WHITECAP RESOURCES INC. CLOSES THE VEREN COMBINATION CREATING A LEADING CANADIAN OIL AND NATURAL GAS PRODUCER, AND INCREASES PRODUCTION GUIDANCE

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12-05-2025

CALGARY, AB, May 12, 2025 /CNW/ - Whitecap Resources Inc. ("Whitecap" or the "Company") (TSX: WCP) is pleased to announce the successful closing of its strategic combination with Veren Inc. ("Veren") (TSX: VRN) (NYSE: VRN), creating the seventh largest oil and natural gas producer and the fifth largest natural gas producer in Canada. Whitecap is now the largest Alberta Montney and Duvernay landholder and a prominent light oil producer in Saskatchewan with an enviable portfolio of premium drilling opportunities which provides for decades of sustainable production and funds flow growth. We plan to leverage the combined asset base and technical expertise to drive incremental improvements to profitability and increased returns to shareholders.
The combined company will be led by Whitecap's management team along with an eleven-member Board of Directors including seven Whitecap directors: Ken Stickland (Chair), Grant Fagerheim (President & CEO), Vineeta Maguire, Glenn McNamara, Steve Nikiforuk, Brad Wall and Grant Zawalsky. The four new directors joining from the Veren Board of Directors are: Craig Bryksa, Jodi Jenson Labrie, Barbara Munroe and Myron Stadnyk. Stepping down from their roles as Whitecap directors are Mary-Jo Case and Chandra Henry. Whitecap would like to thank Ms. Case and Ms. Henry for their leadership, guidance and contributions as directors to the success of Whitecap.
NON-STRATEGIC ASSET DISPOSITIONS
Whitecap has entered into two agreements to dispose of certain non-strategic assets for aggregate consideration of $270 million, prior to any closing adjustments. The non-strategic assets include approximately 8,000 boe/d1 (90% liquids) of medium oil production in southwest Saskatchewan and an 8.333% working interest in a natural gas facility in the Kaybob region. The dispositions are expected to close on or before June 30, 2025, subject to customary closing conditions, with the proceeds directed toward our balance sheet.
2025 GUIDANCE
After accounting for the Veren combination and the non-strategic asset dispositions, we are increasing our average 2025 production forecast to 295,000 – 300,000 boe/d (63% liquids) on capital expenditures of approximately $2.0 billion for the year. For the second half of 2025, we expect production to average 363,000 – 368,000 boe/d (62% liquids) on capital expenditures of approximately $1.1 billion.
Unconventional
We plan to allocate approximately 75% of our second half capital budget to our Montney and Duvernay assets which includes drilling 67 (58.1 net) wells, of which 66 (63.5 net) wells are expected to come on stream in the second half of the year (including wells drilled in the first half of 2025). We are currently running 6 unconventional rigs focused in areas with established technical understanding and available infrastructure capacity.
Application of our unconventional development workflows on the acquired lands has already commenced and we will now proceed with the integration of the two technical teams and undertake detailed reviews of the respective assets. Through this process, we will investigate opportunities for overall enhancement of the asset base through variations on development, including well spacing, benching, completions technology, and drawdown strategies. As with our development to date, our priority remains on long-term value generation from these lands through deliberate progression of capital efficiency improvement initiatives.
Montney
At Musreau, we plan to drill a 6-well (6.0 net) pad late in the second quarter which will be completed in early 2026 as plant capacity becomes available. We are also investigating debottlenecking options at this facility in order to modestly enhance the pace of development of these lands, which could add 10% – 20% of incremental throughput.
In Kakwa, completions are scheduled to commence late in the second quarter on our latest 4-well (4.0 net) pad, with production onstream in the third quarter. This pad features inter-well spacing of 250 metres, consistent with our inter-well spacing pilots in Kakwa in 2023 which were successful in improving per-well recoveries. We are also anticipating the spud of an 8-well (1.6 net) non-op pad in the area, which will be drilled in later 2025 and on production in 2026.
In Lator, a planned 3-well (3.0 net) pad at 10-24-061-03W6 will continue to progress our technical delineation in this area. This pad is positioned to further confirm the productive capability of the core of our land base and quantify the impact of interaction between a variety of offset development conditions. Our 04-13 facility is expected to commence earthworks and civil construction in the second half of this year as we continue to progress towards a late 2026/early 2027 commissioning and startup. Costs of the facility are expected to remain within our original expectations of $250 - $300 million, funded through our strategic partnership with Pembina Gas Infrastructure.
