News Releases

WHITECAP DELIVERS RECORD 2025 RESULTS, EXCEEDS GUIDANCE AND SUCCESSFULLY INTEGRATES VEREN

CALGARY, ALBERTA – 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.

Financial ($ millions except for share amounts)	Three months ended Dec. 31		Year ended Dec. 31
	2025	2024	2025	2024
Petroleum and natural gas revenues	1,666.0	926.1	5,633.8	3,665.7
Net income	307.2	233.8	984.6	812.3
Basic ($/share)	0.25	0.40	0.99	1.37
Diluted ($/share)	0.25	0.40	0.99	1.36
Funds flow 1	882.1	412.8	2,937.8	1,632.2
Basic ($/share) 1	0.73	0.70	2.96	2.74
Diluted ($/share) 1	0.72	0.70	2.95	2.73
Dividends declared	221.4	107.1	735.5	433.3
Per share	0.18	0.18	0.73	0.73
Expenditures on property, plant and equipment 2	696.1	261.4	2,049.3	1,131.1
Free funds flow 1	186.0	151.4	888.5	501.1
Net debt 1	3,394.0	933.1	3,394.0	933.1
Operating
Average daily production
Crude oil (bbls/d)	183,758	94,965	152,705	92,449
NGLs (bbls/d)	48,661	20,797	38,450	20,371
Natural gas (Mcf/d)	883,124	365,809	696,542	368,610
Total (boe/d) 3	379,606	176,730	307,245	174,255
Average realized price 1,4
Crude oil ($/bbl)	75.50	92.46	82.65	94.52
NGLs ($/bbl)	33.62	34.23	35.19	34.47
Natural gas ($/Mcf)	2.94	1.57	2.10	1.56
Petroleum and natural gas revenues ($/boe) 1	47.70	56.96	50.24	57.48
Operating netback ($/boe) 1
Petroleum and natural gas revenues1	47.70	56.96	50.24	57.48
Tariffs 1	(0.16)	(0.40)	(0.26)	(0.42)
Processing & other income 1	0.40	0.61	0.47	0.69
Marketing revenues 1	0.70	4.37	2.24	4.00
Petroleum and natural gas sales 1	48.64	61.54	52.69	61.75
Realized gain on commodity contracts 1	1.77	0.84	1.48	0.61
Royalties 1	(5.52)	(9.11)	(6.59)	(9.41)
Operating expenses 1	(12.24)	(13.70)	(12.83)	(13.71)
Transportation expenses 1	(3.68)	(2.24)	(3.19)	(2.13)
Marketing expenses 1	(0.72)	(4.37)	(2.22)	(3.97)
Operating netbacks	28.25	32.96	29.34	33.14
Share information (millions)
Common shares outstanding, end of period	1,213.9	587.5	1,213.9	587.5
Weighted average basic shares outstanding	1,213.8	587.6	993.1	594.9
Weighted average diluted shares outstanding	1,219.1	591.4	997.3	598.1

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.

OPERATIONS 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.

NOTES
¹    Funds flow, funds flow basic ($/share), funds flow diluted ($/share), annualized funds flow and net debt are capital management measures. Average realized price, net debt to annualized funds flow ratio, per boe disclosure figures and total shareholder return are supplementary financial measures. Operating netback, free cash flow and free funds flow are non-GAAP financial measures. Operating netbacks ($/boe), F&D costs, FD&A costs and recycle ratio are non-GAAP ratios. Refer to the Specified Financial Measures section and Oil and Gas Metrics section in this press release for additional disclosure and assumptions.
²   Also referred to herein as "capital expenditures", "capital spending", "capital investment" and "capital budget".
³   Disclosure of production on a per boe basis in this press release consists of the constituent product types and their respective quantities disclosed herein. Refer to Barrel of Oil Equivalency and Production, Initial Production Rates & Product Type Information in this press release for additional disclosure.
⁴   Prior to the impact of risk management activities and tariffs.
⁵   Production per share is the Company's total crude oil, NGL and natural gas production volumes for the applicable period divided by the weighted average number of diluted shares outstanding for the applicable period. Production per share growth is determined in comparison to the applicable comparative period.
⁶   See "Production Replacement Ratio and Reserve Life Index" for disclosures regarding reserve life index (RLI).
⁷   Disclosure of drilling locations in this press release consists of proved, probable, and unbooked locations and their respective quantities on a gross and net basis as disclosed herein. Refer to Drilling Locations in this press release for additional disclosure.

