WHITECAP RESOURCES INC. ACHIEVES RECORD PRODUCTION, INCREASES GUIDANCE AND ANNOUNCES INVESTOR DAY

CALGARY, AB, April 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 months ended March 31, 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 months ended March 31, 2024 which are available at www.sedarplus.ca and on our website at www.wcap.ca.

Financial ($ millions except for share amounts and percentages)			Three Months ended Mar. 31
			2024	2023
Petroleum and natural gas revenues			868.3	883.7
Net income			59.8	262.6
Basic ($/share)			0.10	0.43
Diluted ($/share)			0.10	0.43
Funds flow ^1			384.0	448.0
Basic ($/share) ^1			0.64	0.74
Diluted ($/share) ^1			0.64	0.73
Dividends declared			109.1	87.7
Per share			0.18	0.15
Expenditures on property, plant and equipment ^2			393.2	253.6
Free funds flow ^1			(9.2)	194.4
Net Debt ^1			1,495.4	1,471.1
Operating
Average daily production
Crude oil (bbls/d)			88,807	86,276
NGLs (bbls/d)			19,403	16,655
Natural gas (Mcf/d)			368,701	313,159
Total (boe/d) ^3			169,660	155,124
Average realized Price ^1,4
Crude oil ($/bbl)			89.02	91.73
NGLs ($/bbl)			34.77	47.50
Natural gas ($/Mcf)			2.61	3.56
Petroleum and natural gas revenues ($/boe) ^1			56.24	63.30
Operating Netback ($/boe) ^1
Petroleum and natural gas revenues^1			56.24	63.30
Tariffs ^1			(0.44)	(0.54)
Processing & other income ^1			0.78	0.85
Marketing revenues ^1			3.87	4.63
Petroleum and natural gas sales ^1			60.45	68.24
Realized gain on commodity contracts ^1			0.36	0.65
Royalties ^1			(9.43)	(11.51)
Operating expenses ^1			(14.27)	(13.97)
Transportation expenses ^1			(2.06)	(2.13)
Marketing expenses ^1			(3.84)	(4.60)
Operating netbacks			31.21	36.68
Share information (millions)
Common shares outstanding, end of period			598.0	603.0
Weighted average basic shares outstanding			598.0	606.1
Weighted average diluted shares outstanding			601.7	610.8

MESSAGE TO SHAREHOLDERS

Whitecap had an exceptional first quarter with average production of 169,660 boe/d (108,210 bbls/d of light oil and liquids and 368,701 mcf/d of natural gas) compared to our forecast of approximately 163,500 boe/d (105,000 bbls/d of light oil and liquids and 351,000 mcf/d of natural gas), an increase of over 6,000 boe/d. This was achieved with lower than expected capital expenditures of $393 million compared to our forecast of approximately $430 million.

The first quarter represented the most active in our history. Drilling peaked at 15 rigs during the quarter to spud 96 (88.4 net) wells. We also completed the commissioning and start-up of our owned and operated Musreau battery. First sales volumes were produced through the facility in mid-March, approximately two weeks ahead of schedule and the combined project (including the sales gas pipeline) came in approximately 10% under our budget.

Production outperformance continues to exceed our expectations across our West and East Divisions into the second quarter. To reflect this outperformance that we have achieved year to date, we are increasing our annual production guidance by 2,000 boe/d to an updated guidance range of 167,000 – 172,000 boe/d, with no change to our capital budget of $0.9 - $1.1 billion.

Our balance sheet is in excellent condition with $1.5 billion of net debt (0.7 times debt to EBITDA ratio⁵) at quarter end. Continued strengthening of our balance sheet through the second quarter remains a priority for both downside price protection and value enhancing opportunities in the future.  

