CALGARY, Alberta, Feb. 29, 2024 (GLOBE NEWSWIRE) â Athabasca Oil Corporation (TSX: ATH) (âAthabascaâ or the âCompanyâ) is pleased to report its audited 2023 year-end results and reserves. Athabasca provides investors unique positioning to top tier liquids weighted assets (Thermal Oil and Duvernay) with a capital allocation framework aimed at maximizing cash flow per share growth and returning capital to shareholders.
Year-end 2023 Corporate Results
- Production:Â Average production of 34,490 boe/d (95% Liquids), achieving annual guidance of 34,500 boe/d, after adjusting for the sale of non-core Light Oil assets.
- Cash Flow:Â Adjusted Funds Flow of $295 million & Cash Flow from Operating Activities of $306 million.
- Capital Program:Â $140 million, below annual guidance of $145 million, with $99 million invested at its cornerstone Leismer asset focused on advancing the expansion project with growth expected to 28,000 bbl/d by mid-year 2024.
- Free Cash Flow:Â $155 million of Free Cash Flow supporting return of capital commitments.
- Financial Strength:Â Net Cash position of $131 million; Liquidity of $429 million ($343 million of cash).
Return of Capital Strategy
- 2023 Share Buybacks:Â $159 million of share repurchases between April and December (44 million shares at an average price of $3.58/share); returned 94% of Excess Cash Flow to shareholders through share buyback program, well in excess of Athabascaâs 75% commitment in 2023.
- 2024 Return of Capital Commitment:Â Â Athabasca is planning to allocate of 100% of Free Cash Flow to shareholders through continued share buybacks in 2024. Year to date the Company has completed ~$24 million of share repurchases (5.4 million shares at an average price of $4.38/share). The Company expects to fully execute its Normal Course Issuer Bid (âNCIBâ) approval of 57,967,098 common shares for the 12 month period ending March 15, 2024. The Company plans to renew its NCIB with the Toronto Stock Exchange for another 12 month period.
2023 Year-end Reserves
- Differentiated Long-life Reserves:Â Athabasca holds 1.2 billion barrels of Proved Plus Probable reserves and ~1 billion barrels of Contingent Resource (Best Estimate). This represents $5.3 billion2Â NPV10 of Proved Plus Probable reserves ($9.23 per share), an increase of 14% from 2023, and includes $1.8 billion2Â of Proved Developed Producing reserves ($3.09 per share) and $3.1 billion2Â of Total Proved reserves ($5.44 per share). Athabascaâs Proved plus Probable reserve life is ~100 years.
- Deep Inventory of Development Projects:Â Leismer and Corner have regulatory approval for up to 80,000 bbl/d and benefit from a pre-payout Crown royalty structure, with royalty rates between 5 â 9%. The Company also has exposure to an estimated 500 gross Kaybob Duvernay locations through its subsidiary, Duvernay Energy Corporation.
2024 Guidance
- Thermal Oil:Â Athabascaâs Thermal Oil division underpins the Companyâs strong Free Cash Flow outlook, with an unchanged $135 million capital budget and production guidance of 32,000 â 33,000 bbl/d. The facility expansion at Leismer is on track to be commissioned during H1 2024 with production expected to reach ~28,000 bbl/d midâyear following the tieâin of behind pipe wells. Two 1,400 meter well pairs are planned to be drilled at Hangingstone in H2 2024 with the objective of ensuring the project continues to deliver meaningful cash flow to the Company.
- Duvernay Energy Corporation:Â The 2024 capital program of ~$82 million (gross) includes the drilling of 12 gross (7.1 net) Duvernay wells. Capital will be funded through cash balances and cash flow from operations. 2024 production guidance is ~3,000 boe/d (75% Liquids). Development plans are expected to drive strong production momentum into 2025 with estimated production of ~6,000 boe/d.
