WHITECAP RESOURCES INC. ANNOUNCES 2023 RESULTS AND RESERVES, OPERATIONS UPDATE AND UPDATED 2024 GUIDANCE

CALGARY, ALBERTA – Whitecap Resources Inc. ("Whitecap" or the "Company") (TSX: WCP) is pleased to report its operating and audited financial results for the three and twelve months ended December 31, 2023.

Selected financial and operating information is outlined below and should be read with Whitecap’s audited annual consolidated financial statements and related management’s discussion and analysis for the three months and year ended December 31, 2023 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 Dec. 31		Year ended Dec. 31
	2023	2022	2023	2022
Petroleum and natural gas revenues	914.1	1,116.5	3,551.6	4,452.9
Net income	298.3	318.7	889.0	1,676.1
Basic ($/share)	0.49	0.52	1.47	2.72
Diluted ($/share)	0.49	0.52	1.46	2.70
Funds flow 1	462.3	593.6	1,791.4	2,322.8
Basic ($/share) 1	0.77	0.97	2.96	3.77
Diluted ($/share) 1	0.76	0.97	2.94	3.74
Dividends declared	109.6	67.2	372.8	237.2
Per share	0.18	0.11	0.62	0.39
Expenditures on property, plant and equipment 2	200.5	179.0	953.8	686.5
Free funds flow 1	261.8	414.6	837.6	1,636.3
Net Debt 1	1,385.5	1,913.1	1,385.5	1,913.1
Operating
Average daily production
Crude oil (bbls/d)	88,687	91,812	85,718	86,417
NGLs (bbls/d)	19,241	17,473	17,296	15,521
Natural gas (Mcf/d)	351,757	342,640	320,922	254,708
Total (boe/d) 3	166,554	166,392	156,501	144,389
Average realized Price 1,4
Crude oil ($/bbl)	93.98	102.50	95.05	114.68
NGLs ($/bbl)	37.85	46.84	38.90	55.30
Natural gas ($/Mcf)	2.48	5.56	2.84	5.62
Petroleum and natural gas revenues ($/boe) 1	59.66	72.94	62.17	84.49
Operating Netback ($/boe) 1
Petroleum and natural gas revenues1	59.66	72.94	62.17	84.49
Tariffs 1	(0.42)	(0.49)	(0.49)	(0.46)
Processing & other income 1	0.80	0.77	0.87	0.68
Marketing revenues 1	4.57	5.93	4.82	5.99
Petroleum and natural gas sales 1	64.61	79.15	67.37	90.70
Realized gain/(loss) on commodity contracts 1	(0.14)	(1.43)	0.34	(4.66)
Royalties 1	(10.66)	(13.34)	(10.83)	(16.35)
Operating expenses 1	(13.41)	(14.13)	(14.10)	(14.54)
Transportation expenses 1	(2.09)	(2.12)	(2.17)	(2.18)
Marketing expenses 1	(4.54)	(5.87)	(4.79)	(5.94)
Operating netbacks	33.77	42.26	35.82	47.03
Share information (millions)
Common shares outstanding, end of period	598.0	608.7	598.0	608.7
Weighted average basic shares outstanding	603.2	610.8	605.1	616.5
Weighted average diluted shares outstanding	607.3	613.8	608.6	621.1

MESSAGE TO SHAREHOLDERS

2023 was a strong year for Whitecap both operationally and financially, highlighted by 11% production per share growth⁵ and the achievement of our second of two net debt milestones, prompting a 26% increase to our base dividend. The ongoing development of our high-quality drilling inventory has yielded exceptional results, with our team constantly evaluating options to further improve capital efficiencies and netbacks for increased profitability.

Average 2023 production of 156,501 boe/d, including 103,014 bbls/d of light oil and liquids and 320,922 mcf/d of natural gas, generated funds flow of $1.8 billion ($2.94 per share) and after capital expenditures of $954 million, resulted in free funds flow of $838 million ($1.38 per share¹). Dividends declared of $373 million ($0.62 per share) along with $123 million of share repurchases on our normal course issuer bid ("NCIB") resulted in shareholder returns of approximately $500 million ($0.81 per share). We are committed to strong return of capital to shareholders with a current base monthly dividend of $0.0608 per share ($0.73 per share annually) which will be supplemented with share repurchases on our NCIB.