We provide the following first quarter 2024 financial and operating highlights:

• Funds Flow. First quarter funds flow of $384 million ($0.64 per share) equated to a funds flow netback¹ of $24.87 per boe. Strong WTI crude oil prices and a weak Canadian dollar contributed to our strong netback while the wider differentials experienced on Canadian oil prices that persisted through the first quarter have substantially narrowed with the in service date of the Trans Mountain Expansion pipeline now expected in the second quarter.
• Drilling Program. We spud 96 (88.4 net) wells and brought on production 85 (80.0 net) wells during the first quarter, including 11 (10.5 net) wells in our West Division and 74 (69.5 net) wells in our East Division. Initial results are very strong across both our West and East Divisions, exceeding our internal forecasts on a total production basis and liquids content, particularly from our Glauconite and Montney assets.
• Return of Capital. First quarter dividends declared of $109 million ($0.18 per share) increased by 24% relative to the first quarter of 2023. Our annual base dividend of $0.73 per share represents a stable return of capital to our shareholders and will be further enhanced through share repurchases using our Normal Course Issuer Bid ("NCIB").
• Balance Sheet Strength. Quarter end net debt of $1.5 billion equated to a debt to EBITDA ratio of 0.7 times and an EBITDA to interest expense ratio⁵ of 27.2 times, both well within our debt covenants of not greater than 4.0 times and not less than 3.5 times, respectively.

OPERATIONS UPDATE

West Division

The progression of our Montney development took a significant step forward with the commissioning and startup of our Musreau battery near the end of the first quarter. Initial sales volumes flowed through the facility approximately two weeks ahead of schedule and initial production rates from our first 4-well (4.0 net) pad at Musreau are higher than anticipated. Tie-in of our second 4-well pad at Musreau was completed in early April and each well on this pad has now been brought on production on a staged basis.

At Kakwa, our two recent 3-well pads that were drilled to a wider six wells per section spacing compared to offset wells and previously eight wells per section spacing have continued to achieve strong results. Our most recent 3-well (3.0 net) pad, at 03-21B has produced at average IP(90) rates of 1,830 boe/d (34% liquids) per well, which is 20% above our expectations, matching the early-time outperformance of our adjacent 02-26B 3-well (3.0 net) pad. Based on initial outperformance, the per-section economic return profiles of this asset are strengthened utilizing this updated spacing strategy and we are currently evaluating the applicability to other areas of future Montney and Duvernay development.

The 2-well (2.0 net) pad at Lator that was drilled in the back half of 2023 continues to outperform expectations with average IP(150) rates of 1,580 boe/d (42% liquids) per well being 17% above our expectations. Our next two wells at Lator will be drilled in the third quarter this year, while ongoing engineering and commercial work is being advanced to determine the optimal development and infrastructure strategy for our expansive land base at Lator.

In the Duvernay at Kaybob we have just completed drilling our third pad, a 3-well (3.0 net) pad which is expected to be brought on production near the end of the second quarter. The three wells on this pad have been drilled with 4,200 metre lateral lengths, our longest Duvernay laterals to date. Our first seven (7.0 net) wells (4-well and 3-well pads) are 22% above our expectations with average IP(150) rates of 1,498 boe/d (35% liquids) per well. We plan to bring eight (8.0 net) Duvernay wells on production in 2024.

East Division

Our East Division had a very active first quarter, running 11 rigs on average and we brought 74 (69.5 net) wells on production, with an additional 11 (8.3 net) wells from our first quarter program planned to be brought on production by mid-May. Production outperformance across multiple areas allowed us to offset the negative impacts that adverse weather conditions had on our drilling program and production in the quarter.

Strong results from our first quarter drilling program include four (3.9 net) Glauconite wells, a three-well (2.9 net) pad and a single (1.0 net) infill well. All four wells are producing significantly above initial expectations and have been aided by increased infrastructure access in the area. We are in the process of drilling 5 (4.8 net) Glauconite wells through breakup with 2 (2.0 net) wells to be brought on by the end of the second quarter.

In East Saskatchewan, we drilled 17 (15.7 net) wells in the first quarter, including 11 (10.3 net) triple leg horizontal wells targeting the Frobisher formation. Early time results on our Frobisher program are tracking above our type curve for the area. Efficiency improvements by drilling dual and triple-leg wells are notable and the significant majority of our 2024 program will utilize multi-laterals in the Frobisher.

OUTLOOK

2024 is off to a great start with March production volumes averaging over 175,000 boe/d as a result of our Musreau battery coming online as well as from high flush volumes from our first quarter drilling program in both the West and East Divisions. We are particularly excited about our first 4-well (4.0 net) Musreau pad, with initial results exceeding our expectations for the area. Musreau was identified as key acreage in our 2022 XTO acquisition and upcoming development is expected to generate top tier economics.