- Managing for Free Cash Flow:Â Excluding its 70% equity interest in Duvernay Energy, Athabasca forecasts Adjusted Funds Flow of ~$460 million in 2024 (US$80/bbl WTI & US$15/bbl WCS heavy differential). Athabascaâs 2024 Free Cash Flow forecast is ~$325 million. The Company expects to generate >$1 billion in Free Cash Flow during the three-year timeframe of 2024-26. As a result of its $2.8 billion in corporate tax pools, Athabasca is not forecasted to pay cash taxes for approximately seven years.
- Exposure to Improving Alberta Heavy Oil Pricing:Â Athabasca anticipates tightening of the WCS heavy differentials from current levels as the Trans Mountain Expansion pipeline (590,000 bbl/d) commences operations in Q2 2024. Every $5/bbl WTI change impacts Adjusted Funds Flow by ~$55 million annually and every $5/bbl WCS change impacts Adjusted Funds Flow by ~$85 million annually.
- Environmental, Social and Governance âESGâ Disclosure:Â The Company will release its annual ESG update in May of 2024. In 2023, the Company maintained a strong safety record with a 0.31 Total Recordable Injury Frequency and no reportable hydrocarbon spills.
Footnote: Refer to the âReader Advisoryâ section within this news release for additional information on NonâGAAP Financial Measures (e.g. Adjusted Funds Flow, Free Cash Flow, Excess Cash Flow, Sustaining Capital, Net Cash, Liquidity) and production disclosure.
1Â Pricing Assumptions: 2024Â US$80Â WTI, US$15Â Western Canadian Select âWCSâ heavy differential, C$3Â AECO, and $0.75 C$/US$ FX. 2025-26Â US$85 WTI, US$12.50 WCS heavy differential, C$3Â AECO, and $0.75 C$/US$ FX.
2 Net present value of future net revenue before tax at a 10% discount rate (NPV 10 before tax) for 2024 is based on an average of McDaniel, Sproule and GLJ pricing as at January 1, 2024.
Thermal Oil â Operations Update
Bitumen production for Q4 2023 and 2023 averaged 31,059 bbl/d and 30,246 bbl/d, respectively. The Thermal Oil division generated Operating Income of $92.2 million ($30.78/bbl) and $370.7 million ($32.93/bbl) during these periods. Capital expenditures for Q4 2023 and 2023 were $29.3 million and $113.1 million, respectively.
Leismer
Bitumen production for Q4 2023 and 2023 averaged 23,764 bbl/d (up 9% year over year) and 22,497 bbl/d (up 12% year over year), respectively. Current production is in excess of 24,000 bbl/d (February 2024). The asset realized continued improvement in the Steam Oil Ratio (âSORâ) from expansion of the non-condensable gas co-injection and production additions from new wells resulting in an annual average SOR of 3.1 for 2023.
In 2023, five additional new well pairs at Pad L8 were brought on production mid-year. These well pairs have a combined production rate of ~5,000 bbl/d and are expected to maintain a stable production profile for approximately five years. The Company also completed drilling the final four well pairs at Pad L8S with steaming currently underway and recently placed four infill wells on production at Pad L7.
The facility expansion is on track to be commissioned in H1 and production is expected to reach ~28,000 bbl/d mid-year once all new wells are on production.
Leismer has a significant unrecovered capital balance of $1.4 billion which ensures a low Crown royalty framework as the asset is forecasted to remain pre-payout until 20271.
Hangingstone
Bitumen production for Q4 2023 and 2023 averaged 7,295 bbl/d and 7,749 bbl/d, respectively. Non-condensable gas co-injection has aided in pressure support and reduced energy usage. Hangingstoneâs steam oil ratio averaged 3.6 for 2023.
Two ~1,400 meter well pairs will spud in Q3 2024. Modern well design with extended reach laterals is expected to drive competitive 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.
