Whitecap Delivers Record 2025 Results, Exceeds Guidance and Successfully Integrates Veren

CALGARY, AB , Feb. 23, 2026 /CNW/ – Whitecap Resources Inc. (“Whitecap” or the “Company”) (TSX: WCP) is pleased to report its operating and audited financial results for the three months and year ended December 31, 2025 and year end 2025 reserves.

Selected financial and operating information is outlined below and should be read with Whitecap’s audited annual consolidated financial statements and related management’s discussion and analysis for the three months and year ended December 31, 2025 which are available at sedarplus.ca and on our website at wcap.ca.

MESSAGE TO SHAREHOLDERS

2025 was an exceptional operational and financial year for Whitecap, driven by the controlled and focused integration of the business combination with Veren Inc. (the “Veren Combination”) and strong execution following its closing on May 12, 2025. The Company realized immediate efficiencies across the combined asset base and exceeded second half production guidance, averaging 377,115 boe/d on capital expenditures of $1.2 billion. Full year average production was 307,245 boe/d (62% liquids), approximately 10,000 boe/d above the guidance range of 295,000 – 300,000 boe/d established at closing, on $2.0 billion of capital expenditures. Annualized integration synergies now exceed $300 million, a 43% increase over the original estimate of $210 million.

The increased size and scale of the combined company, supported by its investment grade credit profile, have enhanced Whitecap’s ability to access premium markets and execute larger, long-term marketing agreements that provide meaningful price diversification. Today, Whitecap is the seventh largest oil and gas producer in Canada, providing the scale and reliability required to support significant long-term production commitments. Whitecap has entered into a 10-year agreement with Centrica Energy, the energy trading and optimization arm of Centrica plc., to deliver 50,000 MMBtu/d of natural gas beginning in April 2028, priced off European Title Transfer Facility (TTF) benchmarks. The Company has also executed a second 10-year agreement with a third party to deliver 35,000 MMBtu/d of natural gas beginning in July 2026, with volumes physically delivered in Chicago and priced at NYMEX Henry Hub less associated deductions. Together, these agreements represent significant progress toward Whitecap’s strategy of diversifying 50% of future natural gas volumes away from regional markets and providing long-term exposure to premium pricing hubs.

Whitecap ended the year with a strong balance sheet and significant financial flexibility. The Company remains investment grade rated by DBRS (BBB) and maintains low leverage, with net debt to funds flow below 1.0 times based on annualized fourth quarter results. During 2025, Whitecap issued $300 million of investment grade notes at a low coupon of 3.761% and closed the year with approximately $1.5 billion of available liquidity. With a balanced debt structure and an average cost of debt of approximately 4%, Whitecap is well positioned to support sustainable shareholder returns and future growth.

2025 Highlights

• Record annual production of 307,245 boe/d (62% liquids), up 76% from 2024.
• Funds flow of $2.9 billion ($2.95 per share), representing the second highest annual per share funds flow in Whitecap’s history.
• Free funds flow of approximately $900 million, after capital expenditures of $2.0 billion.
• Total shareholder return¹ of 15%, at the high end of our annual target range, comprised of 6% production per share growth⁵, 7% base dividend yield and 2% share repurchases.
• Year end net debt of $3.4 billion, with net debt to annualized fourth quarter funds flow of less than 1.0 times.

Fourth Quarter 2025 Highlights

• Record quarterly production of 379,606 boe/d (61% liquids) continues Whitecap’s track record of delivering results above guidance driven by strong base production, new well performance and operational execution.
• Funds flow of approximately $900 million ($0.72 per share), reflecting operating cost synergies realized across the combined asset base and strong operational performance. Margin enhancement initiatives remain a focus for 2026 and beyond.
• Free funds flow of $186 million, after capital expenditures of $696 million.
• Operating netback of $28.25 per boe, highlighting the strength of the Company’s margins and cost structure.

2025 Year End Reserves Highlights

• Record total proved plus probable (“2P”) reserves of 2.2 billion boe, resulting in a long-duration reserve life index⁶ (“RLI”) of over 16 years.
• Conservative reserve bookings, with only 21% of identified unconventional locations⁷ and 35% of identified conventional locations currently booked in 2P reserves, highlighting significant future inventory upside.
• Total reserve growth of over 80% year-over-year across proved developed producing (“PDP”), total proved (“1P”) and 2P reserve categories, reflecting the impact of the Veren Combination and continued organic development success.
• Positive technical revisions, driven by improved base production performance and type curve enhancements across our Montney, Duvernay and Glauconite inventory.
• Strong capital efficiency, with 2P finding and development (“F&D”) costs¹ of $17.17/boe and a recycle ratio of 1.7x, and 2P finding, development and acquisition (“FD&A”) costs¹ of $15.81/boe and a recycle ratio of 1.9x.