We will continue to optimize our expansive portfolio of 6,442 (5,619 net) high quality drilling locations⁶ by reducing drilling days, refining completions parameters on a pad-by-pad basis (such as proppant intensity, cluster spacing and fluid optimization) and expect our operating costs per boe to continue to improve as we move through the remainder of the year.

As mentioned earlier, we are increasing our production guidance by 2,000 boe/d to an updated guidance range of 167,000 – 172,000 boe/d, with no change to our $0.9 - $1.1 billion capital budget.

We are comfortable with the sustainability of our current monthly dividend of $0.0608 per share that has been stress tested down to US$50/bbl WTI and $2.00/GJ AECO and is further supported by a fortified balance sheet. Our focus is now on share repurchases through our NCIB to continue to enhance our per share metrics.

At current strip prices⁷, we are forecasting 2024 funds flow of approximately $1.7 billion⁸ which results in free funds flow of $700 million⁸ after capital investments.

We see continued tailwinds for Canadian crude oil producers with the TMX pipeline expansion expected to begin commercial operations on May 1, 2024, resulting in tighter differentials for both heavy and light oil over the next several years. As Whitecap is predominately a light oil producer, we are seeing the benefits of the Edmonton Par Differential narrow from over US$8.50/bbl in the first quarter of 2024 and is expected to average less than US$3.00/bbl over the remainder of the year.

Natural gas production in Western Canada remains near all-time highs, resulting in depressed AECO prices that are expected to remain challenged in the near to medium term. However, AECO prices are expected to improve with the start-up of LNG Canada phase 1 commissioning and the associated ramp up in the latter part of this year. Although Whitecap's production mix is 65% oil and liquids which represents 90% of our revenues, this will have a positive impact to our cash flows as we currently produce approximately 370,000 mcf/d of natural gas.

With the tailwinds for Canadian Energy, Whitecap's deep inventory set, strong operational execution and a clean balance sheet to execute on share buybacks and/or disciplined acquisitions, we are well positioned to deliver exceptional returns for shareholders in 2024 and beyond.

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

INVESTOR DAY

We are also pleased to announce a virtual Investor Day to be held on Tuesday, June 11, 2024 from 8:30 - 10:00 am MT (10:30 am - 12:00 pm ET). Members of management will present with a Q&A period to follow.

Registration can be made using the following link (Investor Day Registration) or via Whitecap's website at www.wcap.ca by selecting "Investors", then "Presentations & Events".

NOTES
^1	Funds flow, funds flow basic ($/share), funds flow diluted ($/share) and net debt are capital management measures. Funds flow netback ($/boe), average realized price and per boe disclosure figures are supplementary financial measures. Operating netback and free funds flow are non-GAAP financial measures. Operating netbacks ($/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	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.
^7	Based on the following strip commodity pricing and exchange rate assumptions for the remainder of 2024: US$80/bbl WTI, $1.76/GJ AECO, USD/CAD of $1.37.
^8	2023 Funds flow was $1.8 billion and 2023 free funds flow was $838 million.

