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Athabasca Oil Corporation Provides 2022 Budget Guidance

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  • ATHOF

CALGARY, Alberta, Dec. 01, 2021 (GLOBE NEWSWIRE) -- Athabasca Oil Corporation (TSX: ATH) (“Athabasca” or “the Company”) announces its 2022 budget that is focused on sustaining base production and maximizing free cash flow generation. The Company remains committed to its capital allocation priorities with near-term free cash flow directed to further significant term debt repayment. Reduced cash flow volatility, consistent operational execution and a best-in-class balance sheet is expected to unlock significant shareholder value.

2022 Budget and Guidance

Low Sustaining Capital. Athabasca is planning expenditures of ~$128 million (~$115 million Thermal Oil & ~$13 million Light Oil) with activity primarily focused on sustaining projects at Leismer, completions operations in the Duvernay and routine maintenance across the portfolio.

Resilient Production. The portfolio of long reserve life assets have a low corporate decline rate and require minimal sustaining capital. Annual 2022 production guidance of 33,000 – 34,000 boe/d (~92% liquids) is consistent with 2021 production and includes downtime associated with a planned two week turnaround at Leismer in Q2.

Thermal Oil Activity. At Leismer, production from the new Pad L8 (5 well pairs) is expected in early 2022 with production ramping up to >5,000 bbl/d in mid-2022. Two infill wells at Pad L6 and five additional well pairs at Pad L8 will commence drilling mid-2022. These wells will support production through 2023 and have Profit to Investment Ratios (NPV/Investment) of greater than 7x at current commodity prices. Leismer production is expected to exit 2022 at close to 21,000 bbl/d.

Light Oil Activity. At Kaybob, three completions on previously drilled Duvernay wells in the Two Creeks area are planned for early 2022. The wells are expected to be placed on-stream before spring break-up. Wells in this area have demonstrated compelling results with the last 12 wells averaging IP180’s of ~725 boe/d (85% liquids) and IP365’s of ~550 boe/d (83% liquids). The Light Oil division continues to demonstrate top decile industry netbacks and will contribute significant cash flow to the Company. Future development opportunities are substantial, with ~150 well locations in Placid Montney and ~700 well locations in Kaybob Duvernay. The Company has minimal near-term land expiries.

Balance Sheet and Risk Management

Managing for Strong Free Cash Flow. In 2022, the Company anticipates generating ~$300 million of Adjusted EBITDA (~$250 million of Adjusted Funds Flow) and ~$125 million of Free Cash Flow (US$70 WTI & US$13.50 Western Canadian Select “WCS” Heavy Differentials). Athabasca forecasts >$600 million in Free Cash Flow during the 3 year timeframe of 2022-24 (US$70 WTI & US$12.50 WCS differentials flat pricing). The Company has ~$3.2 billion in tax pools, including ~$2.4 billion of immediately deductible non-capital loses and exploration pools.

Clear Debt Reduction Targets. The Company will direct at least 75% of future free cash flow to reducing its term debt. Athabasca is targeting total outstanding term debt of US$175 million (50% reduction), expected to be reached in 2023. The first debt repayment will commence in May 2022 (for the period Q4 2021 – Q1 2022). The Company expects to be in a net cash position in 2023 and has no term debt maturities until Q4 2026.

Ample Liquidity Bolstered by an Increased LC Facility. The Company is completing the annual renewal of its unsecured letter of credit facility with ATB Capital Markets and has confirmed an increase of $10 million to $50 million. The facility renewal is expected be completed in early December and is supported by a performance security guarantee from Export Development Canada. Year-end 2021 corporate Liquidity is estimated at ~$290 million, including ~$210 million of cash.

Risk Management. The Company’s hedge program is designed to protect its entire capital program down to US$50 WTI while retaining significant exposure to higher commodity prices. The Company’s current 2022 hedges equate to ~50% of sales volumes and include 13,500 bbl/d of fixed WCS swaps at ~US$54 (~US$67.50 WTI assuming a US$13.50 WCS differential) and ~9,750 bbl/d of WTI collars with an average floor of US$50 WTI and an average ceiling of US$96 WTI.

Commitment to ESG. Athabasca is committed to ESG initiatives by employing technology through its capital program to lower overall emissions. This includes drilling longer lateral wells, installing flow control devices upon completion and the application of non-condensable gas injection to lower SOR’s. The Company also plans to progress its partnership with Entropy Inc. to explore the application of Carbon Capture and Sequestration at Leismer.

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:

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”, “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 2021 and 2022 capital, production and financial guidance, 2022-24 free cash flow outlook, financial metrics including Profit to Investment ratios for Thermal Oil sustaining wells, key strategic priorities 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, EBITDA 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, 2020 (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 3, 2021 and Management’s Discussion and Analysis dated November 3, 2021, available on SEDAR at www.sedar.com, 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 2021 and 2022 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 700 Duvernay (Greater Kaybob) drilling locations referenced include: 7 proved undeveloped locations and 78 probable undeveloped locations for a total of 85 booked locations with the balance being unbooked locations. The 150 Montney drilling (Greater Placid) locations referenced include: 63 proved undeveloped locations and 35 probable undeveloped locations for a total of 98 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, 2020 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 Financial Measures and Production Disclosure

The "Adjusted Funds Flow”, “Adjusted EBITDA” and “Free Cash Flow” 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 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. The “Advisories and Other Guidance” section within the Company’s Q3 2021 MD&A includes reconciliations of these measures, where applicable, to the nearest IFRS measures.

Adjusted Funds Flow is not intended to represent cash flow from operating activities, net earnings or other measures of financial performance calculated in accordance with IFRS. Adjusted Funds Flow is calculated by adjusting for changes in non‐cash working capital, restructuring expenses and settlement of provisions from cash flow from operating activities. The Adjusted Funds Flow measure allows management and others to evaluate the Company’s ability to fund its capital programs and meet its ongoing financial obligations using cash flow internally generated from ongoing operating related activities. Adjusted Funds Flow per share is calculated as Adjusted Funds Flow divided by the applicable number of weighted average shares outstanding.

Adjusted EBITDA is defined as Net income (loss) and comprehensive income (loss) before financing and interest expense, depreciation, depletion, impairment and taxation (recovery) expense adjusted for unrealized foreign exchange gain (loss), unrealized gain (loss) on risk management contracts, gain (loss) on revaluation of provisions and other, gain (loss) on sale of assets and non‐cash stock‐based compensation.

The Free Cash Flow measure in this News Release is calculated by subtracting Capital Expenditures from Adjusted Funds Flow. This measure allows management and others to evaluate Athabasca's ability to generate funds to finance operations and capital expenditures.

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 of 34,500 boe/d for 2021. Athabasca expects that approximately 78% of that production will be comprised of bitumen, 10% shale gas, 6% tight oil, 4% condensate natural gas liquids and 2% other natural gas liquids.

This News Release also makes reference to Athabasca's forecasted total average daily production between 33,000 -34,000 boe/d for 2022. Athabasca expects that approximately 82% of that production will be comprised of bitumen, 8% shale gas, 5% tight oil, 3% condensate natural gas liquids and 2% other natural gas liquids.

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

Additionally, this News Release makes reference to Athabasca's well results in Two Creeks and Kaybob East that have seen average productivity of ~725 boe/d IP180s (85% Liquids), which is comprised of ~80% tight oil, ~15% shale gas and ~5% NGLs, and ~550 boe/d (83% Liquids) IP365s, which is comprised of ~78% tight oil, ~17% shale gas and ~5% NGLs.


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