OPERATION REVIEW

Operational results in 2025 were very strong, with production exceeding guidance while capital spending remained in line with expectations. Performance across both acquired and legacy assets improved through enhanced drilling and completion execution, infrastructure optimization and production timing. Fourth quarter results were particularly strong, driven by record production and continued outperformance from both base volumes and new wells.

Unconventional Highlights

• Gold Creek/Karr was the primary driver of fourth quarter outperformance, supported by enhanced execution, production optimization initiatives and strong initial production rates. Infrastructure enhancements and targeted operational improvements have strengthened base production, while new well initial production rates have exceeded expectations by approximately 10%.
• In the Duvernay at Kaybob, we recently brought on production our seventh pad utilizing a wine rack drilling design. Subsurface data from pilot and follow-on pads supports improved reservoir access and reduced inter-well interaction. A portion of the anticipated estimated ultimate recovery (EUR) uplift has been incorporated into our 2025 reserves, with further optimization expected as additional data is evaluated.
• Construction of the 04-13 Lator facility continues to progress alongside the drilling of eleven (11.0 net) wells in 2026, which are expected to be brought on production into the 04-13 facility which is planned to be completed in the fourth quarter. Ongoing integration of well performance data, collaboration across technical teams and continued subsurface analysis will inform future development plans in the area.
• The Musreau asset delivered strong production outperformance in 2025. Improvements in drilling and completion execution contributed to significant free cash flow¹ generation, with the asset delivering over $100 million of operating free cash flow during the year.

Conventional Highlights

• Our Glauconite assets significantly outperformed expectations in 2025, driven by strong new well performance, production optimization initiatives and enhanced operational execution. Since acquiring the asset in 2021, Whitecap has improved drilling and completion designs and strengthened infrastructure access, improving overall well productivity and economics.
• In the East Saskatchewan Bakken, transitioning to more 2-mile laterals and increasing lateral length on our open hole multi-lateral (“OHML”) program is expected to enhance near-term economics and expand future inventory depth. A recent 3-mile OHML Bakken well achieved an IP90 production rate of 324 bbl/d³, approximately 38% above expectations.
• Our East Saskatchewan Bakken and Frobisher assets drove Saskatchewan outperformance in 2025. From our 2025 program, new wells with more than 180 days of production history have achieved IP180 rates that are on average 41% above expectations.

OUTLOOK

Whitecap has entered 2026 with strong operational momentum, supported by carryover performance from late 2025 and continued integration benefits across the combined asset base. Activity levels are expected to be elevated in the first quarter, with drilling peaking at 18 rigs as part of an active winter program focused on execution and on-stream timing.

The Company benefits from a deep, high-quality inventory that supports multi decades of sustainable development across a broad range of commodity price environments spanning light oil, liquids rich natural gas to lean natural gas opportunities. Whitecap’s 2026 guidance remains unchanged at 370,000 – 375,000 boe/d on capital investment of $2.0 – $2.1 billion, reflecting confidence in the plan and continued capital discipline. We plan to drill approximately 255 (231.6 net) wells in 2026, which compares to our total inventory of approximately 10,500 locations⁷. This long-duration opportunity set provides Whitecap with significant flexibility to allocate capital to the highest return projects while maintaining disciplined growth and long-term value creation.

Commodity markets have experienced volatility to begin the year, driven by geopolitical uncertainty and evolving global trade dynamics. Whitecap is well positioned to manage price variability through its strong balance sheet, significant liquidity and disciplined risk management program, with approximately 25% of oil production and 29% of natural gas production hedged in 2026.

Whitecap remains constructive on the medium- and long-term commodity outlook. Expanded oil egress through the Trans Mountain Expansion (“TMX”) pipeline and the potential for future capacity enhancements support improved access to global markets for Canadian crude oil. Condensate fundamentals remain favorable, supported by sustained demand for diluent. For natural gas, Whitecap expects structural demand growth driven by liquified natural gas (“LNG”) expansion and growing power demand across North America. Against this backdrop, the Company will maintain a disciplined approach to capital allocation as we advance our strategic priorities in 2026.

On behalf of our employees, management team and Board of Directors, we thank our shareholders for their continued support and confidence in our team.

