Calgary, Alberta--(Newsfile Corp. - February 23, 2026) - Cardinal Energy Ltd. (TSX: CJ) ("Cardinal" or the "Company") is pleased to present the results of its independent reserve reports effective December 31, 2025. Consistent with prior years, Cardinal's year-end 2025 non-thermal reserves were evaluated by GLJ Ltd. ("GLJ"). The thermal reserves were independently evaluated by McDaniel & Associates Consultants Ltd. ("McDaniel") (the GLJ report and the McDaniel report being collectively the "2025 Reserve Report").
The 2025 financial information in this news release is unaudited and accordingly, such financial information is subject to change based on the results of the Company's year-end audit.
Cardinal's 2025 year-end reserves reflect the quality, predictability, and sustainability of our low decline conventional asset base which is now being supplemented and enhanced by the growing recognition of reserves and value from the Company's first operational thermal heavy oil development at Reford, Saskatchewan ("Reford 1").
Scott Ratushny, Cardinal's Chairman and CEO commented, "2025 was an exciting year of transition for Cardinal. The significant up-front facility investment for Reford 1 that was reflected in last year's reserve report is now behind us, and we can now look forward to decades of predictable free cash flow and low-cost reserve additions from this asset. We look forward to replicating this success as we now embark on Reford 2, a similar thermal project to Reford 1, which is expected to increase Cardinal's production by more than 15% in 2027."
RESERVE REPORT HIGHLIGHTS
All reserves information contained in this news release are based on the 2025 Reserve Report.
After growing its Total Proved plus Probable ("TPP") reserves by 30% at year-end 2024 with the addition of its first thermal project at Reford 1, the conversion of these bookings into higher value reserve categories continued in 2025. Cardinal's Total Proved ("TP") reserves increased by 24% (21% per basic share)(4) in 2025 at a Finding, Development, and Acquisition ("FD&A")(1)(2) cost of $21.77/boe;
Despite a modest capital budget being directed to our conventional assets in 2025, Cardinal delivered production replacement of 1.1x within the Proved Developed Producing ("PDP") reserve category. This was achieved through the addition of six producing SAGD well pairs at Reford and continued positive technical revisions from Cardinal's conventional assets that benefit from established enhanced oil recovery schemes for long-life reserves. Cardinal replaced 3.4x production in TP reserve category with 64% of Reford 1 reserves now classified as proved;
Reford 1 year-end 2025 reserve bookings grew to 5.8 million boe PDP, 25.7 million boe TP, and 40.1 million boe TPP, representing 7%/25%/27% of the total corporate reserves by category, respectively. The before tax net present value discounted at 10% ("NPV10") of Reford 1 is estimated at $507 million ($3.16 per basic share)(4) based on the three consultant's average (GLJ, McDaniel and Sproule Associates Ltd., collectively, the "Consultants") pricing forecast as at December 31, 2025;
Future thermal projects, including Reford 2 and Kelfield, remain unbooked at this time and were not captured in the Company's year-end 2025 Reserve Report. Cardinal's thermal upside has recently become more tangible with the Company formally sanctioning the Reford 2 project on January 28, 2026, alongside the concurrent $104.7 million equity financing. With this in place we are anticipating Cardinal will recognize another step-change in reserve additions for next year-end;
Cardinal's TPP reserves now consist of 93% light, medium and heavy crude oil and natural gas liquids ("NGL's") and 7% natural gas;
Notes:
(1) FD&A costs is a non-GAAP financial ratio. Development costs is a non-GAAP financial measure and is used as a component of the non-GAAP financial ratio. See "Oil and Gas Metrics" and "Non-GAAP and Other Financial Measures" in this news release for information relating to these non-GAAP financial ratios and measures.
(2) Company interest reserves were utilized in the calculation of FD&A costs. This included the consideration of royalty interest volumes produced of 11 mboe (2 mbbl of heavy crude oil; 8 mbbl of light and medium crude oil and 10 mmcf of natural gas).
(3) See also "Note Regarding Forward-Looking Statements", "Reserves Advisories" and "Reserve Definitions".
(4) At year-end 2025, there were 160,650,490 basic outstanding shares and 167,468,085 diluted shares outstanding.
CARDINAL'S TOP TIER RESERVE LIFE ASSETS
Cardinal continues to maintain a reserve life index ("RLI")(1) of 9.1 years PDP, 12.5 years TP, and 17.2 years TPP based on fourth quarter 2025 production. This reflects the low risk and predictable nature of our asset base that continues to demonstrate one of the lowest production decline rates amongst Cardinal's peers.
