Athabasca Oil Announces 2024 Third Quarter Results Highlighted by Strong Free Cash Flow and Continued Execution on Share Buybacks
CALGARY, Alberta, Oct. 30, 2024 (GLOBE NEWSWIRE) — Athabasca Oil Corporation (TSX: ATH) (“Athabasca” or the “Company”) is pleased to report its third quarter results highlighting strong free cash flow underpinned by operational momentum at all assets and continued execution on its return of capital commitment through share buybacks.
Corporate Consolidated Third Quarter Highlights
- Production: Average production of 38,909 boe/d (98% Liquids), representing 8% growth year over year (16% on a per share basis). Annual production remains on track with previously increased 2024 guidance of 36,000 – 37,000 boe/d.
- Cash Flow Growth: Adjusted Funds Flow of $164 million (cash flow from operating activities of $187 million) or $0.30 per share, representing 25% growth on a per share basis year over year. In 2024, the Company forecasts Adjusted Funds Flow of ~$555 million1, supported by increased operating scale and constructive Canadian heavy oil pricing. Athabasca forecasts ~100% growth in 2024 forecasted funds flow per share relative to 2022 when growth to 28,000 bbl/d at Leismer was sanctioned.
- Differentiated Balance Sheet: Proactively refinanced the Company’s senior secured second lien Notes with $200 million of senior unsecured notes at a 6.75% coupon with a 2029 maturity. Consolidated Net Cash position of $135 million with Liquidity of $456 million, including $335 million in cash.
- Resilient Producer: Competitively positioned with Thermal Oil sustaining capital to hold production flat funded within cash flow at ~US$50/bbl WTI1 and growth initiatives fully funded within cash flow at ~US$60/bbl WTI1.
- Robust Free Cash Flow: Capital flexibility and balance sheet strength supports durable asset growth and return of capital initiatives for shareholders, resulting in continued top tier cash flow per share growth into the future. Athabasca expects to generate in excess of $1 billion of Free Cash Flow at US$70/bbl WTI1 after fully funding its growth program during the timeframe of 2024-27. The Company intends to release its 2025 capital budget in December.
Return of Capital
- Cumulative Return of Capital of ~$800 million. Commencing in the Fall of 2021 a deliberate strategy prioritized $385 million of debt reduction. Share buybacks commenced in 2023 and have totaled $415 million to date.
- 2024 Return of Capital Commitment: Athabasca (Thermal Oil) is allocating 100% of Free Cash Flow to share buybacks in 2024. Year to date the Company has completed $257 million in share buybacks and forecasts 2024 Free Cash Flow of ~$315 million1.
- Focus on Per Share Metrics: A steadfast commitment to return of capital has driven an ~104 million share reduction (~16%) in the Company’s fully diluted share count since March 31, 2023.
Athabasca (Thermal Oil) Third Quarter Highlights
- Production: ~34,900 bbl/d supported by growth at Leismer (record quarter at ~27,500 bbl/d) and stability at Hangingstone (~7,400 bbl/d).
- Cash Flow: Adjusted Funds Flow of $150 million with an Operating Netback of $49.68/bbl.
- Capital Program: $44 million of capital focused on sustaining operations at Leismer and Hangingstone. 2024 capital program forecast of ~$195 million including the commencement of progressive growth to 40,000 bbl/d at Leismer. The Company is currently drilling four new well pairs and six redrill opportunities at Leismer with production expected in early 2025. Two new well pairs at Hangingstone (1,400 meter laterals) will begin steaming in late November with production expected in early 2025.
- Free Cash Flow: $106 million of Free Cash Flow supporting return of capital commitments.
Duvernay Energy Corporation (“DEC”) Third Quarter Highlights
- Production: ~4,100 boe/d (77% Liquids) supported by production from two new pads placed on production in the spring. Results continue to support management’s type curve expectations with restricted IP180s/well averaging ~840 boe/d (82% Liquids) on the 2-well 100% working interest (“WI”) pad and IP120s/well averaging ~835 boe/d (85% Liquids) on the 3-well 30% WI pad.
- Cash Flow: Adjusted Funds Flow of $14 million with an Operating Netback of $44.20/boe.
- Capital Program: $6 million focused on commencing a 3-well 100% WI pad at 04-18-64-16W5 which spud in early September. The first two wells have been cased with lateral lengths averaging ~4,000 meters per well. The pad is expected to be completed in 2025. The 2024 capital program forecast is ~$75 million, fully funded within cash flow and cash on hand in DEC.