In Gold Creek and Karr, we plan to drill 21 (21.0 net) wells in the second half of this year, building upon strong legacy results in this area. Our efforts will be focused on utilizing available infrastructure capacity that has been materially debottlenecked over the past twelve months. We plan to perform a detailed asset review through the third quarter, utilizing our unconventional workflow to assess the impact of well design changes, including plug-and-perf completions. We will assess the effectiveness of these changes while moderating risk exposure, consistent with our approach to drilling and completions optimization across our unconventional asset base over the years.
Duvernay
In the second half of the year, we plan to drill 35 (32.5 net) Duvernay wells with a focus on areas with good subsurface control and available infrastructure.
Included in those activities are 11 (11.0 net) wells in the volatile oil window of Kaybob North, and 24 (21.5 net) wells in the liquids-rich gas window of Kaybob South. We expect that this will result in our 15-07 gas processing facility operating at capacity of approximately 36,500 boe/d in the third quarter of 2025. Concurrently, a recently constructed connection to a nearby third-party processing facility will be commissioned which will allow for incremental productive capacity of approximately 7,000 boe/d.
We expect significant infrastructure synergies to come from the Kaybob area where we plan to reduce capital expenditure duplication on trunk lines, compression, and associated development infrastructure.
Conventional
We plan to invest approximately 25% of our second half capital budget on our conventional assets which includes drilling 91 (74.8 net) wells in Saskatchewan and 10 (5.2 net) wells in Alberta. Our conventional assets in both Saskatchewan and Alberta provide Whitecap with strong free funds flow generation to support our return of capital strategy to shareholders.
Saskatchewan
In eastern Saskatchewan, our second half of the year Frobisher program will be the most active with 25 (22.8 net) wells planned with two rigs. The majority of this activity commences in late September and will continue to focus on triple leg lateral wells to maximize royalty incentives and well economics. This program will continue to build off the momentum of our first quarter program which outperformed IP90 expectations by approximately 25%.
In western Saskatchewan, we plan to drill 18 (18.0 net) Viking wells in our legacy Kerrobert and Dodsland properties and in southwest Saskatchewan we plan to drill 17 (13.8 net) wells focused on the Shaunavon and Success formations. These areas are further supported by a low decline enhanced oil recovery ("EOR") base which provides for strong free funds flow generation.
At Viewfield, we plan to drill 17 (11.1 net) Bakken wells including 9 open hole multi-lateral wells ranging from 1.0 to 2.0 miles in length with approximately 8 legs per well. The remaining development will target historical horizontal multi-stage fracturing designs.
At Weyburn, where we own and operate a world class carbon capture, utilization and storage project, we plan to drill 14 (9.1 net) wells to continue to support the low 3% – 5% base decline rate in this area.
Alberta
Our conventional assets in Alberta will continue to focus on Cardium and Glauconite development with the drilling of 6 (3.6 net) Cardium wells in West Pembina and 3 (1.2 net) wells in the Glauconite. Both assets have continued to exceed our expectations with strong results and well design enhancements further improving the economics in these plays.
STRONG CREDIT PROFILE
Whitecap has also entered into a new $3 billion unsecured 4-year credit facility (the "New Facility") with our syndicate of banks which replaces Whitecap's existing credit facility. The New Facility, combined with our existing $1.4 billion investment grade senior notes and $223 million private placement notes, results in total credit capacity of $4.6 billion. At US$60/bbl WTI and $2.50/GJ AECO, net debt2 is expected to be approximately $3.4 billion by year end2, which represents a net debt to annualized funds flow ratio of approximately 1.0 times3 and leaves the Company with $1.2 billion of unutilized capacity.
Whitecap's materially improved business risk profile, low leverage and ample liquidity positions us well to navigate through the current market volatility and to execute on our long-term strategic priorities.
STRATEGIC PRIORITIES
We continue to prioritize balance sheet strength by ensuring capital expenditures and dividends are covered by our funds flow. Our capital investments are focused on capital efficiencies and free funds flow generation with a long-term organic production growth target of 3% – 5% per share4 enhanced by share repurchases. The dividend provides stable and reliable cash returns to shareholders during periods of commodity price volatility and is well supported by a best-in-class portfolio with decades of free funds flow generation and an excellent balance sheet with low leverage and ample liquidity.
The integration of Veren's assets is well underway and expected to be seamless given the significant operational overlap, our technical expertise in each of the areas and our proven ability to effectively acquire, integrate and optimize historical acquisitions. We will use our technical, operating and financial expertise to realize the previously identified $200 million of initial synergies over the next 6 – 12 months with the potential to further reduce our controllable costs and improve our capital efficiencies over the long term. We are very excited about the future potential of our consolidated portfolio and look forward to reporting back to shareholders on our progress.
