WHITECAP RESOURCES INC. CONTINUES OPERATIONAL MOMENTUM AND ACHIEVES RECORD PRODUCTION

USA - English

CALGARY, AB, July 24, 2024 /CNW/ - Whitecap Resources Inc. ("Whitecap" or the "Company") (TSX: WCP) is pleased to report its operating and unaudited financial results for the three and six months ended June 30, 2024.

Selected financial and operating information is outlined below and should be read with Whitecap's unaudited interim consolidated financial statements and related management's discussion and analysis for the three and six months ended June 30, 2024 which are available at www.sedarplus.ca and on our website at www.wcap.ca.

Financial ($ millions except for share amounts)	Three Months ended Jun. 30		Six Months ended Jun. 30
	2024	2023	2024	2023
Petroleum and natural gas revenues	980.4	797.9	1,848.7	1,681.6
Net income	244.5	175.4	304.3	438.0
Basic ($/share)	0.41	0.29	0.51	0.72
Diluted ($/share)	0.41	0.29	0.51	0.72
Funds flow ^1	426.4	415.1	810.4	863.1
Basic ($/share) ^1	0.71	0.69	1.35	1.43
Diluted ($/share) ^1	0.71	0.68	1.35	1.41
Dividends declared	109.2	87.7	218.3	175.4
Per share	0.18	0.15	0.37	0.29
Expenditures on property, plant and equipment ^2	203.8	217.8	597.0	471.4
Free funds flow ^1	222.6	197.3	213.4	391.7
Net Debt ^1	1,297.0	1,361.2	1,297.0	1,361.2
Operating
Average daily production
Crude oil (bbls/d)	93,663	82,649	91,235	84,452
NGLs (bbls/d)	20,701	15,448	20,052	16,048
Natural gas (Mcf/d)	377,700	294,412	373,200	303,734
Total (boe/d) ^3	177,314	147,166	173,487	151,122
Average realized Price ^1,4
Crude oil ($/bbl)	102.06	90.59	95.71	91.17
NGLs ($/bbl)	34.88	33.58	34.83	40.76
Natural gas ($/Mcf)	1.30	2.59	1.95	3.08
Petroleum and natural gas revenues ($/boe) ^1	60.76	59.58	58.55	61.48
Operating Netback ($/boe) ^1
Petroleum and natural gas revenues^1	60.76	59.58	58.55	61.48
Tariffs ^1	(0.42)	(0.50)	(0.43)	(0.52)
Processing & other income ^1	0.71	1.08	0.74	0.96
Marketing revenues ^1	3.95	5.06	3.91	4.84
Petroleum and natural gas sales ^1	65.00	65.22	62.77	66.76
Realized gain on commodity contracts ^1	0.28	0.89	0.32	0.77
Royalties ^1	(10.09)	(9.57)	(9.77)	(10.56)
Operating expenses ^1	(13.49)	(15.16)	(13.87)	(14.55)
Transportation expenses ^1	(2.12)	(2.23)	(2.09)	(2.18)
Marketing expenses ^1	(3.91)	(5.08)	(3.88)	(4.83)
Operating netbacks	35.67	34.07	33.48	35.41
Share information (millions)
Common shares outstanding, end of period	599.4	605.8	599.4	605.8
Weighted average basic shares outstanding	598.8	605.2	598.4	605.6
Weighted average diluted shares outstanding	602.1	609.2	601.9	610.1

MESSAGE TO SHAREHOLDERS

Whitecap's operational momentum continued into the second quarter after an active first quarter drilling program and the start-up of our Musreau facility with record quarterly volumes of 177,314 boe/d, consisting of 114,364 bbls/d of oil and NGLs and 377,700 mcf/d of natural gas. Strong production results across our Montney and Duvernay assets as well as our conventional assets in Alberta and Saskatchewan contributed to production being higher than our internal forecast of 170,500 boe/d in the quarter.