Corporate Consolidated Strategy
- Value Creation: The Company’s Thermal Oil division provides a differentiated liquids weighted growth platform supported by financial resiliency to execute on return of capital initiatives. Athabasca’s subsidiary company, Duvernay Energy Corporation, is designed to enhance value for Athabasca’s shareholders by providing a clear path for self-funded production and cash flow growth in the Kaybob Duvernay resource play. Athabasca (Thermal Oil) and Duvernay Energy have independent strategies and capital allocation frameworks.
- Consolidated Free Cash Flow Growth: Athabasca’s capital allocation framework is designed to unlock shareholder value by prioritizing multi‐year cash flow per share growth. In 2024, Athabasca forecasts Corporate Consolidated Adjusted Funds Flow of ~$555 million or ~$1 per share, representing ~100% per share growth over 2022 when the Company sanctioned growth to 28,000 bbl/d at Leismer. The Company’s outlook targets ~20% net Adjusted Funds Flow per share compound annual growth rate during the three-year time to 20272.
Athabasca (Thermal Oil) Strategy
- Large Resource Base: Athabasca’s top-tier assets underpin a strong Free Cash Flow outlook with low sustaining capital requirements. The long life, low decline asset base includes ~1.2 billion barrels of Proved plus Probable reserves and ~1 billion barrels of Contingent Resource.
- Strong Financial Position: Prudent balance sheet management is a core tenet of Athabasca’s strategy. During the quarter, Athabasca issued $200 million 6.75% senior unsecured notes due in 2029 and redeemed US$157 million 9.75% senior secured second lien notes due in 2026. The Company proactively refinanced its debt on attractive terms and maintains strategic flexibility with a Net Cash position.
- Capital Efficient Leismer Expansions: As previously announced, the Company has sanctioned expansion plans at Leismer for growth to 40,000 bbl/d. This will be completed utilizing a progressive build strategy that adds incremental production in the coming years with the full capacity to be achieved in 2028. The capital for this project is estimated at $300 million for a capital efficiency of ~$25,000/bbl/d. The Company can maintain 40,000 bbl/d for approximately fifty years (Proved plus Probable Reserves).
- Sustaining Hangingstone: Steaming on two new sustaining well pairs will occur later this year with first production expected in early 2025. These wells will support base production with the objective of ensuring Hangingstone continues to deliver meaningful cash flow contributions to the Company and maintaining competitive netbacks ($48.39/bbl Q3 2024 Operating Netback).
- Corner – Future Optionality: The Company’s Corner asset is a large de-risked oil sands asset adjacent to Leismer with 351 million barrels of Proved plus Probable reserves and 520 million barrels Contingent Resource (Best Estimate Unrisked). There are over 300 delineation wells and ~80% seismic coverage, with reservoir qualities similar or better than Leismer. The asset has a 40,000 bbl/d regulatory approval for development with the existing pipeline corridor passing through the Corner lease. The Company has updated its development plans and is finalizing facility cost estimates. Athabasca intends to explore external funding options and does not plan to fund an expansion utilizing existing cash flow or balance sheet resources.
- Exposure to Improving Heavy Oil Pricing: With the start-up of the Trans Mountain pipeline expansion (590,000 bbl/d) in early May, spare pipeline capacity is driving tighter and less volatile WCS heavy differentials. Regional liquids pricing benchmarks have also been supported by a depreciating Canadian currency relative to the United States. Every US$5/bbl WCS change impacts Athabasca (Thermal Oil) Adjusted Funds Flow by ~$85 million annually.
- Significant Multi-Year Free Cash Flow: Inclusive of the progressive growth at Leismer, Athabasca (Thermal Oil) expects to generate in excess of $1 billion of Free Cash Flow at US$70 WTI1 during the timeframe of 2024-27. Free Cash Flow will continue to support the Company’s return of capital initiatives.
- Thermal Oil Royalty Advantage: Athabasca has significant unrecovered capital balances on its Thermal Oil Assets that ensure a low Crown royalty framework (~6%1). Leismer is forecasted to remain pre-payout until late 20271 and Hangingstone is forecasted to remain pre-payout beyond 20301.
- Tax Free Horizon Advantage: Athabasca (Thermal Oil) has $2.4 billion of valuable tax pools and does not forecast paying cash taxes this decade.
Duvernay Energy Strategy
- Accelerating Value: DEC is an operated, private subsidiary of Athabasca (owned 70% by Athabasca and 30% by Cenovus Energy). DEC accelerates value realization for Athabasca’s shareholders by providing a clear path for self-funded production and cash flow growth without compromising Athabasca’s capacity to fund its Thermal Oil assets or its return of capital strategy.
- Kaybob Duvernay Focused: Exposure to ~200,000 gross acres in the liquids rich and oil windows with ~500 gross future well locations, including ~46,000 gross acres with 100% working interest.
