CALGARY, Alberta, May 08, 2024 (GLOBE NEWSWIRE) — Athabasca Oil Corporation (TSX: ATH) (“Athabasca” or the “Company”) is pleased to report its first quarter results showcasing continued operational momentum and full execution of its inaugural buyback program. Production growth is underway with the commissioning of the Leismer expansion project and the tie-in of new multi-well pads in Duvernay Energy.
Athabasca Corporate Consolidated Q1 2024 Highlights
- Production: Average production of 33,470 boe/d (98% Liquids).
- Cash Flow: Adjusted Funds Flow of $88 million & Cash Flow from Operating Activities of $77 million. The Company forecasts consolidated 2024 Adjusted Funds Flow of ~$550 million1, with increasing operating scale and strong heavy oil pricing for the balance of the year.
- Balance Sheet: Net Cash of $90 million; Liquidity of $433 million (including $307 million cash).
Athabasca (Thermal Oil) Highlights
- Production: First quarter production of 31,536 bbl/d (24,143 bbl/d at Leismer & 7,393 bbl/d at Hangingstone). Leismer production is on track to reach ~28,000 bbl/d by mid-year.
- Cash Flow: Adjusted Funds Flow of $84 million with an Operating Netback of $36/bbl in the first quarter, with forecasted annual Adjusted Funds Flow of ~$500 million from the Thermal Assets.
- Capital Program: $42 million focused on completing the Leismer expansion project with facility additions commissioned in late February and new wells currently being brought onstream. Athabasca is on-track with original annual guidance of $135 million for its current Thermal program.
- Free Cash Flow: $42 million of Free Cash Flow supporting return of capital commitments. Athabasca expects to generate $1.2 billion1 in Free Cash Flow during the three-year timeframe of 2024-26.
Duvernay Energy Highlights
- Production: First quarter production of 1,934 boe/d. Production growth is expected in the second quarter with two 100% working interest (“WI”) wells on stream in late April and a three well 30% WI pad expected to be on stream late in June.
- Cash Flow and Financial Position: Adjusted Funds Flow of $4 million with an Operating Netback of $27/boe. Duvernay Energy was seeded with $40 million of cash by the equity partners and the Company has a $50 million credit facility.
- Capital Program: $34 million focused on drilling, completions and readiness activity for the future. The 2024 capital program of $82 million includes four multi-well pads supporting production momentum with volumes expected to average ~6,000 boe/d in 2025.
Return of Capital Strategy
- Full Execution of Inaugural Normal Course Issuer Bid (“NCIB”): On March 15, the Company fully completed its inaugural annual NCIB, returning $225 million to shareholders (58 million shares repurchased and cancelled for an average price of $3.88 per share).
- 2024 Return of Capital Commitment: Athabasca is allocating 100% of Free Cash Flow (not including Duvernay Energy) to share buybacks in 2024. The Company renewed its NCIB with capacity to repurchase up to 55 million shares. Year to date the Company has completed $97 million in share buybacks. The Company has reduced its fully diluted share count by 72 million shares or 11% since March 31, 2023.
Athabasca Oil – Strategic Update and Corporate Guidance
- Value Creation: Athabasca’s capital allocation framework is designed to unlock shareholder value by prioritizing multi‐year cash flow per share growth. The Company’s long life, low decline asset base provides a differentiated liquids weighted growth platform supported by financial resiliency to execute on return of capital initiatives.
- Thermal Oil Assets: Athabasca’s top-tier assets underpin a strong Free Cash Flow outlook, with a $135 million 2024 capital budget and production guidance of 32,000 – 33,000 bbl/d. Athabasca has differentiated and significant unrecovered capital balances on its Thermal Oil Assets that ensure a low Crown royalty framework (~7%1). Leismer is forecasted to remain pre-payout until 20271 (and beyond with incremental project capital) while Hangingstone is forecasted to remain pre-payout beyond 20301.
- Leismer Expansion: The facility expansion at Leismer was completed in late February with additional wells currently being brought onstream and the Company remains on track to reach ~28,000 bbl/d mid‐year.