Funds flow of $426 million ($0.71 per share) benefitted from the strong operational results and continued crude oil price strength and, after capital expenditures of $204 million, Whitecap generated free funds flow of $223 million in the second quarter. We returned approximately $110 million to shareholders during the quarter through our base dividend and share repurchases under our normal course issuer bid ("NCIB").

Our balance sheet continues to be in excellent shape with low leverage and ample liquidity. Net debt at the end of the second quarter was $1.3 billion (0.6x Debt to EBITDA⁵) on total capacity of $2.9 billion.

We also significantly improved our balance sheet with the partial infrastructure dispositions we press released on July 2, 2024, for gross proceeds of $520 million. The 50% working interest sale of our Musreau 05-09 facility to Topaz Energy Corp. closed on June 24, 2024, and the 50% working interest sale of our 15-07 Kaybob complex to Pembina Gas Infrastructure ("PGI") is expected to close in the third quarter of this year.

We provide the following second quarter and year to date 2024 financial and operating highlights:

• Production Growth. Strong operational execution resulted in record average production of 177,314 boe/d in the second quarter or 4% production per share growth⁶ compared to the first quarter of this year and 22% production per share growth compared to the second quarter of the prior year.
• Funds Flow. Second quarter funds flow of $426 million ($0.71 per share) increased 11% per share compared to the first quarter of this year and increased 4% per share compared to the second quarter of the prior year. Our production base is 64% light oil and liquids and with WTI prices averaging over $110/bbl in Canadian dollars, oil and liquids represented 95% of our second quarter petroleum and natural gas revenue.
• Drilling Program. Second quarter capital expenditures were $204 million and of the 27 wells spud during the second quarter, nine were Montney and Duvernay, and 18 were conventional. We brought 33 (27.4 net) wells on production during the second quarter, including three Duvernay wells at Kaybob and four Montney wells at Musreau during April.
• Return of Capital. For the six months ended June 30, 2024, we have returned $220 million to shareholders through our monthly dividend of $0.0608 per share and share repurchases under our NCIB. Our NCIB was renewed in the second quarter, providing for up to 59.1 million shares that may be repurchased prior to May 22, 2025.
• Balance Sheet Strength. Quarter end net debt of $1.3 billion equated to a debt to EBITDA ratio of 0.6 times and an EBITDA to interest expense ratio⁵ of 27.6 times, both well within our debt covenants of not greater than 4.0 times and not less than 3.5 times, respectively.

OPERATIONS UPDATE

Montney & Duvernay Assets

We run a continuous two rig program in the Montney and Duvernay and have grown production by 27% over the past year and a half to approximately 61,000 boe/d from 48,000 boe/d in the fourth quarter of 2022. Our strategic partnership with PGI and the funding of Lator phase 1 as press released on July 2, 2024, is an important milestone for future growth in the Montney and Duvernay to 100,000 boe/d over the next five years.

Our rigorous technical analysis and customized pad designs have enabled us to continually refine our approach to asset development, while at the same time our assets have performed better than initial expectations and provided increased confidence in the future deliverability of these areas. Our first eight Montney wells at Musreau have extended this trend with average IP(90) rates of 1,600 boe/d per well (70% liquids) which is 19% above our expectations.

We are currently completing a four well pad at Musreau, our third pad overall and second targeting both the D2 and D3 Montney intervals. The thickness of pay and high liquids content at Musreau is favorable to multi-bench development and we expect this pad to be on production later in the third quarter.

We recently brought 3 (3.0 net) Duvernay wells on production at Kaybob and we will bring an additional 5 (5.0 net) Duvernay wells and 10 (10.0 net) Montney wells on production in the second half of the year.

Conventional Assets

Strong results from our conventional drilling program continued into the second quarter with results exceeding expectations across our asset base. Our second half drilling program is now underway, with six currently active rigs and plans to drill a total of 76 (68.9 net) wells on our conventional assets before year end.