- Self-Funded Growth: Current activity is being funded within cash flow and cash on hand. The 2024 program includes drilling and completions of a two-well 100% WI pad and a three-well 30% WI pad along with the spudding an additional multi-well pad in September 2024. The Company has self-funded growth potential to in excess of ~20,000 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, Sustaining Capital, Net Cash, Liquidity) and production disclosure.
1 Pricing Assumptions: realized prices January – October and flat pricing of US$70 WTI, US$12.50 WCS heavy differential, C$2 AECO, and 0.73 C$/US$ FX for the balance of 2024. 2025-27 US$70 WTI, US$12.50 WCS heavy differential, C$3.00 AECO, and 0.75 C$/US$ FX.
2 The Company’s illustrative multi-year outlook assumes a 10% annual share buyback program at an implied share price of 4.5x EV/Debt Adjusted Cash flow in 2025 and beyond.
Financial and Operational Highlights
| Three months ended September 30, | Nine months ended September 30, | |||||||||||||||
| ($ Thousands, unless otherwise noted) | 2024 | 2023 | 2024 | 2023 | ||||||||||||
| CORPORATE CONSOLIDATED(1) | ||||||||||||||||
| Petroleum and natural gas production (boe/d)(2) | 38,909 | 36,176 | 36,675 | 34,950 | ||||||||||||
| Petroleum, natural gas and midstream sales | $ | 376,781 | $ | 379,241 | $ | 1,089,635 | $ | 952,596 | ||||||||
| Operating Income(2) | $ | 180,184 | $ | 168,410 | $ | 465,070 | $ | 320,063 | ||||||||
| Operating Income Net of Realized Hedging(2)(3) | $ | 175,755 | $ | 164,643 | $ | 460,511 | $ | 289,645 | ||||||||
| Operating Netback ($/boe)(2) | $ | 49.12 | $ | 50.84 | $ | 46.36 | $ | 33.27 | ||||||||
| Operating Netback Net of Realized Hedging ($/boe)(2)(3) | $ | 47.91 | $ | 49.70 | $ | 45.91 | $ | 30.11 | ||||||||
| Capital expenditures | $ | 50,634 | $ | 33,286 | $ | 175,098 | $ | 101,080 | ||||||||
| Cash flow from operating activities | $ | 187,143 | $ | 134,879 | $ | 398,864 | $ | 202,330 | ||||||||
| per share – basic | $ | 0.35 | $ | 0.23 | $ | 0.72 | $ | 0.34 | ||||||||
| Adjusted Funds Flow(2) | $ | 163,680 | $ | 141,138 | $ | 417,198 | $ | 213,406 | ||||||||
| per share – basic | $ | 0.30 | $ | 0.24 | $ | 0.75 | $ | 0.36 | ||||||||
| ATHABASCA (THERMAL OIL) | ||||||||||||||||
| Bitumen production (bbl/d)(2) | 34,853 | 31,691 | 33,390 | 29,972 | ||||||||||||
| Petroleum, natural gas and midstream sales | $ | 372,634 | $ | 360,761 | $ | 1,072,954 | $ | 895,167 | ||||||||
| Operating Income(2) | $ | 163,694 | $ | 155,415 | $ | 425,837 | $ | 278,533 | ||||||||
| Operating Netback ($/bbl)(2) | $ | 49.68 | $ | 53.59 | $ | 46.64 | $ | 33.72 | ||||||||
| Capital expenditures | $ | 44,431 | $ | 34,439 | $ | 120,634 | $ | 89,604 | ||||||||
| Adjusted Funds Flow(2) | $ | 150,088 | $ | 383,214 | ||||||||||||
| Free Cash Flow(2) | $ | 105,657 | $ | 262,580 | ||||||||||||
| DUVERNAY ENERGY(1) | ||||||||||||||||
| Petroleum and natural gas production (boe/d)(2) | 4,056 | 4,485 | 3,285 | 4,978 | ||||||||||||
| Percentage Liquids (%)(2) | 77 | % | 55 | % | 77 | % | 56 | % | ||||||||
| Petroleum, natural gas and midstream sales | $ | 24,728 | $ | 24,508 | $ | 63,015 | $ | 78,403 | ||||||||
| Operating Income(2) | $ | 16,490 | $ | 12,995 | $ | 39,233 | $ | 41,530 | ||||||||
| Operating Netback ($/boe)(2) | $ | 44.20 | $ | 31.50 | $ | 43.59 | $ | 30.56 | ||||||||
| Capital expenditures | $ | 6,203 | $ | (1,153 | ) | $ | 54,464 | $ | 11,476 | |||||||
| Adjusted Funds Flow(2) | $ | 13,592 | $ | 33,984 | ||||||||||||
| Free Cash Flow(2) | $ | 7,389 | $ | (20,480 | ) | |||||||||||
| NET INCOME AND COMPREHENSIVE INCOME | ||||||||||||||||
| Net income and comprehensive income(4) | $ | 68,722 | $ | (79,212 | ) | $ | 203,407 | $ | (78,726 | ) | ||||||
| per share – basic(4) | $ | 0.13 | $ | (0.14 | ) | $ | 0.37 | $ | (0.13 | ) | ||||||
| per share – diluted(4) | $ | 0.12 | $ | (0.14 | ) | $ | 0.36 | $ | (0.13 | ) | ||||||
| COMMON SHARES OUTSTANDING | ||||||||||||||||
| Weighted average shares outstanding – basic | 540,884,257 | 581,917,255 | 555,035,218 | 586,906,810 | ||||||||||||