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

	Company Share (Gross) Reserves
Description	Light & Medium Crude Oil (MMbbl)	Tight Crude Oil (MMbbl)	Conventional Natural Gas (Bcf)	Shale Gas (Bcf)	Natural Gas Liquids (MMbbl)	Total (MMboe)
Proved developed producing	253	43	368	1,075	148	685
Proved developed non-producing	3	4	12	133	16	47
Proved undeveloped	108	83	164	1,831	208	732
Total proved	365	130	544	3,039	372	1,464
Probable	141	85	228	1,834	191	761
Total proved plus probable	506	215	772	4,873	563	2,225

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

	Before Tax Net Present Value ($ millions) (1)
	Discount Rate
Reserves Category	0%	5%	10%	15%	20%
Proved developed producing	12,281	11,028	9,443	8,249	7,361
Proved developed non-producing	984	770	631	533	460
Proved undeveloped	10,331	6,687	4,439	2,973	1,973
Total Proved	23,597	18,484	14,513	11,755	9,794
Total Probable	18,093	10,714	7,167	5,185	3,964
Total Proved + Probable	41,690	29,199	21,679	16,940	13,758

⁽¹⁾     Includes abandonment and reclamation costs as defined in NI 51-101 for all of our facilities, pipelines and wells including those without reserves assigned. Abandonment and reclamation costs associated with facilities, pipelines and wells without associated reserves would not be considered material in the determination of the Company's future net revenue.

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.

($ millions)	Total Proved	Total Proved plus Probable
2026	1,930	1,963
2027	2,814	2,896
2028	3,085	3,255
2029	2,586	3,100
2030	1,339	2,290
Remainder	1,059	3,585
Total FDC, Undiscounted	12,813	17,090
Total FDC, Discounted at 10%	9,806	12,364

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:

	2025	2024	2023	Three Year Weighted Average
Proved Developed Producing
F&D costs per boe (1)	$17.19	$16.01	$14.69	$16.25
F&D recycle ratio (2)	1.7x	2.1x	2.4x	2.0x
FD&A costs per boe (3)	$22.48	$8.84	$17.24	$17.60
FD&A recycle ratio (2)	1.3x	3.7x	2.1x	2.1x
Total Proved
F&D costs per boe (1)	$17.13	$19.24	$17.63	$17.81
F&D recycle ratio (2)	1.7x	1.7x	2.0x	1.8x
FD&A costs per boe (3)	$19.97	$12.47	$22.55	$18.66
FD&A recycle ratio (2)	1.5x	2.7x	1.6x	1.8x
Total Proved Plus Probable
F&D costs per boe (1)	$17.17	$15.46	$20.53	$17.58
F&D recycle ratio (2)	1.7x	2.1x	1.7x	1.8x
FD&A costs per boe (3) (4)	$15.81	$10.03	nm	nm
FD&A recycle ratio (2) (4)	1.9x	3.3x	nm	nm

⁽¹⁾     F&D costs are non-GAAP ratios and are calculated as the sum of development capital of $2.0 billion (excluding corporate and capitalized general and administrative expenses ("G&A")) plus the change in FDC for the period of $74 million (PDP), $186 million (1P) and $629 million (2P), divided by the change in reserves volumes that are characterized as development for the period. See "Oil and Gas Metrics" and "Specified Financial Measures".
⁽²⁾     Recycle ratio is a non-GAAP ratio and is calculated as operating netback divided by F&D or FD&A costs. Our operating netback in 2025 was $29.34/boe. See "Oil and Gas Metrics" and "Specified Financial Measures".
⁽³⁾     FD&A costs are non-GAAP ratios and are calculated as the sum of development capital of $2.0 billion (excluding corporate and capitalized G&A) plus acquisition capital of $7.6 billion plus the change in FDC for the period of $74 million (PDP), $186 million (1P) and $629 million (2P), divided by the change in total reserves volumes, other than from production, for the period. See "Oil and Gas Metrics" and "Specified Financial Measures".
⁽⁴⁾     The impact of net dispositions in 2023 results in a very low denominator value and therefore the 2023 FD&A cost of $85.40 per boe is deemed not material ("nm") to our reserves performance measures.

Production Replacement Ratio 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.

	2025	2024	2023	Three Year Weighted Average
Proved Developed Producing
Production replacement (1)	383%	112%	71%	233%
RLI (years) (2)	4.9	5.7	5.9	5.4
Total Proved
Production replacement (1)	687%	123%	81%	382%
RLI (years) (2)	10.6	12.5	13.0	11.7
Total Proved Plus Probable
Production replacement (1)	1,011%	154%	16%	534%
RLI (years) (2)	16.1	18.7	19.2	17.5

⁽¹⁾     Production replacement ratio is calculated as total reserves additions (including acquisitions net of dispositions) divided by annual production. Whitecap’s production averaged 307,245 boe/d in 2025.
⁽²⁾     RLI is calculated as total Company share (gross) reserves divided by the annualized fourth quarter actual production of 379,606 boe/d.

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.

For further information:

Grant Fagerheim, President & CEO
or
Thanh Kang, Senior Vice President & CFO

Whitecap Resources Inc.
3800, 525 – 8^th Avenue SW
Calgary, AB T2P 1G1
(403) 266-0767
wcap.ca
InvestorRelations@wcap.ca

Refer to full press release for forward-looking statements and advisories.