2025 RESERVES REVIEW

Our 2025 year end reserves were evaluated by independent reserves evaluator McDaniel & Associates Consultants Ltd. (“McDaniel”) in accordance with the definitions, standards and procedures contained in the Canadian Oil and Gas Evaluation Handbook (“COGE Handbook”) and National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (“NI 51-101”) as of December 31, 2025. The reserves evaluation was based on the average forecast pricing of McDaniel, GLJ Ltd. and Sproule ERCE and foreign exchange rates at January 1, 2026 which is available on McDaniel’s website at mcdan.com.

Reserves included are Company share (gross) reserves which are the Company’s total working interest reserves before the deduction of any royalties and without including any royalty interests payable to the Company. Additional reserves information as required under NI 51-101 will be included in our Annual Information Form which will be filed on SEDAR+ at sedarplus.ca. The numbers in the tables below may not add due to rounding.

Summary of Reserves

Reserves as at December 31, 2025

Net Present Values of Future Net Revenue

Summary of Before Tax Net Present Values of Future Net Revenue (Forecast Pricing)
As at December 31, 2025

Future Development Costs (“FDC”)

FDC reflects the best estimate of the capital cost to develop and produce reserves. FDC associated with our 1P reserves at year end 2025 is $12.8 billion undiscounted ($9.8 billion discounted at 10%).

Also included in FDC are 2,256 (2,086 net) proved booked drilling locations and 732 (681 net) probable booked drilling locations.

Performance Measures (Including FDC)

The following table highlights F&D and FD&A costs and associated recycle ratios, including FDC, based on the evaluation of our petroleum and natural gas reserves prepared by McDaniel:

Production Replacement Ration and Reserve Life Index

The following table highlights our production replacement ratio and RLI based on the evaluation of our petroleum and natural gas reserves prepared by McDaniel:

In 2025, we replaced 383% of production on a PDP reserves basis, 687% of production on a 1P reserves basis and 1,011% of production on a 2P reserves basis.

CONFERENCE CALL AND WEBCAST

Whitecap has scheduled a conference call and webcast to begin promptly at 9:00 am MT (11:00 am ET) on Tuesday, February 24, 2026.

The conference call dial-in number is: 1-888-510-2154 or (403) 910-0389 or (437) 900-0527

A live webcast of the conference call will be accessible on Whitecap’s website at wcap.ca by selecting “Investors”, then “Presentations & Events”. Shortly after the live webcast, an archived version will be available for approximately 14 days.

NOTE REGARDING FORWARD-LOOKING STATEMENTS

This press release contains forward-looking statements and forward-looking information (collectively “forward-looking information”) within the meaning of applicable securities laws relating to the Company’s plans and other aspects of our anticipated future operations, management focus, strategies, financial, operating and production results and business opportunities. Forward-looking information typically uses words such as “anticipate”, “believe”, “continue”, “trend”, “sustain”, “project”, “expect”, “forecast”, “budget”, “goal”, “guidance”, “plan”, “objective”, “strategy”, “target”, “intend”, “estimate”, “potential”, or similar words suggesting future outcomes, statements that actions, events or conditions “may”, “would”, “could” or “will” be taken or occur in the future, including statements about our strategy, plans, focus, objectives, priorities and position.

In particular, and without limiting the generality of the foregoing, this press release contains forward-looking information with respect to: our estimation that annualized integration synergies now exceed $300 million; our belief that the increased size and scale of the combined company, supported by its investment grade credit profile, have enhanced Whitecap’s ability to access premium markets and execute larger, long-term marketing agreements that provide meaningful price diversification; our belief that the size of our production provides the scale and reliability required to support significant long-term production commitments; the terms of the Centrica Energy agreement, including volumes, term and pricing as described herein; the terms of the second natural gas sales agreement, including volumes, term and pricing as described herein; our belief that these agreements represent significant progress toward Whitecap’s strategy of diversifying 50% of future natural gas volumes away from regional markets and provide long-term exposure to premium pricing hubs; that Whitecap has $1.5 billion of available liquidity; our belief that Whitecap is well positioned to support sustainable shareholder returns and future growth; that margin enhancement initiatives remain a focus for 2026 and beyond; our anticipated RLI; our belief that conservative reserve bookings highlight significant future inventory upside; our belief that infrastructure enhancements and targeted operational improvements have strengthened base production; that further optimization of our Kaybob wine rack reserve bookings is expected as additional data is evaluated; that we anticipate bringing Lator wells on production upon facility completion, and the anticipated timing of the facility completion; our belief that ongoing integration of well performance data, collaboration across technical teams and continued subsurface analysis will inform future development plans in the Lator area; our belief that transitioning to more 2-mile laterals and increasing lateral length on our OHML program is expected to enhance near-term economics and expand future inventory depth; that activity levels are expected to be elevated in the first quarter, with drilling peaking at 18 rigs and that or winter program will be focused on execution and on-stream timing; our belief that the Company benefits from a deep, high-quality inventory that supports multi decades of sustainable development across a broad range of commodity price environments spanning light oil, liquids rich natural gas to lean natural gas opportunities; our belief that this long-duration opportunity set provides Whitecap with significant flexibility to allocate capital to the highest-return projects while maintaining disciplined growth and long-term value creation; our forecast 2026 capital expenditures, wells drilled and average daily production, including by product type; our assumption for the total locations in our inventory; our belief that Whitecap is well positioned to manage price variability through its strong balance sheet, significant liquidity and disciplined risk management program; the approximate proportion of our production hedged for 2026; that Whitecap remains constructive on the medium- and long-term commodity outlook; our belief that expanded oil egress through the TMX pipeline and the potential for future capacity enhancements support improved access to global markets for Canadian crude oil; our belief that condensate fundamentals remain favorable, supported by sustained demand for diluent; that Whitecap expects structural demand growth driven by LNG expansion and growing power demand across North America; and that we will maintain a disciplined approach to capital allocation as we advance our strategic priorities in 2026. Statements relating to “reserves” are also deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated and that the reserves can be profitably produced in the future.