| Weighted average shares outstanding – diluted | 550,712,443 | 581,917,255 | 559,203,568 | 586,906,810 | ||||||||||||
| September 30 | December 31 | |||||||
| As at ($ Thousands) | 2024 | 2023 | ||||||
| LIQUIDITY AND BALANCE SHEET | ||||||||
| Cash and cash equivalents | $ | 334,851 | $ | 343,309 | ||||
| Available credit facilities(5) | $ | 121,316 | $ | 85,488 | ||||
| Face value of term debt(6) | $ | 200,000 | $ | 207,648 | ||||
(1) Corporate Consolidated and Duvernay Energy reflect gross production and financial metrics before taking into consideration Athabasca’s 70% equity interest in Duvernay Energy.
(2) Refer to the “Reader Advisory” section within this News Release for additional information on Non-GAAP Financial Measures and production disclosure.
(3) Includes realized commodity risk management loss of $4.4 million and $4.6 million for the three and nine months ended September 30, 2024 (three and nine months ended September 30, 2023 – loss of $3.8 million and $30.4 million).
(4) Net income (loss) and comprehensive income (loss) per share amounts are based on net income (loss) and comprehensive income (loss) attributable to shareholders of the Parent Company. In the calculation of diluted net income (loss) per share for the three months ended September 30, 2024 net income (loss) was reduced by $2.6 million to account for the impact to net income (loss) had the outstanding warrants been converted to equity.
(5) Includes available credit under Athabasca’s and Duvernay Energy’s Credit Facilities and Athabasca’s Unsecured Letter of Credit Facility.
(6) The face value of the term debt at December 31, 2023 was US$157.0 million translated into Canadian dollars at the December 31, 2023 exchange rate of US$1.00 = C$1.3226.
Operations Update
Athabasca (Thermal Oil)
Production for the third quarter of 2024 averaged 34,853 bbl/d. The Thermal Oil division generated Operating Income of $164 million (Operating Netbacks – $50.05/bbl at the Leismer and $48.39/bbl at Hangingstone) during the period with capital expenditures of $44 million, primarily related to drilling and completions, and progressing future growth initiatives at Leismer.
Leismer
Leismer produced a record 27,485 bbl/d during the quarter following the completion of the facility expansion. The Company is continuing with progressive growth to increase Leismer production to 40,000 bbl/d (regulatory approved capacity) over the next three years. These capital projects 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. Activity over the next three years will include drilling ~20 well pairs (sustaining and growth wells), expanding steam capacity to ~130,000 bbl/d and adding oil processing capacity at the central processing facility. The project will benefit from installing opportunistically pre-purchased steam generators which reduce the timelines and costs for the project.
Activity in H2 2024 includes drilling four sustaining well pairs at Pad L10 and six extended redrills on Pad L1, with production expected in early 2025.
Hangingstone
Production during the quarter averaged 7,368 bbl/d. Non-condensable gas co-injection continues to assist in pressure support, reduced energy usage and an improved SOR averaging ~3.4x year to date. During the quarter the Company rig released two ~1,400 meter well pairs with first steam planned for later this year and production in early 2025. Well design with extended reach laterals is expected to drive project capital efficiencies of ~$15,000/bbl/d and will leverage off available plant and infrastructure capacity. These sustaining well pairs will support base production with the objective of ensuring Hangingstone continues to deliver meaningful cash flow contributions to the Company and maintaining competitive netbacks.
Duvernay Energy
Production for the third quarter of 2024 averaged 4,056 boe/d (77% Liquids). Duvernay Energy generated Operating Income of $16 million (Operating Netback – $44.20/boe) during the period.
