News Releases

WHITECAP RESOURCES INC. ANNOUNCES STRONG 2024 RESERVES METRICS AND PROVIDES AN OPERATIONS UPDATE

CALGARY, ALBERTA – Whitecap Resources Inc. ("Whitecap" or the "Company") (TSX: WCP) is pleased to provide the results of our 2024 year end reserves evaluation as prepared by McDaniel & Associates Consultants Ltd. ("McDaniel").

2024 was a strong operational and financial year for Whitecap, driven by the successful execution of our organic drilling program. Our annual production of 174,255 boe/d¹ (65% liquids) was significantly above our initial expectations for the year, with the outperformance primarily driven by initial production results from our key assets including the Montney at Musreau, Duvernay at Kaybob, Glauconite in Central Alberta and Frobisher in East Saskatchewan. Our base production also outperformed our expectations through lower declines, production optimization and additional egress capacity.

Across all three reserves categories, proved developed producing ("PDP"), total proven ("TP") and total proven plus probable ("TPP"), we replaced over 110% of production², achieved debt-adjusted reserves per share growth³ of 12% – 13% and generated strong recycle ratios⁴, all of which demonstrate the predictability and profitability of our asset base. Our long-dated premium drilling inventory of 6,270 (5,461 net) locations⁵ provides shareholders with sustainable and profitable long-term growth in production, funds flow and free funds flow. At our current drilling pace, our total inventory represents almost 30 years of development on our asset base.

We highlight the following 2024 year end reserves report results:
·     Reserves Growth³. Strong reserves per share growth of 4% on PDP reserves, 4% on TP reserves and 5% on TPP reserves. On a debt-adjusted basis, reserves per share growth is 12% on PDP reserves, 12% on TP reserves and 13% on TPP reserves.
·     Strong Recycle Ratios. Low Finding, Development & Acquisition ("FD&A") costs⁴ of $8.82/boe on PDP reserves, $12.46/boe on TP reserves and $10.02/boe on TPP reserves results in recycle ratios of 3.8 times, 2.7 times and 3.3 times, respectively. The strong recycle ratios reflect our high-quality asset base that generate attractive and resilient netbacks through commodity price cycles.
·     Long-Dated Inventory. Our booked locations within TPP reserves represent only 32% of our 6,270 (5,461 net) identified locations in inventory. Our future growth will favour development of our unconventional Montney and Duvernay assets, with only 16% of 2,447 (2,198 net) identified unconventional locations being booked within our TPP reserves.

OPERATIONS UPDATE & OUTLOOK

Our 2025 drilling program is off to a strong start, with fourteen rigs currently running across our asset base to spud 83 (75.5 net) conventional wells and 12 (12.0 net) unconventional Montney and Duvernay wells in the first half of the year while planning to spend approximately 55% of our $1.1 – $1.2 billion annual capital budget.

At Kaybob, our 11-14B pad, which was our pilot drilled with vertical benching in a wine rack style development, has achieved IP(90) rates of 1,237 boe/d (40% liquids) including 379 bbl/d of condensate per well. Adjusted for lateral length (approximately 2,900 metre average compared to our type curve at 3,200 metres), production results from this pad are in line with our type curve expectations, while currently observed reservoir performance is notably stronger than that of analogue offset wells. These strong reservoir performance measures have provided us the confidence to progress this pilot with a follow-up pad, a five (5.0 net) well pad at 08-05A, which is currently being completed and expected to be on production late March this year.

The 11-14B pad is bounded by a number of offset wells and continued production performance will lead to an improvement in our long-term development plans through additional locations and/or higher recoveries per well. Our ability to apply this potential development style across our Duvernay assets at Kaybob is enabled by the relative thickness of net pay we have observed at upwards of 50 – 70 metres. We have not yet incorporated improvements to our inventory stemming from vertical benching into our Duvernay inventory at this time but are encouraged by the initial results.

We also plan to bring on production our first triple bench Montney three (1.5 net) well pad at North Kakwa in April of this year, with completion operations commencing after the 08-05A Duvernay pad is complete. We are looking forward to production results later this year as it will inform future development opportunities in an area that has not been actively drilled since we acquired it in 2021.

Our most active conventional areas of development in the first half of the year are the Viking with 33 (33.0 net) wells, the Glauconite with 12 (11.2 net) wells, the Frobisher with 11 (11.0 net) wells and southwest Saskatchewan with 11 (9.7 net) wells.