Cardinal's three-year average FD&A(1) costs for PDP, TP and TPP is $20.27/boe, $19.81 and $17.05/boe respectively.
The Company has multiple years of conventional inventory to be developed alongside the continued expansion of our thermal asset portfolio.
Notes:
(1) See "Oil and Gas Metrics".
(2) See also "Note Regarding Forward-Looking Statements", "Reserves Advisories" and "Reserve Definitions".
OIL AND GAS RESERVES
The 2025 Reserve Report was prepared in accordance with definitions, standards and procedures contained in the Canadian Oil and Gas Evaluation Handbook ("COGEH") and National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities ("NI 51-101"). Please also refer to "Note Regarding Forward-Looking Statements", "Reserves Advisories" and "Reserve Definitions" in this news release.
Our 2025 Reserve Report uses the price forecast of the Consultants outlined below.
Summary of Oil and Gas Reserves (1)(2)
The following tables summarize certain information contained in the 2025 Reserve Report. Reserves included below are the Company's estimated gross reserves as at December 31, 2025, as evaluated in the 2025 Reserve Report.
| Reserves Category | Light and Medium Oil (MMbbl) | Heavy Crude Oil (MMbbl) | Natural Gas Liquids (MMbbl) | Conventional Natural Gas(3) (Bcf) | Total BOE (MMboe) | |
| Proved Developed Producing | 36.9 | 32.9 | 2.7 | 35.2 | 78.4 | |
| Proved Developed Non-Producing | 0.8 | 0.4 | 0.1 | 4.4 | 2.0 | |
| Proved Undeveloped | 4.7 | 21.0 | 0.3 | 5.6 | 26.9 | |
| Total Proved | 42.4 | 54.3 | 3.1 | 45.2 | 107.3 | |
| Probable | 14.0 | 23.2 | 0.9 | 13.4 | 40.3 | |
| Total Proved Plus Probable | 56.4 | 77.5 | 4.0 | 58.6 | 147.6 |
Notes:
(1) Total values may not add due to rounding.
(2) In addition to the gross reserves indicated in the above table, the Company has 178 Mboe TPP royalty interest reserves
comprised of 142 Mbbl light and medium crude oil, 17 Mbbl of heavy crude oil, 2 Mbbl of natural gas liquids and 106 MMcf of conventional natural gas.
(3) Includes non-associated gas, associated gas and solution gas.
Summary of Net Present Values of Future Net Revenue (Before Tax)
(Based on forecast price and costs)
As at December 31, 2025(1)(2)(3)
| Discounted at: | |||||
| Reserves Category | 0.0% (MM$) | 5.0% (MM$) | 10.0% (MM$) | 15.0% (MM$) | 20.0% (MM$) |
| Proved Developed Producing | 2,119 | 1,617 | 1,261 | 1,036 | 886 |
| Proved Developed Non-Producing(4) | (163) | (80) | (50) | (35) | (27) |
| Proved Undeveloped | 621 | 410 | 282 | 202 | 150 |
| Total Proved | 2,578 | 1,947 | 1,493 | 1,203 | 1,008 |
| Probable | 1,649 | 820 | 494 | 336 | 248 |
| Total Proved Plus Probable | 4,227 | 2,767 | 1,987 | 1,540 | 1,257 |
Notes:
(1) Total values may not add due to rounding.
(2) Based on Three Consultant's average, as defined below, December 31, 2025 forecast prices and costs. See below for "Price Forecast".
(3) Future net revenue has been reduced for future abandonment costs and estimated capital for future development associated with the reserves.
(4) All abandonment, decommissioning and reclamation ("ADR") cost, including active (costs included in PDP category) and inactive (included in the Proved Developed Non-Producing ("PDNP") category). The NPV10 of PDNP excluding ADR would be $23.7 million.
Reconciliation of Changes in Reserves(1)
The following table sets out a reconciliation of the changes in the Company's gross reserves as at December 31, 2025 against such reserves at December 31, 2024 based on forecast prices and cost assumptions in effect at the applicable reserve evaluation date.