Recent results from our Frobisher drilling program in Southeast Saskatchewan highlight the attractiveness of these light oil weighted assets. Production from our first quarter program is above our expectations and strong crude oil prices are improving the already robust economics, accelerating our projected capital payout⁷ on these recent wells to less than six months. Over a three year period, these wells are projected to pay out our capital investment three times. We plan to drill 26 (23.8 net) Frobisher wells in the second half of the year.

Our Central Alberta Glauconite assets have seen steady improvement since first entering the play in 2021. We have brought 12 (11.7 net) Glauconite wells on production since the start of the year, with results continuing to exceed our expectations. The economics are further enhanced by high liquids rates as our recent 6 (5.9 net) wells have exceeded forecasted liquids rates by 40% in the first 90 days on production. We plan to drill 6 (6.0 net) Glauconite wells in the second half of the year.

The focus of our Viking program in West Saskatchewan is to improve long term free cash flow generation through continued operational efficiency enhancements and cost savings. On our recently consolidated Viking assets at Elrose, we recently spud our first 1.5-mile extended reach horizonal well, which will be a key initiative for potential inventory enhancement in the area. Initial well results on our 2024 Elrose program are in line with our expectations and higher than historical results, while we have also initiated work to reduce operating costs in the area as we move forward. In aggregate, we plan to drill 32 (32.0 net) Viking wells in the second half of the year on existing and recently acquired lands.

OUTLOOK

Operational and financial performance through the first half of the year has been exceptional and we will look to continue the momentum through the second half of 2024 and into 2025. Results across our Montney and Duvernay assets are increasing the confidence in the future deliverability of these assets and the economics of the 2,462 locations⁸ in inventory, while our focus on profitability and sustainability within our conventional asset base will further enhance the corporate free cash flow capabilities from the 3,980 locations in inventory.

Our 2024 production and capital spending guidance of 167,000 – 172,000 boe/d (64% liquids) and $0.9 - $1.1 billion, respectively, is being maintained.

Our balance sheet is in excellent shape with pro forma net debt below $900 million. We plan to allocate $200 million of the partial infrastructure disposition proceeds to share repurchases under our NCIB in the second half of 2024, of which $25 million has been executed to date in July, with forecast net debt of below $1 billion at year end⁹.

On behalf of our employees, management team and Board of Directors, we would like to thank our shareholders for their continued support.

NOTES

^1	Funds flow, funds flow basic ($/share), funds flow diluted ($/share) and net debt are capital management measures. Average realized price and per boe disclosure figures are supplementary financial measures. Operating netback and free funds flow are non-GAAP financial measures. Operating netbacks ($/boe) is a non-GAAP ratio. Refer to the Specified Financial Measures section in this press release for additional disclosure and assumptions.
^2	Also referred to herein as "capital expenditures", "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 and Product Type Information in this press release for additional disclosure.
^4	Prior to the impact of risk management activities and tariffs.
^5	Debt to EBITDA ratio and EBITDA to interest expense ratio are specified financial measures that are calculated in accordance with the financial covenants in our credit agreement.
^6	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.
^7	Also referred to herein as "half-cycle payout". Refer to Oil and Gas Metrics in this press release for additional disclosure
^8	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.
^9	Based on the following strip commodity pricing and exchange rate assumptions for the remainder of 2024: US$77/bbl WTI, $1.50/GJ AECO, USD/CAD of $1.37.

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 Thursday, July 25, 2024.