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, April 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 capital expenditures for 2024; that continued strengthening of our balance sheet through the second quarter remains a priority for both downside price protection and value enhancing opportunities in the future; that the in service date of the Trans Mountain Expansion pipeline is now expected to be in the second quarter; that our return of capital will be further enhanced through share repurchases using our NCIB;; our belief that the per section economic return profiles of our Kakwa asset are strengthened utilizing the updated spacing strategy described herein; that we will drill our next two wells at Lator in the third quarter of this year; that ongoing engineering and commercial work is being advanced to determine the optimal development and infrastructure strategy for our expansive land base at Lator; that our third Duvernay pad is expected to be brought on production near the end of the second quarter; our plans to bring eight (8.0 net) Duvernay wells on production in 2024; our plans to bring an additional 11 (8.3 net) wells from our first quarter program on production by mid-May; our plans to bring 2 (2.0 net) Glauconite wells on by the end of the second quarter; that the significant majority of our 2024 program will utilize multi-laterals in the Frobisher; our belief that upcoming development at Musreau is expected to generate top tier economics in the current commodity price environment; that we will optimize our expansive portfolio of 6,442 (5,619 net) high quality drilling locations by reducing drilling days, refining completions parameters on a pad-by-pad basis (such as proppant intensity, cluster spacing and fluid optimization) and expect our operating costs per boe to continue to improve as we move through the remainder of the year; that we are comfortable with the sustainability of our current monthly dividend of $0.0608 per share that has been stress tested down to US$50/bbl WTI and $2.00/GJ AECO, and is further supported by a fortified balance sheet; that our focus is now on share repurchases through our NCIB to continue to enhance our per share metrics; our forecasted 2024 funds flow of $1.7 billion, which results in free funds flow of $700 million, after capital investments based on current strip prices; that the TMX pipeline expansion is expected to begin commercial operations on May 1, 2024, resulting in tighter differentials for both heavy and light oil over the next several years; that the Edmonton Par differential is expected to average less than US$3.00/bbl over the remainder of the year; that AECO prices are expected to remain challenged in the near to medium term; that AECO prices are expected to improve with the start-up of LNG Canada phase 1 commissioning and the associated ramp up in the latter part of this year, and that this will have a positive impact to our cash flows; and, our belief that we are well positioned to deliver exceptional returns for shareholders in 2024 and beyond.

The forward-looking information is based on certain key expectations and assumptions made by our management, including: that we will continue to conduct our operations in a manner consistent with past operations except as specifically noted herein (and for greater certainty, the forward-looking information contained herein excludes the potential impact of any acquisitions or dispositions that we may complete in the future); the general continuance or improvement in current industry conditions; the continuance of existing (and in certain circumstances, the implementation of proposed) tax, royalty and regulatory regimes; expectations and assumptions concerning prevailing and forecast commodity prices, exchange rates, interest rates, inflation rates, applicable royalty rates and tax laws, including the assumptions specifically set forth herein; the ability of OPEC+ nations and other major producers of crude oil to adjust crude oil production levels and thereby manage world crude oil prices; the impact (and the duration thereof) of the ongoing military actions in the Middle East and between Russia and Ukraine and related sanctions on crude oil, NGLs and natural gas prices; the impact of 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; our expectations for when the TMX pipeline expansion and LNG Canada phase 1 will begin commercial operations and the impact of those events on commodity prices and our business; 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 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) 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; the risk that the start-up of commercial operations on the TMX pipeline expansion and/or the LNG Canada phase 1 are delayed and/or do not produce the benefits for our business that we expect; 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 forecast for $1.7 billion of funds flow and $700 million of free funds flow in 2024 after capital investments based on current strip prices; and our forecast that our dividend is sustainable down to US$50/bbl WTI and $2.00/GJ AECO; 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 6,442 (5,619 net) drilling locations identified herein, 1,590 (1,374 net) are proved locations, 323 (271 net) are probable locations, and 4,529 (3,974 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, 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), IP(150)) are useful in confirming the presence of hydrocarbons, however such rates are not determinative of the rates at which such wells will continue production and decline thereafter. While encouraging, readers are cautioned not to place reliance on such rates in calculating the aggregate production for Whitecap.

The Company's average daily production for the three months ended March 31, 2024 and 2023 and for the month of March, the forecast average daily production for Q1/2024 and 2024 (midpoint), and the average daily production rate per well for (1) our 3 (3.0 net) 03-21B Montney pad at Kakwa (IP(90)), (2) the 2 (2.0 net) Montney wells at Lator (IP(150)), and (3) the 7 (7.0 net) Duvernay wells at Kaybob (IP(150)) 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	Q1/2024	Q1/2023	Q1/2024 Guidance	March
Light and medium oil (bbls/d)	76,012	76,160	74,800	76,500
Tight oil (bbls/d)	12,795	10,116	10,900	15,000
Crude oil (bbls/d)	88,807	86,276	85,700	91,500
NGLs (bbls/d)	19,403	16,655	19,300	20,000
Shale gas (Mcf/d)	223,009	175,176	201,500	234,000
Conventional natural gas (Mcf/d)	145,692	137,983	149,500	147,000
Natural gas (Mcf/d)	368,701	313,159	351,000	381,000
Total (boe/d)	169,660	155,124	163,500	175,000