- Leismer Growth to 40,000 bbl/d: The Company is operationally ready for progressive growth up to 40,000 bbl/d over the next three years. These growth steps are flexible and highly economic (~$25,000/bbl/d capital efficiency) and will maximize value creation when executed alongside the Company’s return of capital initiatives. Incremental capital allocation is anticipated following the ramp-up of the current expansion project and is supported by a constructive multi-year heavy oil pricing outlook.
- Hangingstone Activity: The Company is preparing to spud two ~1,400 meter well pairs in Q3 2024. Well design with extended reach laterals is expected to drive project capital efficiencies of ~$15,000/bbl/d and will leverage off available infrastructure capacity. These sustaining 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 and maintaining competitive netbacks ($35/bbl Q1 2024 Operating Netback).
- Exposure to Improving Alberta Heavy Oil Pricing: With the start-up of the Trans Mountain pipeline expansion (590,000 bbl/d) in early May, Canadian WCS heavy differentials have narrowed significantly with differentials currently reflecting ~US$11 – 13/bbl for the remainder of 2024. Every $5/bbl WCS change impacts Adjusted Funds Flow by ~$85 million annually.
- Managing for Free Cash Flow: Excluding its 70% equity interest in Duvernay Energy, Athabasca expects to generate $1.2 billion1 in Free Cash Flow during the three-year timeframe of 2024-26.
- Tax Free Horizon: As a result of its $2.6 billion in corporate tax pools, Athabasca is not forecasted to pay cash taxes for approximately seven years.
Duvernay Energy – Strategic Update and Corporate Guidance
- Value Creation: Duvernay Energy (“DEC”) is an operated, private subsidiary of Athabasca (owned 70% by Athabasca and 30% by Cenovus Energy Inc.). DEC accelerates value realization for Athabasca’s shareholders by providing a clear path for self-funded production and cash flow growth in the prolific Kaybob Duvernay resource play. This will be achieved without compromising Athabasca’s capacity to fund its Thermal Oil assets or its return of capital strategy.
- Duvernay Assets: Exposure to ~200,000 gross acres in the liquids rich and oil windows with ~500 gross future well locations, including ~46,000 acres with 100% working interest. There has been over 1,000 wells drilled in the area in the past 10 years, including many on existing DEC lands, providing for a unique low risk development outlook.
- Financial Capability: DEC was seeded with $40 million of cash by the equity partners and the company has a $50 million credit facility. The plan is to allocate 100% of Adjusted Funds Flow from DEC to drive near-term production growth.
- Capital Program: DEC recently brought on production a two well pad (100% working interest) at 03-18-64-17W5 with an average horizontal length of ~4,150 meters per well. A second three well pad at 02-03-65-20W5 (30% working interest) is expected to be placed on stream in June. The 2024 capital program of $82 million includes four multi-well pads supporting production momentum with volumes expected to average ~6,000 boe/d in 2025. The Company has self-funded growth potential to ~25,000 boe/d (75% Liquids) by the late 2020s1.
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 annual average prices of US$80 WTI, US$15 Western Canadian Select “WCS” heavy differential, C$3 AECO, and $0.73 C$/US$ FX with Q1 2024 pricing actualized. 2025-26 US$85 WTI, US$12.50 WCS heavy differential, C$3 AECO, and $0.75 C$/US$ FX.
Environmental, Social, Governance (“ESG”)
- ESG Report: Our fourth annual ESG report serves as a platform to demonstrate positive impacts to our stakeholders, explain how sustainability and responsibility are incorporated into every decision we make, and reaffirm our commitment to ESG amidst an evolving energy landscape. The report is available at https://www.atha.com/esg.html and SEDAR+ (www.sedarplus.ca).
- Environmental Targets: Athabasca continues to make strides in reducing its carbon footprint by investing in new technology and in lower GHG intensity resource developments. The Company has reduced its GHG emissions intensity by 21% since 2015 and is targeting a total 30% reduction through 2025. Growth in the low emissions intensity Duvernay shale play is expected to keep the Company on track with its targets.
- Safety is Always Our Top Priority. Our results demonstrate a robust commitment by our teams as evidenced by our 2023 total recordable injury frequency of 0.3 per 200,000 work hours, well below industry average, with no serious injuries. We are proud to report a fifth consecutive year with zero reportable hydrocarbon spills.