NOTES
1
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 & Product Type Information in this press release for additional disclosure.
2
Based on the following commodity pricing and exchange rate assumptions for the remainder of 2025: US$60/bbl WTI, $2.50/GJ AECO and USD/CAD of $1.39.
3
Funds flow and net debt are capital management measures. Annualized funds flow and net debt to annualized funds flow ratio are supplementary financial measures. Refer to the Specified Financial Measures section in this press release for additional disclosure and assumptions.
4
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.
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 belief that we have an enviable portfolio of premium drilling opportunities that provides multi-decades of sustainable production and funds flow growth; our belief that we will leverage the combined asset base and technical expertise to drive incremental improvements to profitability and increased returns to shareholders; our expectation that each of the non-strategic asset dispositions will close on the anticipated terms and timing; our forecast for 2025 and second half 2025 production, including by product type; our forecast for 2025 and second half 2025 capital expenditures; our second half drilling program including the allocation by formation and the timing of on production; our expectations with respect to our application to our unconventional development workflows on acquired land and our plan to investigate opportunities for overall enhancement of the asset base through variations on development, including well spacing, benching, completions technology, and drawdown strategies; our expectation that our priority will remain on long-term generation from our acquired lands through deliberate progression of capital efficiency improvement initiatives; the anticipated timing for our drilling plans and available infrastructure capacity at Musreau; our belief that debottlenecking options at Musreau could add 10% - 20% of throughput; the anticipated timing for completions on our latest 4-well (4.0 net) pad at Kakwa and the anticipated timing for production coming onstream; our plans for the spud of an 8-well (1.6 net) non-op pad in the Kakwa, which is expected to be drilled in the later part of 2025 and on production in 2026; our belief that the planned 3-well (3.0 net) pad at 10-24-061-03W6 is positioned to further confirm the productive capability of the core of our land base and quantify the impact of interaction between a variety of offset development conditions; the anticipated timing of earthworks and civil construction of our 04-13 facility at Lator; our expectation for costs of the 04-13 facility and how such costs will be funded; our drilling plans for Gold Creek and Karr in the second half of 2025 and our expectation that our efforts will be focused on utilizing available infrastructure capacity; our plans to perform a detailed asset review through the third quarter, utilizing our unconventional workflow to assess the impact of well design changes, including plug-and-perf completions; our Duvernay drilling locations for the second half of this year and our expectation that we will focus on areas with good subsurface control and available infrastructure; our belief that our 15-07 gas processing facility will be operating at capacity in the third quarter of 2025 at approximately 36,500 boe/d and that concurrent with this timing, a recently constructed connection to a nearby third-party processing facility will be commissioned, which will allow for incremental productive capacity of approximately 7,000 boe/d; our expectation for significant infrastructure synergies to come from the Kaybob area where we plan to reduce capital expenditure duplication on trunk lines, compression, and associated development infrastructure; our plan to invest approximately 25% of our second half capital budget on our conventional assets; our belief that our conventional assets in both Saskatchewan and Alberta provide Whitecap with strong free funds flow generation to support our return of capital strategy to shareholders; that our second half Frobisher program will be the most active, the anticipated timing of such activity and that it will continue to focus on triple leg laterals to maximize royalty incentives and well economics; our drilling plans for western Saskatchewan; our belief that a low decline EOR base provides for strong free funds flow generation; our drilling plans for Viewfield and our expectation that the remaining development at Viewfield will target historical horizontal multi-stage fracturing designs; that our drilling program at Weyburn will continue to support the low 3 – 5% base decline rate in this area; our belief that strong results combined with well design enhancements are further improving the economics in the Cardium and Glauconite; our forecast for net debt of $3.4 billion at year end based on US$60/bbl WTI and $2.50/GJ AECO, which represents a debt to annualized funds flow ratio of approximately 1.0 times and leaves the Company with $1.2 billion of unused capacity; our belief that our materially improved business risk profile, low leverage and ample liquidity positions us well to navigate through the current market volatility and to execute on our long-term strategic priorities; that we will continue to prioritize balance sheet strength by ensuring capital expenditures and dividends are covered by our funds flow; our long term production growth target of 3% – 5% per share enhanced by share repurchases; our belief that the dividend provides stable and reliable cash returns to shareholders during periods of commodity price volatility and is well supported by a best-in-class portfolio with multi-decades of free funds flow generation and an excellent balance sheet with low leverage and ample liquidity; that the integration of Veren's assets is expected to be seamless given the significant operational overlap, our technical expertise in each of the areas and our proven ability to effectively acquire, integrate and optimize historical acquisitions; and our expectation that we will use our technical, operating and financial expertise to realize the $200 million of initial synergies identified over the next 6 – 12 months with the potential to further reduce our controllable costs and improve our capital efficiencies longer term.