Our conventional program is focused on high confidence and efficient development opportunities as well as advancing our key inventory enhancement initiatives such as extended reach horizontals, monobore drilling design, adding additional lateral legs (including open hole multi-lateral development), and production and egress optimizations. We have only booked 43% of our 3,823 (3,263 net) total locations in our conventional inventory and our total inventory now includes 110 (88.3 net) State A Frobisher locations. Our conventional inventory is characterized by high netback, light oil weighted assets that generate strong economics through commodity price cycles.

2024 RESERVES REVIEW

Our 2024 year end reserves were evaluated by independent reserves evaluator McDaniel in accordance with the definitions, standards and procedures contained in the Canadian Oil and Gas Evaluation Handbook ("COGE Handbook") and National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities ("NI 51-101") as of December 31, 2024. The reserves evaluation was based on the average forecast pricing of McDaniel, GLJ Ltd. and Sproule Associates Limited and foreign exchange rates at January 1, 2025 which is available on McDaniel’s website at www.mcdan.com.

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

Summary of Reserves

Reserves as at December 31, 2024

	Company Share (Gross) Reserves
Description	Light & Medium Crude Oil (Mbbl)	Tight Crude Oil (Mbbl)	Conventional Natural Gas (MMcf)
Proved developed producing	191,107	620	339,901
Proved developed non-producing	2,377	-	5,092
Proved undeveloped	100,277	9,185	161,391
Total proved	293,761	9,805	506,384
Probable	100,605	6,200	197,985
Total proved plus probable	394,366	16,005	704,369

 

Description	Shale Gas (MMcf)	Natural Gas Liquids (Mbbl)	Total (Mboe)
Proved developed producing	338,367	62,358	367,131
Proved developed non-producing	44,901	4,427	15,136
Proved undeveloped	1,012,874	118,664	423,836
Total proved	1,396,141	185,449	806,103
Probable	916,748	104,520	397,114
Total proved plus probable	2,312,889	289,969	1,203,216

 
Net Present Values of Future Net Revenue

Summary of Before Tax Net Present Values of Future Net Revenue (Forecast Pricing)

As at December 31, 2024

	Before Tax Net Present Value ($ millions) (1)
	Discount Rate
Reserves Category	0%	5%	10%	15%	20%
Proved Developed Producing	7,388	6,455	5,439	4,711	4,186
Proved developed non-producing	390	305	253	218	192
Proved undeveloped	7,560	4,969	3,417	2,425	1,756
Total Proved	15,337	11,729	9,109	7,354	6,133
Total Probable	10,800	6,024	3,967	2,877	2,217
Total Proved + Probable	26,138	17,752	13,076	10,230	8,351

⁽¹⁾  Includes abandonment and reclamation costs as defined in NI 51-101 for all of our facilities, pipelines and wells including those without reserves assigned.

Future Development Costs ("FDC")

FDC reflects the best estimate of the capital cost to develop and produce reserves. FDC associated with our TP reserves at year end 2024 is $7.0 billion undiscounted ($5.1 billion discounted at 10%).

 Also inicluded in FDC are 1,763 (1,496.7 net) proved booked drilling locations and 253 (219.4 net) probable booked drilling locations.

($ millions)	Total Proved	Total Proved plus Probable
2025	1,110	1,133
2026	1,219	1,261
2027	1,309	1,374
2028	1,419	1,492
2029	1,016	1,303
Remainder	940	2,185
Total FDC, Undiscounted	7,014	8,748
Total FDC, Discounted at 10%	5,111	6,102

 

Performance Measures (Including FDC)

The following table highlights finding and development ("F&D")³ and FD&A costs and associated recycle ratios, including FDC, based on the evaluation of our petroleum and natural gas reserves prepared by McDaniel:

	2024	2023	2022	Three Year Weighted Average
Proved Developed Producing
F&D costs per boe (1)	$16.01	$14.69	$13.25	$14.64
F&D recycle ratio (2)	2.1x	2.4x	3.5x	2.7x
FD&A costs per boe (3)	$8.82	$17.24	$24.05	$16.76
FD&A recycle ratio (2)	3.8x	2.1x	2.0x	2.6x
Total Proved
F&D costs per boe (1)	$19.24	$17.63	$16.95	$17.94
F&D recycle ratio (2)	1.7x	2.0x	2.8x	2.2x
FD&A costs per boe (3)	$12.46	$22.55	$14.98	$16.63
FD&A recycle ratio (2)	2.7x	1.6x	3.1x	2.5x
Total Proved Plus Probable
F&D costs per boe (1)	$15.46	$20.53	$19.61	$18.52
F&D recycle ratio (2)	2.1x	1.7x	2.4x	2.1x
FD&A costs per boe (3) (4)	$10.02	nm	$11.55	nm
FD&A recycle ratio (2) (4)	3.3x	nm	4.1x	nm

⁽¹⁾     F&D costs are non-GAAP ratios and are calculated as the sum of development capital of $1.1 billion (excluding corporate and capitalized general and administrative expenses ("G&A")) plus the change in FDC for the period of $22 million (PDP), $372 million (TP) and $378 million (TPP), divided by the change in reserves volumes that are characterized as development for the period. See "Oil and Gas Metrics" and "Specified Financial Measures".
⁽²⁾     Recycle ratio is a non-GAAP ratio and is calculated as operating netback⁴ divided by F&D or FD&A costs. Our operating netback in 2024 was $33.14/boe⁴. See "Oil and Gas Metrics" and "Specified Financial Measures".
⁽³⁾    FD&A costs are non-GAAP ratios and are calculated as the sum of development capital of $1.1 billion (excluding corporate and capitalized G&A) plus acquisition capital of -$505 million plus the change in FDC for the period of $22 million (PDP), $372 million (TP) and $378 million (TPP), divided by the change in total reserves volumes, other than from production, for the period. See "Oil and Gas Metrics" and "Specified Financial Measures".
⁽⁴⁾     The impact of net dispositions in 2023 results in a very low denominator value and therefore the 2023 FD&A cost of $85.40 per boe is deemed not material ("nm") to our reserves performance measures.

 Production Replacement Ratio and Reserve Life Index

The following table highlights our production replacement ratio and reserve life index² ("RLI") based on the evaluation of our petroleum and natural gas reserves prepared by McDaniel:

In 2024, we replaced 112% of production on a PDP reserves basis, 123% of production on a TP reserves basis and 154% of production on a TPP reserves basis.

	2024	2023	2022	Three Year Weighted Average
Proved Developed Producing
Production replacement (1)	112%	71%	208%	131%
RLI (years) (2)	5.7	5.9	6.2	5.9
Total Proved
Production replacement (1)	123%	81%	588%	265%
RLI (years) (2)	12.5	13.0	13.2	12.9
Total Proved Plus Probable
Production replacement (1)	154%	16%	952%	380%
RLI (years) (2)	18.7	19.2	20.0	19.3

⁽¹⁾     Production replacement ratio is calculated as total reserves additions (including acquisitions net of dispositions) divided by annual production. Whitecap’s production averaged 174,255 boe/d in 2024.
⁽²⁾     RLI is calculated as total Company share (gross) reserves divided by the annualized fourth quarter actual production of 176,730 boe/d.

On behalf of our employees, management team and Board of Directors, we would like to thank our shareholders for their support and look forward to an exciting 2025 and beyond. 

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, Initial Production Rates and Product Type Information in this press release for additional disclosure.
²   See "Production Replacement Ratio and Reserve Life Index".
³   "Reserves per share" is the Company’s total crude oil, NGL and natural gas reserves volumes for the applicable period divided by the weighted average number of diluted shares outstanding for the applicable period. "Reserves per share growth" is determined in comparison to the applicable comparative period. "Debt-adjusted reserves per share" is calculated as year end reserves divided by year end fully diluted shares (approximately 595 million) plus the annual change in net debt (-$452 million) divided by the average annual share price for 2024 ($9.99). Debt-adjusted reserves per share growth is determined in comparison to the year end reserves divided by year end fully diluted shares from the applicable comparative period.
⁴    Operating netback is non-GAAP financial measure. Operating netbacks ($/boe), F&D costs, FD&A costs and recycle ratio are non-GAAP ratios. Net debt is a capital management measure. Per boe disclosure figures are supplementary financial measures. Refer to the Specified Financial Measures section in this press release for additional disclosure and assumptions.
⁵   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.

For further information:

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

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

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