Annual Shareholders Meeting
- Athabasca will be hosting its Annual General and Special Meeting of Shareholders (“Meeting”) on Thursday, May 9, 2024 at 9:00 am (MT). The Meeting will be hosted virtually and shareholders and guests can listen via live webcast with details available at:
https://www.atha.com/investors/presentation-events.html
Financial and Operational Highlights
| Three months ended March 31, |
|||||||
| ($ Thousands, unless otherwise noted) | 2024 | 2023 | |||||
| CORPORATE CONSOLIDATED(1) | |||||||
| Petroleum and natural gas production (boe/d)(2) | 33,470 | 34,683 | |||||
| Petroleum, natural gas and midstream sales | $ | 311,116 | $ | 290,741 | |||
| Operating Income(2) | $ | 105,135 | $ | 56,535 | |||
| Operating Income Net of Realized Hedging(2)(3) | $ | 106,580 | $ | 34,480 | |||
| Operating Netback ($/boe)(2) | $ | 35.78 | $ | 16.85 | |||
| Operating Netback Net of Realized Hedging ($/boe)(2)(3) | $ | 36.27 | $ | 10.27 | |||
| Capital expenditures | $ | 76,011 | $ | 26,362 | |||
| Cash flow from operating activities | $ | 76,638 | $ | 20,537 | |||
| per share – basic | $ | 0.14 | $ | 0.04 | |||
| Adjusted Funds Flow(2) | $ | 87,772 | $ | (9,396 | ) | ||
| per share – basic | $ | 0.15 | $ | (0.02 | ) | ||
| ATHABASCA (THERMAL OIL) | |||||||
| Bitumen production (bbl/d)(2) | 31,536 | 29,179 | |||||
| Petroleum, natural gas and midstream sales | $ | 305,041 | $ | 269,102 | |||
| Operating Income(2) | $ | 100,449 | $ | 41,497 | |||
| Operating Netback ($/bbl)(2) | $ | 36.36 | $ | 14.52 | |||
| Capital expenditures | $ | 42,119 | $ | 24,486 | |||
| Adjusted Funds Flow(2) | $ | 83,713 | |||||
| Free Cash Flow(2) | $ | 41,594 | |||||
| DUVERNAY ENERGY(1) | |||||||
| Petroleum and natural gas production (boe/d)(2) | 1,934 | 5,504 | |||||
| Percentage Liquids (%)(2) | 72 | % | 57 | % | |||
| Petroleum, natural gas and midstream sales | $ | 11,538 | $ | 29,889 | |||
| Operating Income(2) | $ | 4,686 | $ | 15,038 | |||
| Operating Netback ($/boe)(2) | $ | 26.63 | $ | 30.35 | |||
| Capital expenditures | $ | 33,892 | $ | 1,876 | |||
| Adjusted Funds Flow(2) | $ | 4,059 | |||||
| Free Cash Flow(2) | $ | (29,833 | ) | ||||
| NET INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS) | |||||||
| Net income (loss) and comprehensive income (loss)(4) | $ | 38,609 | $ | (56,635 | ) | ||
| per share – basic(4) | $ | 0.07 | $ | (0.10 | ) | ||
| per share – diluted(4) | $ | 0.07 | $ | (0.10 | ) | ||
| COMMON SHARES OUTSTANDING | |||||||
| Weighted average shares outstanding – basic | 567,076,940 | 586,631,143 | |||||
| Weighted average shares outstanding – diluted | 577,106,504 | 586,631,143 | |||||
| March 31, | December 31, | ||||
| As at ($ Thousands) | 2024 | 2023 | |||
| LIQUIDITY AND BALANCE SHEET | |||||
| Cash and cash equivalents | $ | 306,503 | $ | 343,309 | |
| Available credit facilities(5) | $ | 126,425 | $ | 85,488 | |
| Face value of term debt(6) | $ | 212,735 | $ | 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 “Reader Advisory” section within this News Release for additional information on Non-GAAP Financial Measures and production disclosure.
(3) Includes realized commodity risk management gain of $1.4 million for the three months ended March 31, 2024 (three months ended March 31, 2023 – loss of $22.1 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.