Duvernay Energy Corporation â Operations Update
Production from Athabascaâs Light Oil Division averaged 2,068 boe/d (71% Liquids) and 4,244 boe/d (58% Liquids) in Q4 2023 and 2023, respectively. These assets generated Operating Income of $4.8 million ($25.02/boe) and $46.3 million ($29.89/boe) during these periods. Capital expenditures were $9.4 million and $20.9 million in Q4 2023 and 2023, respectively.
In September 2023, Athabasca closed the sale of ~3,000 boe/d of non-core Placid, Saxon and Simonette assets for $160 million (before closing adjustments). In December, the Company announced the creation of Duvernay Energy Corporation. Duvernay Energy is a privately held subsidiary of Athabasca, combining Athabasca and Cenovus assets. Athabasca owns 70% equity interest with Cenovus owning the remaining 30% equity interest. Duvernay Energy is managed by Athabasca through a management and operating services agreement.
Duvernay Energy owns ~46,000 acres of 100% working interest operated lands contiguous to its existing Duvernay joint venture assets. In total, Duvernay Energy has exposure to ~200,000 gross contiguous acres in the liquids rich and oil windows with a management estimate of ~500 gross future well locations. Duvernayâs initial capitalization includes ~$40 million cash and a $50 million undrawn credit facility. The plan is to allocate 100% of Adjusted Funds Flow from Duvernay Energy to drive near-term growth potential.
Duvernay Energy recently rig released a two well pad (100% working interest) at 03-18-64-17W5 with an average horizontal length of ~4,150 meters per well. Completion operations are planned for Q1 2024 with on-stream timing at the end of Q2 2024. A three well pad (30% working interest) is currently drilling with completions and tie-in to follow in Q2 2024.
Duvernay Energyâs assets are positioned in the prolific Kaybob Duvernay resource play, primarily in the volatile oil window, and are serviced by extensive operated infrastructure. Current production is ~2,000 boe/d (~75% Liquids). Assuming a constructive commodity price outlook, Duvernay Energy has self-funded growth potential to ~25,000 boe/d (75% Liquids) by the late 2020âs.
Financial and Operational Highlights
| Three months ended December 31, |
Year ended December 31, |
||||||||||||||
| ($ Thousands, unless otherwise noted) | 2023 | 2022 | 2023 | 2022 | |||||||||||
| CONSOLIDATED | |||||||||||||||
| Petroleum and natural gas production (boe/d)(1) | 33,127 | 35,850 | 34,490 | 35,262 | |||||||||||
| Petroleum, natural gas and midstream sales | $ | 315,929 | $ | 282,524 | $ | 1,268,525 | $ | 1,504,685 | |||||||
| Operating Income (Loss)(1) | $ | 96,960 | $ | 70,319 | $ | 417,023 | $ | 530,295 | |||||||
| Operating Income (Loss) Net of Realized Hedging(1)(2) | $ | 91,443 | $ | 62,131 | $ | 381,088 | $ | 378,695 | |||||||
| Operating Netback ($/boe)(1) | $ | 30.44 | $ | 23.17 | $ | 32.57 | $ | 41.65 | |||||||
| Operating Netback Net of Realized Hedging ($/boe)(1)(2) | $ | 28.71 | $ | 20.47 | $ | 29.76 | $ | 29.74 | |||||||
| Capital expenditures | $ | 38,752 | $ | 13,029 | $ | 139,832 | $ | 147,449 | |||||||
| THERMAL OIL DIVISION | |||||||||||||||
| Bitumen production (bbl/d)(1) | 31,059 | 30,210 | 30,246 | 28,989 | |||||||||||
| Petroleum, natural gas and midstream sales | $ | 309,078 | $ | 255,749 | $ | 1,204,245 | $ | 1,382,627 | |||||||