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; the timing of the completion of the non-strategic asset dispositions disclosed herein and the satisfaction of all conditions precedent in a timely manner, including the receipt of applicable regulatory approvals, and that the disposition are completed on the terms contemplated in the respective agreements and that Whitecap realizes the anticipated benefits thereof; that we will continue to conduct our operations in a manner consistent with past operations except as specifically noted herein (and for greater certainty, other than the non-strategic dispositions described herein, 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, currency 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 currency exchange 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; results of operations; business prospects and opportunities; 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, including Veren; 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; the commodity pricing and currency exchange rate forecasts for 2025 and beyond referred to herein; 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 2025 forecast (including for commodity prices and currency 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 by 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 risk that the non-strategic asset dispositions disclosed herein are not completed on the anticipated terms or on the anticipated timing or at all, and/or that the dispositions do not result in the anticipated benefits; 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 currency 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, including with respect to Veren; failure to complete or realize the anticipated benefits of acquisitions or dispositions, including with respect to Veren; 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, currency 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 (www.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 the amount of cash consideration to be received by Whitecap from the non-strategic asset dispositions disclosed herein; the amount of capital expenditures that we expect to make in 2025 and the second half of 2025; our forecast of average daily production for 2025 and the second half of 2025: the costs of our 04-13 battery at Lator being still within our original expectations of $250 - $300 million; our forecast for year end net debt of approximately $3.4 billion and that it equates to a net debt to annualized funds flow ratio of 1.0 times; our anticipated unutilized debt capacity of approximately $1.0 billion in 2025; the $200 million of initial synergies estimated to be derived from the combination with Veren; and our forecast for commodity prices and the USD/CAD exchange rate in 2025; 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 & GAS ADVISORIES
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.
"Decline rate" is the reduction in the rate of production from one period to the next, expressed on an annual basis. Management of Whitecap uses decline rate to assess future productivity of Whitecap's assets.
Production & 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 National Instrument 51-101 ("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. Liquids refers to crude oil and NGLs combined.
The Company's forecast average daily production for the southwest Saskatchewan disposition, 2025 and the second half of 2025 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:
Whitecap CorporateSW Sask Disposition
2025
(mid-point)
2H/2025
(mid-point)
Light and medium oil (bbls/d)7,150
88,000
95,000
Tight oil (bbls/d)-
67,000
94,000
Crude oil (bbls/d)7,000
155,000
189,000NGLs (bbls/d)50
32,000
38,000Shale gas (Mcf/d)-
495,000
660,000
Conventional natural gas (Mcf/d)4,800
168,000
168,000
Natural gas (Mcf/d)4,800
663,000
828,000Total (boe/d)8,000
297,500
365,000
SPECIFIED FINANCIAL MEASURES
This press release includes various specified financial measures, including 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.
"Annualized funds flow" is a supplementary financial measure that is used by management as a substitute for annual funds flow when a material transaction (such as the business 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 the applicable number of days being analyzed (such as a quarter or half year) up to 365. Annualized funds flow for the purposes of the "net debt to annualized funds flow ratio" disclosed herein is calculated based on estimated funds flow for the fourth quarter of 2025.
"Funds flow" is a capital management measure and is a key measure of operating performance as it demonstrates 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 provides a useful measure of Whitecap's ability to generate cash that is not subject to short-term movements in non-cash operating working capital. 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 ended March 31, 2025 which is incorporated herein by reference, and available on SEDAR+ at www.sedarplus.ca. See also Note 5(e)(ii) "Capital Management – Funds Flow" in the Company's unaudited interim consolidated financial statements for the three months ended March 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(e)(i) "Capital Management – Net Debt and Total Capitalization" in the Company's unaudited interim consolidated financial statements for the three months ended March 31, 2025 for additional disclosures. The following table reconciles the Company's long-term debt to net debt:
Net Debt ($ millions)Mar. 31, 2025
Dec. 31, 2024
Mar. 31, 2024
Long-term debt826.2
1,023.8
1,392.6
Cash-
(362.3)
-
Accounts receivable(442.3)
(422.2)
(435.8)
Deposits and prepaid expenses(19.8)
(22.4)
(30.2)
Non-current deposits(86.6)
(86.6)
(82.9)
Accounts payable and accrued liabilities673.7
767.1
615.3
Dividends payable35.7
35.7
36.4
Net Debt986.9
933.1
1,495.4
"Net Debt to annualized funds flow ratio" is a supplementary financial measure determined by dividing net debt at the end of 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.
SOURCE Whitecap Resources Inc.
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