(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 March 31, 2024 was US$157 million (December 31, 2023 – US$157 million) translated into Canadian dollars at the March 31, 2024 exchange rate of US$1.00 = C$1.3550 (December 31, 2023 – C$1.3226).
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; Leismer ramp-up to expected production rates; timing of Leismer’s pre-payout royalty status; applicability of tax pools and the timing of tax payments; expected operating results at Hangingstone; Adjusted Funds Flow and Free Cash Flow in 2024 to 2026; type well economic metrics; number of drilling locations; forecasted daily production and the composition of production; our plans to release an ESG update; our outlook in respect of the Corporation’s business environment, including in respect of the Trans Mountain pipeline expansion and new global heavy oil refining capacity; 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, 2023 (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 February 29, 2024 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; climate change and carbon pricing risk; statutes and regulations regarding the environment; regulatory environment and changes in applicable law; gathering and processing facilities, pipeline systems and rail; reputation and public perception of the oil and gas sector; environment, social and governance goals; political uncertainty; state of capital markets; ability to finance capital requirements; access to capital and insurance; abandonment and reclamation costs; changing demand for oil and natural gas products; anticipated benefits of acquisitions and dispositions; royalty regimes; foreign exchange rates and interest rates; reserves; hedging; operational dependence; operating costs; project risks; supply chain disruption; financial assurances; diluent supply; third party credit risk; indigenous claims; reliance on key personnel and operators; income tax; cybersecurity; advanced technologies; hydraulic fracturing; liability management; seasonality and weather conditions; unexpected events; internal controls; 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 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 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, 2023. 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, 2023 and based on average pricing of McDaniel, Sproule and GLJ as of January 1, 2024.
The 500 gross Duvernay drilling locations referenced include: 37 proved undeveloped locations and 76 probable undeveloped locations for a total of 113 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, 2023 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”, “Duvernay Energy Operating Income”, “Duvernay Energy Operating Netback”, “Athabasca (Thermal Oil) Operating Income”, “Athabasca (Thermal Oil) Operating Netback”, “Corporate Consolidated Operating Income”, “Corporate Consolidated Operating Netback”, ” Corporate Consolidated Operating Income Net of Realized Hedging”, ” Corporate Consolidated Operating Netback Net of Realized Hedging”, “Cash Transportation & Marketing Expense”, “Cash Financing and Interest Expense”, “Cash Stock-Based Compensation Expense” and “Realized Foreign Exchange” 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. Liquidity is a supplementary financial measure. The Leismer and Hangingstone operating results are a supplementary financial measure 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 March 31, 2024 |
Three months ended March 31, 2023 |
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| ($ Thousands) | Athabasca (Thermal Oil) |
Duvernay Energy(1) |
Corporate Consolidated(1) |
Corporate Consolidated |
|||||||||||
| Operating Income | $ | 100,449 | $ | 4,686 | $ | 105,135 | $ | 56,535 | |||||||
| Realized gain (loss) on commodity risk mgmt contracts | 1,445 | — | 1,445 | (22,055 | ) | ||||||||||
| General and administrative | (4,934 | ) | (828 | ) | (5,762 | ) | (5,747 | ) | |||||||
| Interest income | 4,207 | 283 | 4,490 | 3,270 | |||||||||||
| Cash Financing and Interest | (6,321 | ) | (82 | ) | (6,403 | ) | (6,959 | ) | |||||||
| Cash Stock-Based Compensation | (12,186 | ) | — | (12,186 | ) | (34,763 | ) | ||||||||
| Realized Foreign Exchange | 1,120 | — | 1,120 | 635 | |||||||||||
| Exploration expenses | (67 | ) | — | (67 | ) | (312 | ) | ||||||||
| ADJUSTED FUNDS FLOW | 83,713 | 4,059 | 87,772 | (9,396 | ) | ||||||||||