Whitecap Corporate / Initial Production Rates	2024 Guidance (Mid-Point)	Kakwa (IP(90))	Lator (IP(150))	Kaybob (IP(150))
Light and medium oil (bbls/d)	75,200	-	-
Tight oil (bbls/d)	14,800	385	580	370
Crude oil (bbls/d)	90,000	385	580	370
NGLs (bbls/d)	18,000	240	80	150
Shale gas (Mcf/d)	220,000	7,230	5,520	5,868
Conventional natural gas (Mcf/d)	149,000	-	-	-
Natural gas (Mcf/d)	369,000	7,230	5,520	5,868
Total (boe/d)	169,500	1,830	1,580	1,498

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" 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 15 "Revenue" to the Company's unaudited interim consolidated financial statements for the three months ended March 31, 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 and, therefore, may not be comparable with the calculation of similar financial measures disclosed by other entities. The most directly comparable financial measure to free funds flow disclosed in the Company's primary financial statements is cash flow from operating activities. Refer to the "Cash Flow from Operating Activities, Funds Flow and Free Funds Flow" section of our management's discussion and analysis for the three months ended March 31, 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 Mar. 31,		Year ended Dec. 31,
($ millions)	2024	2024	2023	2022
Cash flow from operating activities	352.5	352.5	1,742.5	2,183.1
Net change in non-cash working capital items	31.5	31.5	48.9	139.7
Funds flow	384.0	384.0	1,791.4	2,322.8
Expenditures on PP&E	393.2	393.2	953.8	686.5
Free funds flow	(9.2)	(9.2)	837.6	1,636.3
Funds flow per share, basic	0.64	0.64	2.96	3.77
Funds flow per share, diluted	0.64	0.64	2.94	3.74

"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 months ended March 31, 2024 for additional disclosures.

"Funds flow netback ($/boe)" is a supplementary financial measure calculated by dividing funds flow as disclosed in Note 5(e)(ii) "Capital Management – Funds Flow" in the Company's unaudited interim consolidated financial statements for the three months ended March 31, 2024 by the Company's total production for the period.

"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, 2024 for additional disclosures. The following table reconciles the Company's long-term debt to net debt:

Net Debt ($ millions)		Mar. 31, 2024	Mar. 31, 2023	Dec. 31, 2023
Long-term debt		1,392.6	1,336.7	1,356.1
Accounts receivable		(435.8)	(405.8)	(400.2)
Deposits and prepaid expenses		(30.2)	(18.1)	(32.9)
Non-current deposits		(82.9)	-	(82.9)
Accounts payable and accrued liabilities		615.3	529.2	509.0
Dividends payable		36.4	29.1	36.4
Net Debt		1,495.4	1,471.1	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 and, therefore, may not be comparable with the calculation of similar financial measures disclosed by other entities. For further information, refer to the "Operating Netbacks" section of our management's discussion and analysis for the three months ended March 31, 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 Mar. 31,
Operating Netbacks ($ millions)			2024	2023
Petroleum and natural gas revenues			868.3	883.7
Tariffs			(6.8)	(7.6)
Processing & other income			12.0	11.8
Marketing revenues			59.8	64.7
Petroleum and natural gas sales			933.3	952.6
Realized gain on commodity contracts			5.6	9.1
Royalties			(145.6)	(160.7)
Operating expenses			(220.3)	(195.1)
Transportation expenses			(31.8)	(29.8)
Marketing expenses			(59.3)	(64.2)
Operating netbacks			481.9	511.9

"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 and, therefore may not be comparable with the calculation of similar financial measures disclosed by other entities. Presenting operating netback on a per boe basis allows management to better analyze performance against prior periods on a comparable basis.

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

"Petroleum and natural gas revenues ($/boe)", "Tariffs ($/boe)", "Processing and other income ($/boe)" and "Marketing revenues ($/boe)" are supplementary financial measures calculated by dividing each of these components of petroleum and natural gas sales, disclosed in Note 15 "Revenue" to the Company's unaudited interim consolidated financial statements for the three months ended March 31, 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 months ended March 31, 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.

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]