The conference call dial-in number is: 1-888-390-0605 or [phone] or [phone]

A live webcast of the conference call will be accessible on Whitecap's website at www.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 forecasts for average daily production (including by product type and the proportional liquids production) and capital expenditures for 2024; our belief that our balance sheet is in excellent shape with low leverage and ample liquidity; our expectation that the PGI transaction will close in the third quarter; our expectation for future growth in the Montney and Duvernay to 100,000 boe/d over the next five years; our belief that the thickness of pay and high liquids content at Musreau is favourable to multi-bench development; our expectations to bring on our third pad at Musreau later in the third quarter; our plans to bring 5 (5.0 net) Duvernay wells and 10 (10.0 net) Montney wells on production in the second half of the year; our plans to drill a total of 76 (68.9 net) wells on our conventional assets before year end; our projection for capital payout in less than six months on our recent Frobisher wells and that over a three year period the wells will pay out three times; our plans to drill 26 (23.8 net) Frobisher wells in the second half of the year; our plans to drill 6 (6.0 net) Glauconite wells in the second half of the year; our plans to drill 32 (32.0 net) Viking wells in the second half of this year on existing and recently acquired lands; our belief that results across our Montney and Duvernay assets are increasing the confidence in the future deliverability of these assets and economics of our 2,462 locations in inventory; our belief that our focus on profitability and sustainability within our conventional asset base will further enhance the corporate free cash flow capabilities from the 3,980 locations in inventory; our forecasted pro forma net debt; our plans to allocate $200 million of the partial infrastructure disposition proceeds to share repurchases under our NCIB; and, our forecast for net debt at year end.

The forward-looking information is based on certain key expectations and assumptions made by our management, including: that the disposition to PGI will occur on the terms and timing disclosed herein; that we will continue to conduct our operations in a manner consistent with past operations except as specifically noted herein (and for greater certainty, except with respect to the proposed disposition to PGI, 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 rising and/or sustained high inflation rates and 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; reserve 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; 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 exchange rate forecasts for 2024 specifically set forth 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 our disposition to PGI does not close on the terms and/or on the timetable currently anticipated or at all; 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 2024 forecast (including for commodity prices and exchange rates); 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 high inflation rates, high 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, 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 (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 our forecast 2024 capital expenditures; our pro forma net debt of $900 million; our plan to allocate $200 million to share repurchases under our NCIB in the second half of 2024; our forecast for year end net debt of below $1 billion, 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

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.

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, 2023 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 2,462 (2,213 net) Montney and Duvernay drilling locations identified herein, 262 (226 net) are proved locations, 118 (102 net) are probable locations, and 2,082 (1,885 net) are unbooked locations.
• Of the 3,980 (3,406 net) conventional drilling locations identified herein, 1,318 (1,148 net) are proved locations, 201 (169 net) are probable locations, and 2,461 (2,089 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 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.

Any reference in this news release to initial production rates (IP(90)) 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 and six months ended June 30, 2024 and 2023, the forecast average daily production for Q2/2024 and 2024 (midpoint), and the average daily production rate per well for our first 8 (8.0 net) Montney wells at Musreau 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 Corporate	1H 2024	1H 2023	Q2 2024	Q2 2023
Light and medium oil (bbls/d)	76,352	74,284	76,691	72,429
Tight oil (bbls/d)	14,883	10,168	16,972	10,220
Crude oil (bbls/d)	91,235	84,452	93,663	82,649
NGLs (bbls/d)	20,052	16,048	20,701	15,448
Shale gas (Mcf/d)	224,088	173,379	225,167	171,601
Conventional natural gas (Mcf/d)	149,112	130,355	152,533	122,811
Natural gas (Mcf/d)	373,200	303,734	377,700	294,412
Total (boe/d)	173,487	151,122	177,314	147,166

Whitecap Corporate / Initial Production Rates		2024 Guidance (Mid-Point)	Q2 2024 Forecast	Musreau IP(90) per well
Light and medium oil (bbls/d)		75,200	76,000	-
Tight oil (bbls/d)		14,800	14,000	1,058
Crude oil (bbls/d)		90,000	90,000	1,058
NGLs (bbls/d)		18,000	19,000	62
Shale gas (Mcf/d)		220,000	216,000	2,880
Conventional natural gas (Mcf/d)		149,000	153,000	-
Natural gas (Mcf/d)		369,000	369,000	2,880
Total (boe/d)		169,500	170,500	1,600

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 "capital payout" or "half-cycle payout", which is the time period for the operating netback of a well to equate to the individual cost of drilling, completing and equipping the well. Management uses half-cycle payout as a measure of capital efficiency of a well to make capital allocation decisions. 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. 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.