| Operating Income (Loss)(1) | $ | 92,199 | $ | 50,691 | $ | 370,732 | $ | 420,511 | |||||||
| Operating Netback ($/bbl)(1) | $ | 30.78 | $ | 20.15 | $ | 32.93 | $ | 40.26 | |||||||
| Capital expenditures | $ | 29,260 | $ | 10,895 | $ | 113,077 | $ | 110,582 | |||||||
| LIGHT OIL DIVISION | |||||||||||||||
| Petroleum and natural gas production (boe/d)(1) | 2,068 | 5,640 | 4,244 | 6,273 | |||||||||||
| Percentage Liquids (%)(1) | 71 | % | 56 | % | 58 | % | 57 | % | |||||||
| Petroleum, natural gas and midstream sales | $ | 12,659 | $ | 36,356 | $ | 91,062 | $ | 175,279 | |||||||
| Operating Income (Loss)(1) | $ | 4,761 | $ | 19,628 | $ | 46,291 | $ | 109,784 | |||||||
| Operating Netback ($/boe)(1) | $ | 25.02 | $ | 37.83 | $ | 29.89 | $ | 47.95 | |||||||
| Capital expenditures | $ | 9,381 | $ | 1,594 | $ | 20,857 | $ | 11,662 | |||||||
| CASH FLOW AND FUNDS FLOW | |||||||||||||||
| Cash flow from operating activities | $ | 103,196 | $ | 69,368 | $ | 305,526 | $ | 315,618 | |||||||
| per share â basic | $ | 0.18 | $ | 0.12 | $ | 0.52 | $ | 0.56 | |||||||
| Adjusted Funds Flow(1) | $ | 81,830 | $ | 46,074 | $ | 295,236 | $ | 308,004 | |||||||
| per share â basic | $ | 0.14 | $ | 0.08 | $ | 0.51 | $ | 0.54 | |||||||
| Free Cash Flow(1) | $ | 43,078 | $ | 33,045 | $ | 155,404 | $ | 160,555 | |||||||
| NET INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS) | |||||||||||||||
| Net income (loss) and comprehensive income (loss) | $ | 27,506 | $ | 489,654 | $ | (51,220 | ) | $ | 572,271 | ||||||
| per share â basic | $ | 0.05 | $ | 0.83 | $ | (0.09 | ) | $ | 1.01 | ||||||
| per share â diluted(3) | $ | 0.03 | $ | 0.81 | $ | (0.09 | ) | $ | 0.98 | ||||||
| COMMON SHARES OUTSTANDING | |||||||||||||||
| Weighted average shares outstanding â basic | 574,412,564 | 586,468,394 | 583,757,575 | 568,035,589 | |||||||||||
| Weighted average shares outstanding â diluted | 588,498,448 | 604,911,603 | 583,757,575 | 586,913,328 | |||||||||||
| December 31, | December 31, | |||||||
| As at ($ Thousands) | 2023 | 2022 | ||||||
| LIQUIDITY AND BALANCE SHEET | ||||||||
| Cash and cash equivalents | $ | 343,309 | $ | 197,525 | ||||
| Available credit facilities(4) | $ | 85,488 | $ | 87,838 | ||||
| Face value of term debt(5) | $ | 207,648 | $ | 237,231 | ||||
(1)Â Refer to the âReader Advisoryâ section within this News Release for additional information on Non-GAAP Financial Measures and production disclosure.
(2)Â Includes realized commodity risk management loss of $5.5 million and $35.9 million for the three months and year ended December 31, 2023 (the three months and year ended December 31, 2022 â loss of $8.2 million and $151.6 million).
(3)Â In the calculation of diluted earnings per share for the three months ended December 31, 2023 earnings were reduced by $11.3 million to account for the impact to net income had the outstanding warrants been converted to equity.
(4)Â Includes available credit under Athabascaâs Credit Facility and Unsecured Letter of Credit Facility.
(5)Â The face value of the term debt at December 31, 2023 was US$157 million (December 31, 2022 â US$175 million) translated into Canadian dollars at the December 31, 2023 exchange rate of US$1.00 = C$1.3226 (December 31, 2022 â C$1.3544).
Differentiated Long-life Reserves
Athabascaâs independent reserves evaluator, McDaniel & Associates Consultants Ltd. (âMcDanielâ), prepared the year-end reserves evaluation effective December 31, 2023.