| Total Proved | |||||
| Light and Medium Crude Oil (MMbbl) | Heavy Crude Oil (MMbbl) | Conventional Natural Gas (Bcf) | Natural Gas Liquids (MMbbl) | MBOE (MMboe) | |
| December 31, 2024 | 50.6 | 26.2 | 48.8 | 2.9 | 87.9 |
| Acquisitions & Divestitures | - | (0.2) | (0.1) | - | (0.2) |
| Discoveries | - | - | - | - | - |
| Extensions and Infill Drilling | 0.1 | 26.3 | - | - | 26.1 |
| Technical Revisions (2) | (4.4) | 6.0 | 2.4 | 0.5 | 2.5 |
| Economic Factors (3) | (0.7) | (0.4) | (1.3) | - | (1.4) |
| Production | (3.2) | (3.6) | (4.7) | (0.3) | (8.0) |
| December 31, 2025 | 42.4 | 54.3 | 45.2 | 3.0 | 107.3 |
| Total Proved Plus Probable | |||||
| Light and Medium Crude Oil (MMbbl) | Heavy Crude Oil (MMbbl) | Conventional Natural Gas (Bcf) | Natural Gas Liquids (MMbbl) | MBOE (MMboe) | |
| December 31, 2024 | 67.0 | 72.7 | 63.5 | 3.8 | 154.2 |
| Acquisitions & Divestitures | (0.1) | (0.2) | (0.1) | - | (0.3) |
| Discoveries | - | - | - | - | - |
| Extensions and Infill Drilling | 0.2 | 2.4 | - | - | 2.3 |
| Technical Revisions (2) | (6.4) | 6.8 | 1.7 | 0.5 | 1.1 |
| Economic Factors (3) | (1.1) | (0.6) | (1.8) | (0.1) | (2.0) |
| Production | (3.2) | (3.6) | (4.7) | (0.3) | (8.0) |
| December 31, 2025 | 56.4 | 77.5 | 58.6 | 3.9 | 147.6 |
Notes:
(1) Total values may not add due to rounding.
(2) Positive or negative revisions are due to variations in performance versus previous forecasts, including improved recovery revisions.
(3) Economic factors have been calculated as the difference in reserves using the 2025 Reserve Report price forecast with the 2024 reserve report price forecasts. There is no consideration of changes in operating costs or price offset changes that occurred in 2025.
Price Forecast
The following table summarizes Consultant's average commodity price forecast and foreign exchange rate assumptions as at December 31, 2025, as applied in the 2025 Reserve Report, for the next five years.
| Consultants Average Price Forecast(1) | ||||||
| Exchange Rate | WTI @ Cushing | Canadian Light Sweet 40° API | Western Canada Select 20.9° API | Medium at Cromer 29° API | Natural gas AECO - C spot | |
| Year | ($C/$US) | ($US/bbl) | ($C/bbl) | $C/bbl) | ($C/bbl) | ($C/MMbtu) |
| 2026 | 0.728 | 59.92 | 77.54 | 65.12 | 75.60 | 3.00 |
| 2027 | 0.737 | 65.10 | 83.60 | 70.43 | 81.51 | 3.30 |
| 2028 | 0.740 | 70.28 | 90.18 | 76.90 | 87.92 | 3.49 |
| 2029 | 0.740 | 71.93 | 92.32 | 78.71 | 90.01 | 3.58 |
| 2030 | 0.740 | 73.37 | 94.17 | 80.29 | 91.82 | 3.65 |
Note:
(1) Inflation is accounted for at nil for 2026, and 2% thereafter.
Future Development Costs
Cardinal has conservatively booked undeveloped locations, reflecting our current drilling plans for the next three to four years. Meaningful potential drilling inventory exists beyond those locations and the associated reserves currently booked. Thermal reserves are a reflection of our Reford 1 project only, with potential future reserve expansion and value of other identified thermal projects currently not recognized in the 2025 Reserve Report.
Future Development Costs ("FDC") reflects the best estimate of the capital costs required to produce the Company's reserves. The FDC associated with the TPP reserves at year-end 2025 is $710 million undiscounted ($329 million discounted at 10%).
| millions $ | PDP | Total Proved | Total Proved plus Probable |
| Total FDC, Undiscounted | 71 | 579 | 710 |
| Total FDC, Discounted at 10% | 43 | 330 | 329 |
FDC included at year-end 2025 for CO2 purchases, maintenance and facility capital in PDP, TP and TPP were $71 million, $73 million and $83 million, respectively. Cardinal's Reford 1 thermal project accounts for 69% ($488 million) of the inflated, undiscounted TPP FDC.
Note Regarding Forward-Looking Statements
This news release contains forward-looking statements and forward-looking information (collectively "forward-looking information") within the meaning of applicable securities laws relating to the Cardinal's plans and other aspects of Cardinal's anticipated future operations, management focus, objectives, strategies, financial, operating and production results. Forward-looking information typically uses words such as "anticipate", "believe", "project", "expect", "goal", "plan", "intend", " may", "would", "could" or "will" or similar words suggesting future outcomes, events or performance. The forward-looking statements contained in this news release speak only as of the date thereof and are expressly qualified by this cautionary statement.
