plan will be weighted to activity on Duvernay Energy’s 100% working interest acreage and augmented by development within its 30% working interest joint venture acreage.

Strategic Rationale

Transaction Accelerates Value in Standalone Self-Funded Duvernay Energy. The new entity will accelerate value capture for Athabasca’s shareholders by providing a clear path for accretive production and cash flow growth without sacrificing Athabasca’s ability to fund capital in its Thermal Oil division or Athabasca’s return of capital strategy. The Transaction consolidates Athabasca’s and Cenovus’s 100% working interest operated assets, providing flexibility and efficiencies of scale for impactful development, along with Athabasca’s existing 30% working interest Duvernay joint venture assets that are governed by a strong joint development agreement. Production and cash flow growth will quickly exceed the volumes associated with the Montney non-core disposition completed in September 2023.  

During 2024, Duvernay Energy is forecasting capital expenditures of $82 million, funded by cash flow from the entity and seed capital of $40 million from Athabasca ($22 million) and Cenovus ($18 million). Duvernay Energy will also benefit from ~$20 million in expenditures related to Athabasca’s Q4 2023 drilling operations on a 100% working interest multi-well pad and long lead inventory for future activity.

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.

Athabasca Thermal Oil Budget Maintained: Athabasca’s Thermal Oil division underpins the Company’s strong free cash flow outlook, with an unchanged $135 million capital budget. At Leismer, production is expected to increase to ~28,000 bbl/d by 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. At Hangingstone, sustaining drilling will support base production in 2025 and beyond with the objective of ensuring the asset continues to deliver meaningful cash flow contributions.

Athabasca Managing for Strong Free Cash Flow: Pro forma the Transaction, Athabasca forecasts Adjusted Funds Flow of ~$460 million in 2024 (US$80/bbl WTI & US$15/bbl WCS heavy differential)¹, excluding its 70% equity interest in Duvernay Energy. The capital forecast is $135 million for Thermal Oil, a $40 million reduction in capital spending that previously included Duvernay development. The Transaction does not reduce Athabasca’s 2024 Free Cash Flow forecast which is maintained at ~$325 million. The Company’s low sustaining capital requirements are fully funded within cash flow to US$55/bbl WTI. During the timeframe of 2024 – 2026, Athabasca forecasts >$1 billion in Free Cash Flow¹, representing over 50% of its current equity market capitalization. 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.

Return of Capital Commitments Intact: Athabasca maintains its 2024 return of capital commitments outlined in its budget release on December 6, 2023. The Company intends 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 thereafter with the Toronto Stock Exchange for another 12-month period.

Financial Strength Remains: 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 is US$157 million with an estimated year-end Net Cash position of ~$155 million. The Company has ~$2.8 billion in tax pools, including ~$2.3 billion of immediately deductible non‐capital losses 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).

Differentiated Assets: Duvernay Energy’s funded growth profile complements the Company’s Thermal assets by producing a diluent quality liquid product and creating a natural hedge for diluent sourcing. The Thermal Oil division’s strong margins and Free Cash Flow are supported by a 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. Athabasca also has a fully de-risked asset at Corner which also has regulatory approval for 40,000 bbl/d with reservoir quality equivalent or better than Leismer.

Athabasca Executive Update

In conjunction with the Transaction, Athabasca is pleased to announce the appointment of Mr. Bruce Beynon as Vice President Light Oil, with primary responsibility for the development of the assets within Duvernay Energy. Mr. Beynon is a professional geologist with over 30 years of oil and gas industry experience. Mr. Beynon is currently the President of Tiburon Exploration Corp., a private consulting company. Prior thereto, Mr. Beynon was Executive Vice President, Exploration and Corporate Development at Baytex Energy Corporation. Prior to the merger between Baytex and Raging River Exploration, Mr. Beynon held several positions with Raging River including President. Mr. Mike Wojcichowsky will assume the role of Vice President, Drilling Completions Services and Light Oil Operations.

Mr. Robert Broen, President and CEO of Athabasca Oil Corporation, will also assume the role of Chairman, President and CEO of Duvernay Energy. The Board of Duvernay Energy will consist of Mr. Rob Broen, Mr. Matt Taylor, Chief Financial Officer of Athabasca, Mr. Cam Danyluk, General Counsel and Vice President Corporate Development Athabasca, and Mr. Jeff Lawson, Senior Vice-President Corporate Development, Cenovus.

Conference Call

Athabasca will be hosting a conference call for the investment community to discuss the Transaction on Tuesday, December 19, 2023 at 4:30 pm (MT).

To participate through the online webcast:

https://edge.media-server.com/mmc/p/6wqn4ts7

To participate through a dial-in conference call:

https://register.vevent.com/register/BI6d50c66745394c03aa5095a2fd470d92

An archived recording of the call will be made available on Athabasca’s website at:

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

Advisors

ATB Capital Markets is acting as financial advisor for Athabasca in connection with the Transaction. ATB Financial will lead Duvernay Energy’s new $50 million credit facility. Norton Rose Fullbright Canada LLP is acting as legal advisor for Athabasca.

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 www.atha.com.

For more information, please contact:

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, Free Cash Flow outlook, financial metrics, timing for development projects in Thermal Oil and Light Oil Divisions, return of capital strategy, royalty rates, 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 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; 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

Initial Production Rates: The 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. Liquidity is a 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.

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

A photo accompanying this announcement is available at https://www.globenewswire.com/NewsRoom/AttachmentNg/df0b2141-7be0-46b3-9e24-30b71e684834