The Companyâs Proved plus Probable (â2Pâ) reserves base is 1.2 billion boe, with Leismer/Corner underpinning an additional ~1 billion barrels of low risk, top tier, long reserve life contingent resources (best estimate). Light Oil reserves saw a decrease with the disposition of Placid and Saxon assets in 2023. The Light Oil reserve report includes 113 future booked development locations relative to a deep inventory of ~500 gross estimated development locations. Overall reserve value (NPV 10 before tax) of 2P reserves increased 14% year over year, including an increase of 26% from Athabascaâs Thermal Oil assets. Athabascaâs Proved plus Probable reserve life index is approximately 100 years.
For additional information regarding Athabascaâs reserves and resources estimates, please see âIndependent Reserve and Resource Evaluationsâ in the Companyâs 2023 Annual Information Form which is available on the Companyâs website or on SEDAR www.sedarplus.ca.
| Light Oil | Thermal Oil | Corporate | ||||||||||
| 2022 | 2023 | 2022 | 2023 | 2022 | 2023 | |||||||
| Reserves (mmboe) | ||||||||||||
| Proved Developed Producing | 12 | 4 | 66 | 77 | 78 | 82 | ||||||
| Total Proved | 29 | 11 | 403 | 404 | 433 | 415 | ||||||
| Proved Plus Probable | 70 | 27 | 1,220 | 1,216 | 1,290 | 1,243 | ||||||
| NPV10 BT ($million)1 | ||||||||||||
| Proved Developed Producing | $ | 191 | $ | 58 | $ | 1,201 | $ | 1,713 | $ | 1,393 | $ | 1,771 |
| Total Proved | $ | 317 | $ | 142 | $ | 2,384 | $ | 2,969 | $ | 2,702 | $ | 3,111 |
| Proved Plus Probable | $ | 642 | $ | 269 | $ | 3,985 | $ | 5,011 | $ | 4,627 | $ | 5,280 |
1) Net present value of future net revenue before tax and at a 10% discount rate (NPV 10 before tax) for 2023 is based on an average of McDaniel, Sproule and GLJ pricing as at January 1, 2024.
2) Numbers in the table may not add precisely due to rounding.
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 Albertaâs Western Canadian Sedimentary Basin, the Company has amassed a significant land base of extensive, high quality resources. Athabascaâs light oil assets are held in a private subsidiary (Duvernay Energy Corporation) in which Athabasca owns a 70% equity interest. Athabascaâs common shares trade on the TSX under the symbol âATHâ. For more information, visit www.atha.com.
For more information, please contact:
Reader Advisory:
This News Release contains forward-looking information that involves various risks, uncertainties and other factors. All information other than statements of historical fact is forward-looking information. The use of any of the words âanticipateâ, âplanâ, âprojectâ, âcontinueâ, âmaintainâ, âmayâ, âestimateâ, âexpectâ, âwillâ, âtargetâ, âforecastâ, âcouldâ, âintendâ, âpotentialâ, âguidanceâ, âoutlookâ 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 Companyâs current plans, objectives, goals, strategies, estimates, assumptions and projections about the Companyâs 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 in Leismer; Leismer ramp-up to expected production rates; timing of Leismerâs 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; forecasted daily production and the composition of production; the reclassification of reserves from Proved Undeveloped to Proved Developed Producing; our plans to release an ESG update; our outlook in respect of the Corporationâs 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 âReservesâ and âResourcesâ 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 Companyâs financial condition and results of operations; the Companyâs financial and operational flexibility; the Companyâs financial sustainability; Athabascaâs cash flow break-even commodity price; the Companyâs 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 Companyâs reserves and resources; future capital expenditures to be made by the Company; future sources of funding for the Companyâs capital programs; the Companyâs future debt levels; future production levels; the Companyâs 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 Companyâs 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 Companyâs Reserves and Resources are contained in the report of McDaniel & Associates Consultants Ltd. (âMcDanielâ) evaluating Athabascaâs Proved Reserves, Probable Reserves and Contingent Resources as at December 31, 2023 (which is respectively referred to herein as the âMcDaniel Reportâ).