Specifically, this news release contains forward-looking statements relating to: our asset base and its future potential and opportunities; that we will receive decades of predictable free cash flow and low-cost reserve additions from Reford 2; that the Company's success at Reford 1 will be replicated at Reford 2; that Reford 2 will increase our production by more than 15% in 2027; that the Company has multiple years of conventional inventory to be developed alongside the continued expansion of our thermal assets; future development capital; the life of our reserves; the booking of undeveloped locations which reflect our current drilling plans; our views that significant potential drilling inventory exists beyond those currently booked; the potential for reserve expansion to other identified projects currently not recognized in the 2025 Reserve Report; and that Cardinal will recognize a step-change in TPP reserves at the end of 2026.
In addition, information and statements relating to reserves are deemed to be forward-looking statements, as they involve implied assessment, based on certain estimates and assumptions, that the reserves described exist in quantities predicted or estimated, and that the reserves can be profitably produced in the future.
Forward-looking statements regarding Cardinal are based on certain key expectations and assumptions of Cardinal concerning anticipated financial performance, business prospects, strategies, regulatory developments, current and future commodity prices and exchange rates, applicable royalty rates, tax laws, future well production rates and reserve volumes, future operating costs, inflation, the performance of existing and future wells, the success of its exploration and development activities, the development of current and other potential thermal properties, the sufficiency and timing of budgeted capital expenditures in carrying out planned activities, the availability and cost of labor and services, the impact of competition, conditions in general economic and financial markets, access to markets, availability of drilling and related equipment, effects of regulation by governmental agencies, the ability to obtain financing on acceptable terms which are subject to change based on commodity prices, market conditions and potential timing delays.
These forward-looking statements are subject to numerous risks and uncertainties, certain of which are beyond Cardinal's control. Such risks and uncertainties include, without limitation: the impact of general economic conditions; volatility in market prices for crude oil and natural gas; industry conditions; currency fluctuations; imprecision of reserve estimates; liabilities inherent in crude oil and natural gas operations; environmental risks; incorrect assessments of the value of exploration and development programs; competition from other producers; the lack of availability of qualified personnel, drilling rigs or other services; changes in income tax laws or changes in royalty rates and incentive programs relating to the oil and gas industry; hazards such as fire, explosion, blowouts, and spills, each of which could result in substantial damage to wells, production facilities, other property and the environment or in personal injury; and ability to access sufficient capital from internal and external sources.
Management has included the forward-looking statements above and a summary of assumptions and risks related to forward-looking statements provided in this news release in order to provide readers with a more complete perspective on Cardinal's future operations and such information may not be appropriate for other purposes. Cardinal's actual results, performance or achievement could differ materially from those expressed in, or implied by, these forward-looking statements and, accordingly, no assurance can be given that any of the events anticipated by the forward-looking statements will transpire or occur, or if any of them do so, what benefits that Cardinal will derive therefrom. Readers are cautioned that the foregoing lists of factors are not exhaustive. These forward-looking statements are made as of the date of this news release and Cardinal disclaims any intent or obligation to update publicly any forward-looking statements, whether as a result of new information, future events or results or otherwise, other than as required by applicable securities laws.
Oil and Gas Metrics
The term "boe" or barrels of oil equivalent 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. Additionally, given that the value ratio based on the current price of crude oil, as compared to natural gas, is significantly different from the energy equivalency of 6:1; utilizing a conversion ratio of 6:1 may be misleading as an indication of value.
This news release contains metrics commonly used in the oil and natural gas industry which have been prepared by management, such as "development costs", "FD&A costs", "reserve life index" and "replacement rate". These terms do not have a standardized meaning and may not be comparable to similar measures presented by other companies, and therefore should not be used to make such comparisons.
"Development costs" means the aggregate exploration and development costs including land and seismic incurred in the financial year on reserves that are characterized as development but exclude capitalized general and administration costs. The aggregate of the development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserves additions for that year. Costs associated with exploration and evaluation assets have been excluded from this calculation. See "Non-GAAP Financial Measures".
"FD&A costs" are calculated as the sum of development costs plus net acquisition costs plus the change in FDC for the period when appropriate, divided by the change in reserves within the applicable reserves category, inclusive of changes due to acquisitions and dispositions. Costs associated with exploration and evaluation assets have been excluded from this calculation.
"Reserve life index" or "RLI" is calculated by dividing the applicable reserves by 2025 fourth quarter production of 23,500 boe/d for the PDP and TP reserve categories.