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.

"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 16 "Revenue" to the Company's unaudited interim consolidated financial statements for the three and six months ended June 30, 2024, by their respective production volumes for the period.

"Free funds flow" is a non-GAAP financial measure calculated as funds flow less expenditures on property, plant and equipment ("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 and six months ended June 30, 2024 which is incorporated herein by reference, and available on SEDAR+ at www.sedarplus.ca. In addition, see the following table which reconciles cash flow from operating activities to funds flow and free funds flow:

	Three Months ended Jun. 30,		Six Months ended Jun. 30,
($ millions, except per share amounts)	2024	2023	2024	2023
Cash flow from operating activities	505.0	414.9	857.5	883.5
Net change in non-cash working capital items	(78.6)	0.2	(47.1)	(20.4)
Funds flow	426.4	415.1	810.4	863.1
Expenditures on PP&E	203.8	217.8	597.0	471.4
Free funds flow	222.6	197.3	213.4	391.7
Funds flow per share, basic	0.71	0.69	1.35	1.43
Funds flow per share, diluted	0.71	0.68	1.35	1.41

"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(e)(ii) "Capital Management – Funds Flow" in the Company's unaudited interim consolidated financial statements for the three and six months ended June 30, 2024 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 and six months ended June 30, 2024 for additional disclosures. The following table reconciles the Company's long-term debt to net debt:

Net Debt ($ millions)		Jun. 30, 2024	Jun. 30, 2023	Dec. 31, 2023
Long-term debt		1,190.1	1,259.5	1,356.1
Accounts receivable		(421.6)	(357.5)	(400.2)
Deposits and prepaid expenses		(34.7)	(28.1)	(32.9)
Non-current deposits		(82.9)	-	(82.9)
Accounts payable and accrued liabilities		609.6	458.1	509.0
Dividends payable		36.5	29.2	36.4
Net Debt		1,297.0	1,361.2	1,385.5

"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 and six months ended June 30, 2024, which is incorporated herein by reference, and available on SEDAR+ at www.sedarplus.ca. A reconciliation of operating netbacks to petroleum and natural gas revenues is set out below:

	Three Months ended Jun. 30,		Six Months ended Jun. 30,
Operating Netbacks ($ millions)	2024	2023	2024	2023
Petroleum and natural gas revenues	980.4	797.9	1,848.7	1,681.6
Tariffs	(6.8)	(6.7)	(13.6)	(14.3)
Processing & other income	11.5	14.4	23.5	26.2
Marketing revenues	63.8	67.8	123.6	132.5
Petroleum and natural gas sales	1,048.9	873.4	1,982.2	1,826.0
Realized gain on commodity contracts	4.5	11.9	10.1	21.0
Royalties	(162.8)	(128.2)	(308.4)	(288.9)
Operating expenses	(217.7)	(203.0)	(438.0)	(398.1)
Transportation expenses	(34.2)	(29.8)	(66.0)	(59.6)
Marketing expenses	(63.1)	(68.0)	(122.4)	(132.2)
Operating netbacks	575.6	456.3	1,057.5	968.2

"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 16 "Revenue" to the Company's unaudited interim consolidated financial statements for the three and six months ended June 30, 2024, 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(d) "Financial Instruments and Risk Management – Market Risk" to the Company's unaudited interim consolidated financial statements for the three and six months ended June 30, 2024, by the Company's total production volumes for the period.

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.

For further information: Grant Fagerheim, President & CEO, or Thanh Kang, Senior Vice President & CFO, Whitecap Resources Inc., 3800, 525 - 8th Avenue SW, Calgary, AB T2P 1G1, [phone], www.wcap.ca, [email protected]