Actual results could differ materially from those anticipated in this forward-looking information as a result of the risk factors set forth in the Companyâs Annual Information Form (âAIFâ) 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 Athabascaâs 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 Companyâs 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
âBOEsâ 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 RatesÂ
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 Companyâs 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 Companyâs 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 Companyâs 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 Athabascaâs 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 âAdjusted Funds Flowâ, âAdjusted Funds Flow per Shareâ, âFree Cash Flowâ, âLight Oil Operating Incomeâ, âLight Oil Operating Netbackâ, âThermal Oil Operating Incomeâ, âThermal Oil Operating Netbackâ, âConsolidated Operating Incomeâ, âConsolidated Operating Netbackâ, âConsolidated Operating Income Net of Realized Hedgingâ, âConsolidated Operating Netback Net of Realized Hedgingâ, âCash Transportation & Marketing Expensesâ, âExcess Cash Flowâ and âSustaining Capitalâ 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 Thermal Oil segment results and the Greater Placid and Greater Kaybob operating results are a supplementary financial measure that when aggregated, combine to the Light 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 Companyâs 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 December 31, |
Year ended December 31, |
|||||||||||
| ($ Thousands) | 2023 | 2022 | 2023 | 2022 | ||||||||
| Cash flow from operating activities | $ | 103,196 | $ | 69,368 | $ | 305,526 | $ | 315,618 | ||||
| Changes in non-cash working capital | (21,973 | ) | (23,356 | ) | 525 | (8,970 | ) | |||||
| Settlement of provisions | 607 | 62 | 1,762 | 1,356 | ||||||||
| Long-term deposit | â | â | (12,577 | ) | â | |||||||
| ADJUSTED FUNDS FLOW | 81,830 | 46,074 | 295,236 | 308,004 | ||||||||
| Capital expenditures | (38,752 | ) | (13,029 | ) | (139,832 | ) | (147,449 | ) | ||||
| FREE CASH FLOW | $ | 43,078 | $ | 33,045 | $ | 155,404 | $ | 160,555 | ||||
Light Oil Operating Income and Operating Netback
The non-GAAP measure Light Oil Operating Income in this News Release is calculated by subtracting the Light Oil Segments royalties, operating expenses and transportation & marketing expenses from petroleum and natural gas sales which is the most directly comparable GAAP measure. The Light Oil Operating Netback per boe is a non-GAAP financial ratio calculated by dividing the Light Oil Operating Income by the Light Oil production. The Light Oil Operating Income and the Light Oil Operating Netback measures allow management and others to evaluate the production results from the Companyâs Light Oil assets. The Light Oil Operating Income is calculated using the Light Oil Segments GAAP results, as follows:
| Three months ended December 31, |
Year ended December 31, |
|||||||||||
| ($ Thousands) | 2023 | 2022 | 2023 | 2022 | ||||||||
| Petroleum and natural gas sales | $ | 12,659 | $ | 36,356 | $ | 91,062 | $ | 175,279 | ||||
| Royalties | (2,180 | ) | (6,701 | ) | (12,583 | ) | (25,608 | ) | ||||
| Operating expenses | (5,009 | ) | (7,791 | ) | (24,997 | ) | (30,689 | ) | ||||
| Transportation and marketing | (709 | ) | (2,236 | ) | (7,191 | ) | (9,198 | ) | ||||
| LIGHT OIL OPERATING INCOME | $ | 4,761 | $ | 19,628 | $ | 46,291 | $ | 109,784 | ||||
Thermal Oil Operating Income and Operating Netback