The forward-looking information is based on certain key expectations and assumptions made by our management, including: the duration and impact of tariffs that are currently in effect on goods exported from or imported into Canada, and that other than the tariffs that are currently in effect, neither the U.S. nor Canada (i) increases the rate or scope of such tariffs, reenacts tariffs that are currently suspended, or imposes new tariffs, on the import of goods from one country to the other, including on oil and natural gas, and/or (ii) imposes any other form of tax, restriction or prohibition on the import or export of products from one country to the other, including on oil and natural gas; that we will continue to conduct our operations in a manner consistent with past operations except as specifically noted herein (and for greater certainty, the forward-looking information contained herein excludes the potential impact of any acquisitions or dispositions that we may complete in the future); the general continuance or improvement in current industry conditions; the continuance of existing (and in certain circumstances, the implementation of proposed) tax, royalty and regulatory regimes; expectations and assumptions concerning prevailing and forecast commodity prices, exchange rates, interest rates, inflation rates, applicable royalty rates and tax laws, including the assumptions specifically set forth herein; the ability of OPEC+ nations and other major producers of crude oil to adjust crude oil production levels and thereby manage world crude oil prices; the impact (and the duration thereof) of the ongoing military actions in the Middle East and between Russia and Ukraine and related sanctions on crude oil, NGLs and natural gas prices; the impact of current and forecast exchanges rates, inflation rates and/or interest rates on the North American and world economies and the corresponding impact on our costs, our profitability, and on crude oil, NGLs and natural gas prices; future production rates and estimates of operating costs and development capital, including as specifically set forth herein; performance of existing and future wells; reserves volumes and net present values thereof; anticipated timing and results of capital expenditures/development capital, including as specifically set forth herein; the success obtained in drilling new wells; the sufficiency of budgeted capital expenditures in carrying out planned activities; the timing, location and extent of future drilling operations; the timing and costs of pipeline, storage and facility construction and expansion; the state of the economy and the exploration and production business; the availability and cost of financing, labour and services; future dividend levels and share repurchase levels; the impact of increasing competition; ability to efficiently integrate assets and employees acquired through acquisitions or asset exchange transactions; ability to market oil and natural gas successfully; our ability to access capital and the cost and terms thereof; that we will not be forced to shut-in production due to weather events such as wildfires, floods, droughts or extreme hot or cold temperatures; and that we will be successful in defending against previously disclosed and ongoing reassessments received from the Canada Revenue Agency and assessments received from the Alberta Tax and Revenue Administration.