Duvernay Energy brought its two-well 100% working interest pad at 03-18-64-17W5 on production in late April. The pad generated an average restricted 180-day rate of ~840 boe/d per well (82% liquids). A three well pad (30% working interest) at 02-03-65-20W5 was brought on production in late May, with an approximate 120-day rate of ~835 boe/d per well (85% liquids). Both pads are performing in-line with management’s expectations and are exhibiting strong extended results with high liquids content. The Company spud a three-well 100% working interest pad at 4-18-64-16W5 in September. Two wells have been cased on this pad with average laterals of ~4,000 meters per well. The operated pad of wells is expected to be completed in 2025.
About Athabasca Oil Corporation
Athabasca Oil Corporation is a Canadian energy company with a focused strategy on the development of thermal and light oil assets. Situated in Alberta’s Western Canadian Sedimentary Basin, the Company has amassed a significant land base of extensive, high quality resources. Athabasca’s light oil assets are held in a private subsidiary (Duvernay Energy Corporation) in which Athabasca owns a 70% equity interest. Athabasca’s common shares trade on the TSX under the symbol “ATH”. For more information, visit www.atha.com.
For more information, please contact:
| Matthew Taylor | Robert Broen |
| Chief Financial Officer | President and CEO |
| 1-403-817-9104 | 1-403-817-9190 |
| mtaylor@atha.com | rbroen@atha.com |
Reader Advisory:
This News Release contains forward-looking information that involves various risks, uncertainties and other factors. All information other than statements of historical fact is forward-looking information. The use of any of the words “anticipate”, “plan”, “project”, “continue”, “maintain”, “may”, “estimate”, “expect”, “will”, “target”, “forecast”, “could”, “intend”, “potential”, “guidance”, “outlook” and similar expressions suggesting future outcome are intended to identify forward-looking information. The forward-looking information is not historical fact, but rather is based on the Company’s current plans, objectives, goals, strategies, estimates, assumptions and projections about the Company’s industry, business and future operating and financial results. This information involves known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking information. No assurance can be given that these expectations will prove to be correct and such forward-looking information included in this News Release should not be unduly relied upon. This information speaks only as of the date of this News Release. In particular, this News Release contains forward-looking information pertaining to, but not limited to, the following: our strategic plans; the allocation of future capital; timing and quantum for shareholder returns including share buybacks; the terms of our NCIB program; our drilling plans and capital efficiencies; production growth to expected production rates and estimated sustaining capital amounts; timing of Leismer’s and Hangingstone’s pre-payout royalty status; applicability of tax pools and the timing of tax payments; expected operating results at Hangingstone; Adjusted Funds Flow and Free Cash Flow in 2024 and 2025 to 2027; type well economic metrics; number of drilling locations; forecasted daily production and the composition of production; our outlook in respect of the Company’s business environment, including in respect of the Trans Mountain pipeline expansion and heavy oil pricing; and other matters.
In addition, information and statements in this News Release relating to “Reserves” and “Resources” are deemed to be forward-looking information, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves and resources described exist in the quantities predicted or estimated, and that the reserves and resources described can be profitably produced in the future. With respect to forward-looking information contained in this News Release, assumptions have been made regarding, among other things: commodity prices; the regulatory framework governing royalties, taxes and environmental matters in the jurisdictions in which the Company conducts and will conduct business and the effects that such regulatory framework will have on the Company, including on the Company’s financial condition and results of operations; the Company’s financial and operational flexibility; the Company’s financial sustainability; Athabasca’s cash flow break-even commodity price; the Company’s ability to obtain qualified staff and equipment in a timely and cost-efficient manner; the applicability of technologies for the recovery and production of the Company’s reserves and resources; future capital expenditures to be made by the Company; future sources of funding for the Company’s capital programs; the Company’s future debt levels; future production levels; the Company’s ability to obtain financing and/or enter into joint venture arrangements, on acceptable terms; operating costs; compliance of counterparties with the terms of contractual arrangements; impact of increasing competition globally; collection risk of outstanding accounts receivable from third parties; geological and engineering estimates in respect of the Company’s reserves and resources; recoverability of reserves and resources; the geography of the areas in which the Company is conducting exploration and development activities and the quality of its assets. Certain other assumptions related to the Company’s Reserves and Resources are contained in the report of McDaniel & Associates Consultants Ltd. (“McDaniel”) evaluating Athabasca’s Proved Reserves, Probable Reserves and Contingent Resources as at December 31, 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 including deceptive marketing provisions; regulatory environment and changes in applicable law; gathering and processing facilities, pipeline systems and rail; reputation and public perception of the oil and gas sector; environment, social and governance goals; political uncertainty; state of capital markets; ability to finance capital requirements; access to capital and insurance; abandonment and reclamation costs; changing demand for oil and natural gas products; anticipated benefits of acquisitions and dispositions; royalty regimes; foreign exchange rates and interest rates; reserves; hedging; operational dependence; operating costs; project risks; supply chain disruption; financial assurances; diluent supply; third party credit risk; indigenous claims; reliance on key personnel and operators; income tax; cybersecurity; advanced technologies; hydraulic fracturing; liability management; seasonality and weather conditions; unexpected events; internal controls; limitations and insurance; litigation; natural gas overlying bitumen resources; competition; chain of title and expiration of licenses and leases; breaches of confidentiality; new industry related activities or new geographical areas; water use restrictions and/or limited access to water; relationship with Duvernay Energy Corporation; management estimates and assumptions; third-party claims; conflicts of interest; inflation and cost management; credit ratings; growth management; impact of pandemics; ability of investors resident in the United States to enforce civil remedies in Canada; and risks related to our debt and securities. All subsequent forward-looking information, whether written or oral, attributable to the Company or persons acting on its behalf are expressly qualified in their entirety by these cautionary statements.