The non-GAAP measure Thermal Oil Operating Income in this News Release is calculated by subtracting the 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 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 Thermal Oil Operating Income and the Thermal Oil Operating Netback measures allow management and others to evaluate the production results from the Companyâs Thermal Oil assets. The Thermal Oil Operating Income is calculated using the Thermal Oil Segments GAAP results, as follows:
| Three months ended December 31, |
Year ended December 31, |
|||||||||||
| ($ Thousands, unless otherwise noted) | 2023 | 2022 | 2023 | 2022 | ||||||||
| Heavy oil (blended bitumen) and midstream sales | $ | 309,078 | $ | 255,749 | $ | 1,204,245 | $ | 1,382,627 | ||||
| Cost of diluent | (137,438 | ) | (128,713 | ) | (518,219 | ) | (548,553 | ) | ||||
| Total bitumen and midstream sales | 171,640 | 127,036 | 686,026 | 834,074 | ||||||||
| Royalties | (15,695 | ) | (13,256 | ) | (60,865 | ) | (133,134 | ) | ||||
| Operating expenses â non-energy | (23,767 | ) | (17,062 | ) | (87,116 | ) | (81,319 | ) | ||||
| Operating expenses â energy | (17,651 | ) | (25,914 | ) | (81,769 | ) | (114,622 | ) | ||||
| Transportation and marketing(1) | (22,328 | ) | (20,113 | ) | (85,544 | ) | (84,488 | ) | ||||
| THERMAL OIL OPERATING INCOME | $ | 92,199 | $ | 50,691 | $ | 370,732 | $ | 420,511 | ||||
(1)Â Cash transportation and marketing excludes non-cash costs of $0.6 million and $2.2 million for the three months and year ended December 31, 2023 (three months and year ended December 31, 2022 â $0.6 million and $2.2 million).
Consolidated Operating Income and Consolidated Operating Income Net of Realized Hedging and Operating Netbacks
The non-GAAP measures of Consolidated Operating Income including or excluding realized hedging in this News Release are calculated by adding or subtracting realized gains (losses) on commodity risk management contracts (as applicable), royalties, the cost of diluent blending, operating expenses and cash transportation & marketing expenses from petroleum, natural gas and midstream sales which is the most directly comparable GAAP measure. The Consolidated Operating Netbacks including or excluding realized hedging per boe are non-GAAP ratios calculated by dividing Consolidated Operating Income including or excluding hedging by the total sales volumes and are presented on a per boe basis. The Consolidated Operating Income and Consolidated Operating Netbacks including or excluding realized hedging measures allow management and others to evaluate the production results from the Companyâs Light Oil and Thermal Oil assets combined together including the impact of realized commodity risk management gains or losses (as applicable).
| Three months ended December 31, |
Year ended December 31, |
|||||||||||
| ($ Thousands, unless otherwise noted) | 2023 | 2022 | 2023 | 2022 | ||||||||
| Petroleum, natural gas and midstream sales(1) | $ | 321,737 | $ | 292,105 | $ | 1,295,307 | $ | 1,557,906 | ||||
| Royalties | (17,875 | ) | (19,957 | ) | (73,448 | ) | (158,742 | ) | ||||
| Cost of diluent(1) | (137,438 | ) | (128,713 | ) | (518,219 | ) | (548,553 | ) | ||||
| Operating expenses | (46,427 | ) | (50,767 | ) | (193,882 | ) | (226,630 | ) | ||||
| Transportation and marketing(2) | (23,037 | ) | (22,349 | ) | (92,735 | ) | (93,686 | ) | ||||
| Operating Income (Loss) | 96,960 | 70,319 | 417,023 | 530,295 | ||||||||
| Realized gain (loss) on commodity risk management contracts | (5,517 | ) | (8,188 | ) | (35,935 | ) | (151,600 | ) | ||||
| OPERATING INCOME NET OF REALIZED HEDGING | $ | 91,443 | $ | 62,131 | $ | 381,088 | $ | 378,695 | ||||
(1)Â Non-GAAP measure includes intercompany NGLs (i.e. condensate) sold by the Light Oil segment to the Thermal Oil segment for use as diluent that is eliminated on consolidation.