Although we believe that the expectations and assumptions on which such forward-looking information is based are reasonable, undue reliance should not be placed on the forward-looking information because Whitecap can give no assurance that they will prove to be correct. Since forward-looking information addresses future events and conditions, by its very nature it involves inherent risks and uncertainties. These include, but are not limited to: the risk that the funds that we ultimately return to shareholders through dividends and/or share repurchases is less than currently anticipated and/or is delayed, whether due to the risks identified herein or otherwise; the risk that any of our material assumptions prove to be materially inaccurate, including our 2026 forecast (including for production levels, capital expenditure levels, commodity prices and exchange rates); the risk that (i) the tariffs that are currently in effect on goods exported from or imported into Canada continue in effect for an extended period of time, the tariffs that have been threatened are implemented, that tariffs that are currently suspended are reactivated, the rate or scope of tariffs are increased, or new tariffs are imposed, including on oil and natural gas, (ii) the U.S. and/or Canada imposes any other form of tax, restriction or prohibition on the import or export of products from one country to the other, including on oil and natural gas, and (iii) the tariffs imposed or threatened to be imposed by the U.S. on other countries and retaliatory tariffs imposed or threatened to be imposed by other countries on the U.S., will trigger a broader global trade war which could have a material adverse effect on the Canadian, U.S. and global economies, and by extension the Canadian oil and natural gas industry and the Company including be decreasing demand for (and the price of) oil and natural gas, disrupting supply chains, increasing costs, causing volatility in global financial markets, and limiting access to financing; the risks associated with the oil and gas industry in general such as operational risks in development, exploration and production, including the risk that weather events such as wildfires, flooding, droughts or extreme hot or cold temperatures forces us to shut-in production or otherwise adversely affects our operations; pandemics and epidemics; delays or changes in plans with respect to exploration or development projects or capital expenditures; the uncertainty of estimates and projections relating to reserves, production, costs and expenses; risks associated with increasing costs, whether due to elevated inflation rates, elevated interest rates, supply chain disruptions or other factors; health, safety and environmental risks; commodity price and exchange rate fluctuations; interest rate fluctuations; inflation rate fluctuations; marketing and transportation risks; loss of markets; environmental risks; competition; incorrect assessment of the value of acquisitions; failure to complete or realize the anticipated benefits of acquisitions or dispositions; the risk that going forward we may be unable to access sufficient capital from internal and external sources on acceptable terms or at all; failure to obtain required regulatory and other approvals; reliance on third parties and pipeline systems; changes in legislation, including but not limited to tax laws, tariffs, import or export restrictions or prohibitions, production curtailment, royalties and environmental (including emissions and “greenwashing”) regulations; the risk that we do not successfully defend against previously disclosed and ongoing reassessments received from the Canada Revenue Agency and assessments received from the Alberta Tax and Revenue Administration and are required to pay additional taxes, interest and penalties as a result; and the risk that the amount of future cash dividends paid by us and/or shares repurchased for cancellation by us, if any, will be subject to the discretion of our Board of Directors and may vary depending on a variety of factors and conditions existing from time to time, including, among other things, fluctuations in commodity prices, production levels, capital expenditure requirements, debt service requirements, operating costs, royalty burdens, foreign exchange rates, contractual restrictions contained in our debt agreements, and the satisfaction of the liquidity and solvency tests imposed by applicable corporate law for the declaration and payment of dividends and/or the repurchase of shares – depending on these and various other factors as disclosed herein or otherwise, many of which will be beyond our control, our dividend policy and/or share buyback policy and, as a result, future cash dividends and/or share buybacks, could be reduced or suspended entirely. Our actual results, performance or achievement could differ materially from those expressed in, or implied by, the forward-looking information and, accordingly, no assurance can be given that any of the events anticipated by the forward-looking information will transpire or occur, or if any of them do so, what benefits that we will derive therefrom. Management has included the above summary of assumptions and risks related to forward-looking information provided in this press release in order to provide security holders with a more complete perspective on our future operations and such information may not be appropriate for other purposes.

Readers are cautioned that the foregoing lists of factors are not exhaustive. Additional information on these and other factors that could affect our operations or financial results are included in reports on file with applicable securities regulatory authorities and may be accessed through the SEDAR+ website (sedarplus.ca).

These forward-looking statements are made as of the date of this press release and we disclaim any intent or obligation to update publicly any forward-looking information, whether as a result of new information, future events or results or otherwise, other than as required by applicable securities laws.

This press release contains future-oriented financial information and financial outlook information (collectively, “FOFI”) about: our forecast 2026 capital investment; our forecast of average daily production for 2026; the annual capital, operating and corporate synergies embedded in our 2026 forecast; our available liquidity; our average cost of debt; our forecasts for the future development costs to develop and produce our reserves; all of which are subject to the same assumptions, risk factors, limitations, and qualifications as set forth in the above paragraphs. The actual results of operations of Whitecap and the resulting financial results will likely vary from the amounts set forth herein and such variation may be material. Whitecap and its management believe that the FOFI has been prepared on a reasonable basis, reflecting management’s best estimates and judgments. However, because this information is subjective and subject to numerous risks, it should not be relied on as necessarily indicative of future results. Except as required by applicable securities laws, Whitecap undertakes no obligation to update such FOFI. FOFI contained in this press release was made as of the date of this press release and was provided for the purpose of providing further information about Whitecap’s anticipated future business operations. Readers are cautioned that the FOFI contained in this press release should not be used for purposes other than for which it is disclosed herein.