"Replacement rate" or similar terms does not have a standardized meaning and may not be comparable to similar measures presented by other companies and, therefore, should not be used to make such comparisons. Replacement rate (and similar terms) is the amount added to the Company's applicable reserves, divided by production. It is a measure of the ability of the Company to sustain production levels.
Management uses these oil and gas metrics for its own performance measurements and to provide shareholders with measures to compare our operations over time. Readers are cautioned that the information provided by these metrics, or that can be derived from the metrics presented in this news release, should not be relied upon for investment or other purposes.
Unaudited Financial Information
Certain financial and operating information included in this news release for the year ended December 31, 2025 are based on estimated unaudited financial results for the year then ended, and are subject to the same limitations as discussed under "Note Regarding Forward-Looking Statements". These estimated amounts may change upon the completion of audited financial statements for the year ended December 31, 2025 and such changes could be material.
Supplemental Information Regarding Product Types
This news release includes references to 2025 fourth quarter production. The following table is intended to provide the product type composition as defined by NI 51-101.
| Light/medium Crude Oil | Heavy Oil | NGL | Conventional Natural Gas | Total (boe/d) | |
| Q4 2025 | 42% | 46% | 3% | 9% | 23,500 |
Reserves Advisories
In the 2025 Reserve Report, Cardinal has included all ADR costs for active and inactive wells and facilities. The ADR costs for the active assets are considered in the PDP reserves category. Full inclusion of all ADR costs is recommended by COGEH. Cardinal's full inclusion of costs exceeds the NI 51-101 minimum requirement of ADR for only those assets assigned reserves.
Consistent with prior years and in accordance with COGEH recommendations, Cardinal has included all operating costs for active and inactive assets. The Company also includes the consideration of future maintenance costs which are included as part of the operating costs or as FDC.
Unless otherwise indicated, all reserves reported in this news release are Company share gross reserves which represent Cardinal's total working interest reserves prior to the deduction of royalties payable.
Future net revenue is a forecast of revenue, estimated using forecast prices and costs arising from the anticipated development and production of resources, net of associated royalties, operating costs, development costs and all corporate abandonment and reclamation costs for all active and inactive wells, pipelines and facilities. It should not be assumed that the future net revenues undiscounted and discounted at 10% included in this news release represent the fair market value of the reserves.
The estimates of reserves and future net revenue for individual properties may not reflect the same confidence level as estimates of reserves and future net revenue for all properties due to the effects of aggregation.
Reserve Definitions
"Proved" reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.
"Probable" reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves.
"Developed" reserves are those reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure (e.g. when compared to the cost of drilling a well) to put the reserves on production.
"Developed Producing" reserves are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut-in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty.
"Developed Non-Producing" reserves are those reserves that either have not been on production, or have previously been on production, but are shut-in, and the date of resumption of production is unknown.
"Undeveloped" reserves are those reserves expected to be recovered from known accumulations where a significant expenditure (for example, when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reserve's classification (proved, probable, possible) to which they are assigned.
Non-GAAP and Other Financial Measures
Throughout this news release and in other materials disclosed by the Company, Cardinal employs certain measures to analyze its financial performance, financial position, and cash flow. These non-GAAP and other financial measures are not standardized financial measures under International Financial Reporting Standards ("IFRS" or, alternatively, "GAAP") and may not be comparable to similar financial measures disclosed by other issuers. The non-GAAP and other financial measures should not be considered to be more meaningful than generally accepted accounting principles ("GAAP") measures which are determined in accordance with IFRS, such as net earnings (loss) and cash flow from operating activities as indicators of Cardinal's performance.
Non-GAAP Financial Measures
"Development costs" means the aggregate property, property plant and equipment expenditures including land and seismic incurred in the financial year on reserves that are characterized as development but exclude capitalized general and administration costs.
Non-GAAP Financial Ratios
"FD&A costs" is a non-GAAP financial ratio. See "Oil and Gas Advisories". Management uses FD&A costs as a measure of capital efficiency for organic and acquired reserves development.
About Cardinal Energy Ltd.
Cardinal is a Canadian oil and natural gas production company with operations focused on low decline sustainable oil production in Western Canada. The Company's portfolio of conventional and SAGD projects offers a complimentary low decline, long life resource base that is ideally suited to sustain our commitment to meaningful dividend returns to shareholders.
For further information:
Shawn Van Spankeren, CFO, Laurence Broos, VP Finance or Cody Kwong, Manager Business Development
Email: info@cardinalenergy.ca
Phone: (403) 234-8681
Website: www.cardinalenergy.ca
To view the source version of this press release, please visit https://www.newsfilecorp.com/release/284802
Source: Cardinal Energy Ltd.