(2)Â Cash transportation and marketing excludes non-cash costs of $0.6 million and $2.2 million for the three months and year ended December 31, 2023 (the three months and year ended December 31, 2022 â $0.6 million and $2.2 million).
Cash Transportation & Marketing ExpensesÂ
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.
Excess Cash Flow and Sustaining Capital
The Excess Cash Flow and Sustaining Capital measures allow management and others to evaluate the Companyâs ability to return capital to Shareholders. Sustaining Capital is managements assumption of the required capital to maintain the Companyâs production base. The Excess Cash Flow measure is calculated by Adjusted Funds Flow less Sustaining Capital.
Net Cash / Net Debt
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 December 31, |
Year ended December 31, |
||||||||||||
| Production | 2023 | 2022 | 2023 | 2022 | |||||||||
| Greater Placid: | |||||||||||||
| Condensate NGLs | bbl/d | â | 843 | 528 | 962 | ||||||||
| Other NGLs | bbl/d | â | 360 | 256 | 411 | ||||||||
| Natural gas(1) | mcf/d | â | 10,259 | 6,720 | 11,149 | ||||||||
| Total Greater Placid | boe/d | â | 2,913 | 1,904 | 3,232 | ||||||||
| Greater Kaybob: | |||||||||||||
| Oil(2) | bbl/d | 1,208 | 1,707 | 1,396 | 1,886 | ||||||||
| Other NGLs | bbl/d | 258 | 266 | 269 | 319 | ||||||||
| Natural gas(1) | mcf/d | 3,612 | 4,526 | 4,049 | 5,020 | ||||||||
| Total Greater Kaybob | boe/d | 2,068 | 2,727 | 2,340 | 3,041 | ||||||||
| Light Oil: | |||||||||||||
| Oil(2) | bbl/d | 1,208 | 1,707 | 1,396 | 1,886 | ||||||||
| Condensate NGLs | bbl/d | â | 843 | 528 | 962 | ||||||||
| Oil and condensate NGLs | bbl/d | 1,208 | 2,550 | 1,924 | 2,848 | ||||||||
| Other NGLs | bbl/d | 258 | 626 | 525 | 730 | ||||||||
| Natural gas(1) | mcf/d | 3,612 | 14,785 | 10,769 | 16,169 | ||||||||
| Total Light Oil division | boe/d | 2,068 | 5,640 | 4,244 | 6,273 | ||||||||
| Total Thermal Oil division bitumen | bbl/d | 31,059 | 30,210 | 30,246 | 28,989 | ||||||||
| Total Company production | boe/d | 33,127 | 35,850 | 34,490 | 35,262 | ||||||||
(1)Â Comprised of 99% or greater of shale gas, with the remaining being conventional natural gas.
(2)Â Comprised of 98% or greater of tight oil, with the remaining being light and medium crude oil.
This News Release also makes reference to Athabascaâs forecasted average daily Thermal Oil production of 32,000 â 33,000 bbl/d for 2024. Athabasca expects that 100% of that production will be comprised of bitumen. Duvernay Energyâs 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.
Reserve Life Index is calculated as year-end reserves divided by Q4 2023 production.
Footnote: Refer to the âReader Advisoryâ section within this news release for additional information on NonâGAAP Financial Measures (e.g. Adjusted Funds Flow, Free Cash Flow, Excess Cash Flow, Sustaining Capital, Net Cash, Liquidity) and production disclosure.
1 Pricing Assumptions: 2024 US$80 WTI, US$15 Western Canadian Select âWCSâ heavy differential, C$3 AECO, and $0.75 C$/US$ FX. 2025-26 US$85 WTI, US$12.50 WCS heavy differential, C$3 AECO, and $0.75 C$/US$ FX.
2Â Net present value of future net revenue before tax at a 10% discount rate (NPV 10 before tax) for 2024 is based on an average of McDaniel, Sproule and GLJ pricing as at January 1, 2024.
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