OIL AND GAS ADVISORIES

Reserves Volumes and Net Present Values

All reserve references in this press release are “Company share (gross) reserves”. Company share reserves are our total working interest reserves before the deduction of any royalties and without including any royalty interests payable to the Company.

It should not be assumed that the present worth of estimated future amounts presented in the tables above represents the fair market value of the reserves. There is no assurance that the forecast prices and costs assumptions will be attained, and variances could be material. The recovery and reserves estimates of the crude oil, natural gas liquids and natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual crude oil, natural gas and natural gas liquids reserves may be greater than or less than the estimates provided herein.

Barrel of Oil Equivalency

“Boe” means barrel of oil equivalent. All boe conversions in this press release are derived by converting gas to oil at the ratio of six thousand cubic feet (“Mcf”) of natural gas to one barrel (“Bbl”) of oil. Boe may be misleading, particularly if used in isolation. A Boe conversion rate of 1 Bbl : 6 Mcf is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio of oil compared to natural gas based on currently prevailing prices is significantly different than the energy equivalency ratio of 1 Bbl : 6 Mcf, utilizing a conversion ratio of 1 Bbl : 6 Mcf may be misleading as an indication of value.

Oil and Gas Metrics

This press release contains metrics commonly used in the oil and natural gas industry which have been prepared by management, such as the terms described below. 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.

“Acquisition capital” is a non-GAAP financial measure used in the determination of FD&A costs, which is a non-GAAP ratio. The most directly comparable GAAP measure to acquisition capital is expenditures on corporate acquisitions, net of cash acquired, and expenditures on property acquisitions. For property acquisitions and dispositions, acquisition capital is the net purchase price of assets acquired (disposed). For corporate acquisitions, it is the purchase price (cash and/or shares plus assumed bank debt, if applicable) including any estimated working capital surplus or deficit rather than the amounts allocated to property, plant and equipment (“PP&E”) for accounting purposes. The following table details the calculation of Acquisition capital for the periods indicated:

“Development capital” is a non-GAAP financial measure used in the determination of F&D costs and FD&A costs, which are non-GAAP ratios. The most directly comparable GAAP measure to development capital is expenditures on PP&E. Development capital means the aggregate exploration and development costs incurred in the financial year on reserves that are categorized as development. Development capital excludes corporate and capitalized general and administrative expenses. The following table reconciles expenditures on PP&E to Development capital for the periods indicated:

“F&D costs” are calculated as the sum of development capital plus the change in FDC for the period when appropriate, divided by the change in reserves that are characterized as development for the period. Development capital is a non-GAAP financial measure used as a component of F&D costs. Management uses F&D costs as a measure of capital efficiency for organic reserves development.

“FD&A costs” are calculated as the sum of development capital plus acquisition capital plus the change in FDC for the period when appropriate, divided by the change in total reserves, other than from production, for the period. Development capital and acquisition capital are non-GAAP financial measures used as components of FD&A costs. Management uses FD&A costs as a measure of capital efficiency for organic and acquired reserves development.

“Production replacement ratio” or “production replacement” is calculated as total reserve additions (including acquisitions net of dispositions) divided by annual production.

“Recycle ratio” is calculated by dividing operating netback per boe by F&D costs or FD&A costs for the year. Operating netback per boe is a non-GAAP ratio that uses operating netback, a non-GAAP financial measure, as a component. Development capital, a non-GAAP financial measure, is used as a component of F&D costs. Development capital and acquisition capital, both non-GAAP financial measures, are used as components of FD&A costs. Management uses recycle ratio to relate the cost of adding reserves to the expected cash flows to be generated.

“Reserve life index” or “RLI” is calculated as total Company share (gross) reserves divided by annualized fourth quarter actual production.

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 press release, should not be relied upon for investment or other purposes.

Drilling Locations

This press release discloses drilling inventory in two categories: (i) booked locations (proved and probable); and (ii) unbooked locations. Booked locations represent the summation of proved and probable locations, which are derived from McDaniel & Associates Consultants Ltd.’s reserves evaluation effective December 31, 2025 and account for drilling locations that have associated proved and/or probable reserves, as applicable. Unbooked locations are internal estimates based on our prospective acreage and an assumption as to the number of wells that can be drilled per section based on industry practice and internal review. Unbooked locations do not have attributed reserves or resources.

• Of the 10,481 (9,554 net) drilling locations identified herein, 2,256 (2,086 net) are proved locations, 732 (681 net) are probable locations, and 7,493 (6,787 net) are unbooked locations.