Also included in this News Release are estimates of Athabasca’s 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”, “Corporate Consolidated Operating Income”, “Corporate Consolidated Operating Income Net of Realized Hedging”, “Athabasca (Thermal Oil) Operating Income”, “Duvernay Energy Operating Income”, “Corporate Consolidated Operating Netback”, “Corporate Consolidated Operating Netback Net of Realized Hedging”, “Athabasca (Thermal Oil) Operating Netback”, “Duvernay Energy Operating Netback” and “Cash Transportation and Marketing Expense” financial measures contained in this News Release do not have standardized meanings which are prescribed by IFRS and they are considered to be non-GAAP financial measures or ratios. These measures may not be comparable to similar measures presented by other issuers and should not be considered in isolation with measures that are prepared in accordance with IFRS. Sustaining Capital, Net Cash and Liquidity are supplementary financial measures. The Leismer and Hangingstone operating results are supplementary financial measures that when aggregated, combine to the Athabasca (Thermal Oil) segment results.
Adjusted Funds Flow, Adjusted Funds Flow Per Share and Free Cash Flow
Adjusted Funds Flow and Free Cash Flow are non-GAAP financial measures and are not intended to represent cash flow from operating activities, net earnings or other measures of financial performance calculated in accordance with IFRS. The Adjusted Funds Flow and Free Cash Flow measures allow management and others to evaluate the Company’s ability to fund its capital programs and meet its ongoing financial obligations using cash flow internally generated from ongoing operating related activities. Adjusted Funds Flow per share is a non-GAAP financial ratio calculated as Adjusted Funds Flow divided by the applicable number of weighted average shares outstanding. Adjusted Funds Flow and Free Cash Flow are calculated as follows:
| Three months ended September 30, 2024 | Three months ended September 30, 2023 | |||||||||||
| ($ Thousands) | Athabasca (Thermal Oil) | Duvernay Energy(1) | Corporate Consolidated(1) | Corporate Consolidated | ||||||||
| Cash flow from operating activities | $ | 169,950 | $ | 17,193 | $ | 187,143 | $ | 134,879 | ||||
| Changes in non-cash working capital | (20,201 | ) | (3,401 | ) | (23,602 | ) | 5,898 | |||||
| Settlement of provisions | 339 | (200 | ) | 139 | 361 | |||||||
| ADJUSTED FUNDS FLOW | 150,088 | 13,592 | 163,680 | 141,138 | ||||||||
| Capital expenditures | (44,431 | ) | (6,203 | ) | (50,634 | ) | (33,286 | ) | ||||
| FREE CASH FLOW | $ | 105,657 | $ | 7,389 | $ | 113,046 | $ | 107,852 | ||||
(1) Duvernay Energy and Corporate Consolidated reflect gross financial metrics before taking into consideration Athabasca’s 70% equity interest in Duvernay Energy.