| Capital expenditures | (42,119 | ) | (33,892 | ) | (76,011 | ) | (26,362 | ) | |||||||
| FREE CASH FLOW | $ | 41,594 | $ | (29,833 | ) | $ | 11,761 | $ | (35,758 | ) | |||||
(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 March 31, |
|||||||
| ($ Thousands, unless otherwise noted) | 2024 | 2023 | |||||
| Petroleum and natural gas sales | $ | 11,538 | $ | 29,889 | |||
| Royalties | (2,314 | ) | (5,556 | ) | |||
| Operating expenses | (3,640 | ) | (6,929 | ) | |||
| Transportation and marketing | (898 | ) | (2,366 | ) | |||
| DUVERNAY ENERGY OPERATING INCOME | $ | 4,686 | $ | 15,038 | |||
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 boe 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 March 31, |
|||||||
| ($ Thousands, unless otherwise noted) | 2024 | 2023 | |||||
| Heavy oil (blended bitumen) and midstream sales | $ | 305,041 | $ | 269,102 | |||
| Cost of diluent | (133,860 | ) | (148,933 | ) | |||
| Total bitumen and midstream sales | 171,181 | 120,169 | |||||
| Royalties | (11,537 | ) | (6,613 | ) | |||
| Operating expenses – non-energy | (23,125 | ) | (22,940 | ) | |||
| Operating expenses – energy | (16,558 | ) | (24,829 | ) | |||
| Transportation and marketing(1) | (19,512 | ) | (24,290 | ) | |||
| ATHABASCA (THERMAL OIL) OPERATING INCOME | $ | 100,449 | $ | 41,497 | |||
(1) Transportation and marketing excludes non-cash costs of $0.6 million for the three months ended March 31, 2024 (three months ended March 31, 2023 – $0.6 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).
Cash Transportation & Marketing Expense
The Cash Transportation & Marketing Expense financial measure contained in this News Release is calculated by subtracting the non-cash Transportation & Marketing Expense as reported in the Consolidated Statement of Cash Flows from the Transportation & Marketing Expense as reported in the Consolidated Statement of Income (Loss) and is considered to be a non-GAAP financial measure.
Cash Financing and Interest Expense
The Cash Financing and Interest Expense financial measures contained in this News Release are calculated by subtracting the net non-cash financing and interest expense as reported in the Consolidated Statement of Cash Flows from the financing and interest expense as reported in the Consolidated Statement of Income (Loss) and are considered to be non-GAAP financial measures.
Cash Stock-Based Compensation Expense
The Cash Stock-Based Compensation Expense financial measures contained in this News Release are calculated by subtracting the net non-cash stock-based compensation expense as reported in the Consolidated Statement of Cash Flows from the stock-based compensation expense as reported in the Consolidated Statement of Income (Loss) and are considered to be non-GAAP financial measures.
Realized Foreign Exchange
The Realized Foreign Exchange financial measures contained in this News Release are calculated by subtracting the realized foreign exchange (gain) loss on redemption of US dollar debt as reported in the Consolidated Statement of Cash Flows from the realized foreign exchange gain (loss) as reported in Note 19 of the Consolidated Financial Statements 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 less current assets, excluding risk management contracts and warrant liability.
Liquidity
Liquidity is defined as cash and cash equivalents plus available credit capacity.
Production volumes details
| Three months ended March 31, |
|||||||
| Production | 2024 | 2023 | |||||
| Duvernay Energy: | |||||||
| Oil(1) | bbl/d | 1,205 | 1,576 | ||||
| Condensate NGLs | bbl/d | — | 814 | ||||
| Oil and condensate NGLs | bbl/d | 1,205 | 2,390 | ||||
| Other NGLs | bbl/d | 180 | 721 | ||||
| Natural gas(2) | mcf/d | 3,291 | 14,358 | ||||
| Total Duvernay Energy | boe/d | 1,934 | 5,504 | ||||
| Total Thermal Oil bitumen | bbl/d | 31,536 | 29,179 | ||||
| Total Company production | boe/d | 33,470 | 34,683 | ||||
(1) Comprised of 98% 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 32,000 – 33,000 bbl/d for 2024. Athabasca expects that 100% of that production will be comprised of bitumen. Duvernay Energy’s forecasted average daily production of ~3,000 boe/d for 2024 is expected to be comprised of approximately 66% tight oil, 24% shale gas and 10% NGLs.
Liquids is defined as bitumen, light crude oil, medium crude oil and natural gas liquids.
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