Unbooked locations consist of drilling locations that have been identified by management as an estimation of our multi-year drilling activities based on evaluation of applicable geologic, seismic, engineering, production and reserves information. There is no certainty that we will drill all of these 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 we drill wells will ultimately depend upon the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results, additional reservoir information that is obtained and other factors. While certain of the unbooked drilling locations have been de-risked by drilling existing wells in relative close proximity to such unbooked drilling locations, other unbooked drilling locations are farther away from existing wells where management has less information about the characteristics of the reservoir and therefore there is more uncertainty whether wells will be drilled in such locations and if drilled there is more uncertainty that such wells will result in additional oil and gas reserves, resources or production.

Production, Initial Production Rates & Product Type Information

References to petroleum, crude oil, natural gas liquids (“NGLs”), natural gas and average daily production in this press release refer to the light and medium crude oil, tight crude oil, conventional natural gas, shale gas and NGLs product types, as applicable, as defined in NI 51-101, except as noted below.

NI 51-101 includes condensate within the NGLs product type. The Company has disclosed condensate as combined with crude oil and separately from other NGLs since the price of condensate as compared to other NGLs is currently significantly higher and the Company believes that this crude oil and condensate presentation provides a more accurate description of its operations and results therefrom. Crude oil therefore refers to light oil, medium oil, tight oil and condensate. NGLs refers to ethane, propane, butane and pentane combined. Natural gas refers to conventional natural gas and shale gas combined.

Any reference in this news release to initial production rates (IP(90), IP(180)) are useful in confirming the presence of hydrocarbons, however such rates are not determinative of the rates at which such wells will continue production and decline thereafter. While encouraging, readers are cautioned not to place reliance on such rates in calculating the aggregate production for Whitecap.

The Company’s average daily production for the three months and year ended December 31, 2025 and 2024, and the six months ended December 31, 2025 and the forecast average daily production for 2026 (midpoint) disclosed in this press release consists of the following product types, as defined in NI 51-101 (other than as noted above with respect to condensate) and using a conversion ratio of 1 Bbl : 6 Mcf where applicable:

SPECIFIED FINANCIAL MEASURES

This press release includes various specified financial measures, including non-GAAP financial measures, non-GAAP ratios, capital management measures and supplementary financial measures as further described herein. These financial measures are not standardized financial measures under International Financial Reporting Standards (“IFRS Accounting Standards” or, alternatively, “GAAP”) and, therefore, may not be comparable with the calculation of similar financial measures disclosed by other companies.

“Acquisition capital” and “development capital” are non-GAAP financial measures, and “F&D costs”, “FD&A costs” and “recycle ratio” are non-GAAP ratios. See “Oil and Gas Metrics”.

“Annualized funds flow” is a capital management measure that is used by management as a substitute for annual funds flow when a material transaction (such as the strategic combination with Veren) or other material change occurs during the middle of the year and as a result annual funds flow is less meaningful. It is calculated by grossing up the applicable number of days being analyzed (such as a quarter or half year) to 365. Annualized funds flow referred to in this press release is calculated based on Whitecap’s funds flow for the fourth quarter of 2025 of $882 million, which equates to an estimated annualized funds flow of $3.5 billion.

“Average realized prices” for crude oil, NGLs and natural gas are supplementary financial measures calculated by dividing each of these components of petroleum and natural gas revenues, disclosed in Note 15 “Revenue” to the Company’s audited annual consolidated financial statements for the year ended December 31, 2025, by their respective production volumes for the period.

“Free cash flow” is a non-GAAP financial measure calculated as operating netback less expenditures on PP&E. Management believes that free cash flow provides a useful measure of the asset and project level contributions to Company profitability. Free cash flow is not a standardized financial measure under IFRS Accounting Standards and, therefore, may not be comparable with the calculation of similar financial measures disclosed by other entities. The most directly comparable financial measure to free cash flow disclosed in the Company’s primary financial statements is cash flow from operating activities. Refer to the “Cash Flow from Operating Activities, Funds Flow and Free Funds Flow” section of Whitecap’s management’s discussion and analysis for the year ended December 31, 2025 which is incorporated herein by reference, and available on SEDAR+ at sedarplus.ca.