| Nine months ended September 30, 2024 | Nine months ended September 30, 2023 | |||||||||||
| ($ Thousands) | Athabasca (Thermal Oil) | Duvernay Energy(1) | Corporate Consolidated(1) | Corporate Consolidated | ||||||||
| Cash flow from operating activities | $ | 367,018 | $ | 31,846 | $ | 398,864 | $ | 202,330 | ||||
| Changes in non-cash working capital | 14,560 | 2,134 | 16,694 | 22,498 | ||||||||
| Settlement of provisions | 1,636 | 4 | 1,640 | 1,155 | ||||||||
| Long-term deposit | — | — | — | (12,577 | ) | |||||||
| ADJUSTED FUNDS FLOW | 383,214 | 33,984 | 417,198 | 213,406 | ||||||||
| Capital expenditures | (120,634 | ) | (54,464 | ) | (175,098 | ) | (101,080 | ) | ||||
| FREE CASH FLOW | $ | 262,580 | $ | (20,480 | ) | $ | 242,100 | $ | 112,326 | |||
(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 September 30, | Nine months ended September 30, | |||||||||||
| ($ Thousands, unless otherwise noted) | 2024 | 2023 | 2024 | 2023 | ||||||||
| Petroleum and natural gas sales | $ | 24,728 | $ | 24,508 | $ | 63,015 | $ | 78,403 | ||||
| Royalties | (2,470 | ) | (3,510 | ) | (8,282 | ) | (10,403 | ) | ||||
| Operating expenses | (4,684 | ) | (5,964 | ) | (12,387 | ) | (19,988 | ) | ||||
| Transportation and marketing | (1,084 | ) | (2,039 | ) | (3,113 | ) | (6,482 | ) | ||||
| DUVERNAY ENERGY OPERATING INCOME | $ | 16,490 | $ | 12,995 | $ | 39,233 | $ | 41,530 | ||||
Athabasca (Thermal Oil) Operating Income and Operating Netback
The non-GAAP measure Athabasca (Thermal Oil) Operating Income in this News Release is calculated by subtracting the Athabasca (Thermal Oil) segments cost of diluent blending, royalties, operating expenses and cash transportation & marketing expenses from heavy oil (blended bitumen) and midstream sales which is the most directly comparable GAAP measure. The Athabasca (Thermal Oil) Operating Netback per bbl is a non-GAAP financial ratio calculated by dividing the respective projects Operating Income by its respective bitumen sales volumes. The Athabasca (Thermal Oil) Operating Income and the Athabasca (Thermal Oil) Operating Netback measures allow management and others to evaluate the production results from the Athabasca (Thermal Oil) assets. The Athabasca (Thermal Oil) Operating Income is calculated using the Athabasca (Thermal Oil) Segments GAAP results, as follows:
| Three months ended September 30, | Nine months ended September 30, | |||||||||||
| ($ Thousands) | 2024 | 2023 | 2024 | 2023 | ||||||||
| Heavy oil (blended bitumen) and midstream sales | $ | 372,634 | $ | 360,761 | $ | 1,072,954 | $ | 895,167 | ||||
| Cost of diluent | (129,965 | ) | (117,418 | ) | (411,991 | ) | (380,781 | ) | ||||
| Total bitumen and midstream sales | 242,669 | 243,343 | 660,963 | 514,386 | ||||||||
| Royalties | (22,291 | ) | (27,613 | ) | (62,651 | ) | (45,170 | ) | ||||
| Operating expenses – non-energy | (24,903 | ) | (19,521 | ) | (72,445 | ) | (63,349 | ) | ||||
| Operating expenses – energy | (9,994 | ) | (20,572 | ) | (38,187 | ) | (64,118 | ) | ||||
| Transportation and marketing(1) | (21,787 | ) | (20,222 | ) | (61,843 | ) | (63,216 | ) | ||||
| ATHABASCA (THERMAL OIL) OPERATING INCOME | $ | 163,694 | $ | 155,415 | $ | 425,837 | $ | 278,533 | ||||
(1) Transportation and marketing excludes non-cash costs of $0.6 million and $1.7 million for the three and nine months ended September 30, 2024 (three and nine months ended September 30, 2023 – $0.6 million and $1.7 million).
Corporate Consolidated Operating Income and Corporate Consolidated Operating Income Net of Realized Hedging and Operating Netbacks
The non-GAAP measures of Corporate Consolidated Operating Income including or excluding realized hedging in this News Release are calculated by adding or subtracting realized gains (losses) on commodity risk management contracts (as applicable), royalties, the cost of diluent blending, operating expenses and cash transportation & marketing expenses from petroleum, natural gas and midstream sales which is the most directly comparable GAAP measure. The Corporate Consolidated Operating Netbacks including or excluding realized hedging per boe are non-GAAP ratios calculated by dividing Corporate Consolidated Operating Income including or excluding hedging by the total sales volumes and are presented on a per boe basis. The Corporate Consolidated Operating Income and Corporate Consolidated Operating Netbacks including or excluding realized hedging measures allow management and others to evaluate the production results from the Company’s Duvernay Energy and Athabasca (Thermal Oil) assets combined together including the impact of realized commodity risk management gains or losses (as applicable).
| Three months ended September 30, | Nine months ended September 30, | |||||||||||
| ($ Thousands) | 2024 | 2023 | 2024 | 2023 | ||||||||
| Petroleum, natural gas and midstream sales(1) | $ | 397,362 | $ | 385,269 | $ | 1,135,969 | $ | 973,570 | ||||
| Royalties | (24,761 | ) | (31,123 | ) | (70,933 | ) | (55,573 | ) | ||||
| Cost of diluent(1) | (129,965 | ) | (117,418 | ) | (411,991 | ) | (380,781 | ) | ||||
| Operating expenses | (39,581 | ) | (46,057 | ) | (123,019 | ) | (147,455 | ) | ||||
| Transportation and marketing(2) | (22,871 | ) | (22,261 | ) | (64,956 | ) | (69,698 | ) | ||||
| Operating Income | 180,184 | 168,410 | 465,070 | 320,063 | ||||||||
| Realized loss on commodity risk mgmt. contracts | (4,429 | ) | (3,767 | ) | (4,559 | ) | (30,418 | ) | ||||
| OPERATING INCOME NET OF REALIZED HEDGING | $ | 175,755 | $ | 164,643 | $ | 460,511 | $ | 289,645 | ||||
(1) Non-GAAP measure includes intercompany NGLs (i.e. condensate) sold by the Duvernay Energy segment to the Athabasca (Thermal Oil) segment for use as diluent that is eliminated on consolidation.
(2) Transportation and marketing excludes non-cash costs of $0.6 million and $1.7 million for the three and nine months ended September 30, 2024 (three and nine months ended September 30, 2023 – $0.6 million and $1.7 million).
Cash Transportation and Marketing Expense
The Cash Transportation and Marketing Expense financial measures contained in this News Release are calculated by subtracting the non-cash transportation and marketing expense as reported in the Consolidated Statement of Cash Flows from the transportation and marketing expense as reported in the Consolidated Statement of Income (Loss) and are considered to be non-GAAP financial measures.
Sustaining Capital
Sustaining Capital is managements’ assumption of the required capital to maintain the Company’s production base.
Net Cash
Net Cash is defined as the face value of term debt, plus accounts payable and accrued liabilities, plus current portion of provisions and other liabilities plus income tax payable less current assets, excluding risk management contracts.
Liquidity
Liquidity is defined as cash and cash equivalents plus available credit capacity.
Production volumes details
| Three months ended September 30, | Nine months ended September 30, | ||||||||||
| Production | 2024 | 2023 | 2024 | 2023 | |||||||
| Duvernay Energy: | |||||||||||
| Oil(1) | bbl/d | 2,688 | 1,398 | 2,235 | 1,461 | ||||||
| Condensate NGLs | bbl/d | — | 581 | — | 705 | ||||||
| Oil and condensate NGLs | bbl/d | 2,688 | 1,979 | 2,235 | 2,166 | ||||||
| Other NGLs | bbl/d | 447 | 528 | 298 | 615 | ||||||
| Natural gas(2) | mcf/d | 5,526 | 11,869 | 4,511 | 13,181 | ||||||
| Total Duvernay Energy | boe/d | 4,056 | 4,485 | 3,285 | 4,978 | ||||||
| Total Thermal Oil bitumen | bbl/d | 34,853 | 31,691 | 33,390 | 29,972 | ||||||
| Total Company production | boe/d | 38,909 | 36,176 | 36,675 | 34,950 | ||||||
(1) Comprised of 99% or greater of tight oil, with the remaining being light and medium crude oil.
(2) Comprised of 99% or greater of shale gas, with the remaining being conventional natural gas.
This News Release also makes reference to Athabasca’s forecasted average daily Thermal Oil production of 33,000 – 34,000 bbl/d for 2024. Athabasca expects that 100% of that production will be comprised of bitumen. Duvernay Energy’s forecasted total average daily production of ~3,000 boe/d for 2024 is expected to be comprised of approximately 67% tight oil, 23% shale gas and 10% NGLs.
Liquids is defined as bitumen, light crude oil, medium crude oil and natural gas liquids.
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, Sustaining Capital, Net Cash, Liquidity) and production disclosure.
1 Pricing Assumptions: realized prices January – October and flat pricing of US$70 WTI, US$12.50 WCS heavy differential, C$2 AECO, and 0.73 C$/US$ FX for the balance of 2024. 2025-27 US$70 WTI, US$12.50 WCS heavy differential, C$3.00 AECO, and 0.75 C$/US$ FX.
2 The Company’s illustrative multi-year outlook assumes a 10% annual share buyback program at an implied share price of 4.5x EV/Debt Adjusted Cash flow in 2025 and beyond.