“Free funds flow” is a non-GAAP financial measure calculated as funds flow less expenditures on PP&E. Management believes that free funds flow provides a useful measure of Whitecap’s ability to increase returns to shareholders and to grow the Company’s business. Free funds flow is not a standardized financial measure under IFRS Accounting Standards and, therefore, may not be comparable with the calculation of similar financial measures disclosed by other entities. The most directly comparable financial measure to free funds flow disclosed in the Company’s primary financial statements is cash flow from operating activities. Refer to the “Cash Flow from Operating Activities, Funds Flow and Free Funds Flow” section of our management’s discussion and analysis for the three months and year ended December 31, 2025 which is incorporated herein by reference, and available on SEDAR+ at sedarplus.ca. In addition, see the following table which reconciles cash flow from operating activities to funds flow and free funds flow:

“Funds flow”, “funds flow basic ($/share)” and “funds flow diluted ($/share)” are capital management measures and are key measures of operating performance as they demonstrate Whitecap’s ability to generate the cash necessary to pay dividends, repay debt, make capital investments, and/or to repurchase common shares under the Company’s normal course issuer bid. Management believes that by excluding the temporary impact of changes in non-cash operating working capital, funds flow, funds flow basic ($/share) and funds flow diluted ($/share) provide useful measures of Whitecap’s ability to generate cash that are not subject to short-term movements in non-cash operating working capital. Whitecap reports funds flow in total and on a per share basis (basic and diluted), which is calculated by dividing funds flow by the weighted average number of basic shares and weighted average number of diluted shares outstanding for the relevant period. See Note 5(f)(ii) “Capital Management – Funds Flow” in the Company’s audited annual consolidated financial statements for the year ended December 31, 2025 for additional disclosures.

“Net Debt” is a capital management measure that management considers to be key to assessing the Company’s liquidity. See Note 5(f)(i) “Capital Management – Net Debt and Total Capitalization” in the Company’s audited annual consolidated financial statements for the year ended December 31, 2025 for additional disclosures. The following table reconciles the Company’s long-term debt to net debt:

“Net debt to annualized funds flow” is a supplementary financial measure determined by dividing net debt for the applicable period by annualized funds flow. Net debt to annualized funds flow is not a standardized measure and therefore may not be comparable with the calculation of similar measures by other entities.

“Operating netback” is a non-GAAP financial measure determined by adding marketing revenues and processing & other income, deducting realized losses on commodity risk management contracts or adding realized gains on commodity risk management contracts and deducting tariffs, royalties, operating expenses, transportation expenses and marketing expenses from petroleum and natural gas revenues. The most directly comparable financial measure to operating netback disclosed in the Company’s primary financial statements is petroleum and natural gas sales. Operating netback is a measure used in operational and capital allocation decisions. Operating netback is not a standardized financial measure under IFRS Accounting Standards and, therefore, may not be comparable with the calculation of similar financial measures disclosed by other entities. For further information, refer to the “Operating Netbacks” section of our management’s discussion and analysis for the three months and year ended December 31, 2025, which is incorporated herein by reference, and available on SEDAR+ at sedarplus.ca. A reconciliation of operating netbacks to petroleum and natural gas revenues is set out below:

“Operating netback ($/boe)” is a non-GAAP ratio calculated by dividing operating netbacks by the total production for the period. Operating netback is a non-GAAP financial measure component of operating netback per boe. Operating netback per boe is not a standardized financial measure under IFRS Accounting Standards and, therefore, may not be comparable with the calculation of similar financial measures disclosed by other entities. Presenting operating netback on a per boe basis allows management to better analyze performance against prior periods on a comparable basis.

“Per boe” or “($/boe)” disclosures for petroleum and natural gas sales, royalties, operating expenses, transportation expenses and marketing expenses are supplementary financial measures that are calculated by dividing each of these respective GAAP measures by the Company’s total production volumes for the period.

“Petroleum and natural gas revenues ($/boe)”, “Tariffs ($/boe)”, “Processing and other income ($/boe)” and “Marketing revenues ($/boe)” are supplementary financial measures calculated by dividing each of these components of petroleum and natural gas sales, disclosed in Note 15 “Revenue” to the Company’s audited annual consolidated financial statements for the year ended December 31, 2025, by the Company’s total production volumes for the period.

“Realized gain on commodity contracts ($/boe)” is a supplementary financial measure calculated by dividing realized gain on commodity contracts, disclosed in Note 5(e) “Financial Instruments and Risk Management – Market Risk” to the Company’s audited annual consolidated financial statements for the year ended December 31, 2025, by the Company’s total production volumes for the period.

“Total shareholder return” is a supplementary financial measure calculated as the sum of the annual base dividend and normal course issuer bid yield and annual per share production growth expressed on a per share basis. Management believes that total shareholder return provides a useful measure of the return characteristics of various capital allocation decisions. Total shareholder return is not a standardized measure under IFRS accounting standards and therefore may not be comparable with the calculation of similar measures by other entities.

Per Share Amounts

Per share amounts noted in this press release are based on fully diluted shares outstanding unless noted otherwise.

SOURCE Whitecap Resources Inc.

 

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