We are also pleased to report exceptional 2023 reserve values highlighted by per share organic growth across all three reserve categories. These organic growth additions resulted in proved developed producing ("PDP") and total proven ("TP") production replacement¹ of 107% and 141%, respectively, and reflect our strong 2023 drilling program. Three-year average finding and development ("F&D") recycle ratios¹ between 2.6 times and 3.3 times highlight the robust profitability of our asset base through commodity price cycles.

Our balance sheet remains a priority for us and is in excellent condition with less than $1.4 billion of net debt (0.7 times debt to EBITDA ratio⁶) at year end and approximately $1.7 billion of available capacity on $3.1 billion of total debt capacity. As we continue to allocate a portion of our free funds flow towards debt reduction, this will further strengthen our balance sheet for both downside protection and value enhancing opportunities in the future.  

Near the end of the fourth quarter, we completed a tuck-in acquisition of light oil Viking assets in one of our core areas in Western Saskatchewan for cash proceeds of $154 million, prior to closing adjustments. The acquisition consolidates an active area of our Viking drilling program, was completed at attractive acquisition metrics, and was highly accretive to funds flow per share and free funds flow per share. Our team is now actively executing on production optimization opportunities on this 100% light oil asset base.

We provide the following fourth quarter and full year 2023 financial and operating highlights:

·      Funds Flow. Full year and fourth quarter funds flow netbacks¹ of $31.36 per boe and $30.16 per boe, respectively, were strong despite average 2023 WTI crude oil prices being 18% lower and natural gas prices being 50% lower than in 2022. Operating costs of $14.10 per boe were down 3% from 2022, despite inflationary pressures persisting through the year. Full year funds flow of $1.8 billion equates to $2.94 per share, while fourth quarter funds flow of $462 million equates to $0.76 per share.

·      Drilling Program. We were the fourth most active driller in Western Canada in 2023, drilling 215 (189.0 net) wells, including 181 (158.2 net) wells in our East Division and 34 (30.8 net) wells in our West Division. Of the $954 million of capital expenditures incurred in 2023, 80% was allocated to drilling and completions, while 17% was directed to facilities spending, including initial work on our Musreau battery to support Montney production additions in 2024 as well as an expansion to our 3-27 facility supporting regional Montney and Charlie Lake development in the Peace River Arch.

·      Increasing Return of Capital. We increased our dividend for the seventh time in three years to $0.73 per share annually in October 2023. We have been focused on delivering a strong return of capital to shareholders since paying our first dividend at the start of 2013, returning a total of $1.8 billion in dividends over the past eleven years. These returns have been further enhanced by repurchasing over 76 million shares for $612 million since 2017. Total return to shareholders of approximately $500 million in 2023 demonstrates a continuation of this strategy.

·      Balance Sheet Strength. Year end net debt of $1.4 billion equated to a debt to EBITDA ratio of 0.7 times and an EBITDA to interest expense ratio⁶ of 27.0 times, both well within our debt covenants of not greater than 4.0 times and not less than 3.5 times, respectively. We have significant financial flexibility with over $1.7 billion of available capacity on $3.1 billion of total credit capacity.

OPERATIONS UPDATE

West Division

We continue to advance operations in our West Division including a buildout of new facilities and infrastructure to handle our production growth into the future. We are looking forward to our next stage of Montney development at Musreau with the completion of our battery in the second quarter of this year. Our 2023 West Division drilling program has achieved excellent results thus far with average well results performing above type curve expectations, while we also continue to expand our technical knowledge of our asset base.

At Kakwa, we are encouraged by strong initial results on our two most recent Montney pads, where we have optimized our development strategy for dynamic reservoir and fluid properties in this localized area. Our 3-well (3.0 net) 02-26 (B) pad was brought on production in September and has achieved an average IP(120) rate of 1,889 boe/d (32% liquids) per well which is 26% above our expectations. The 3-well (3.0 net) 03-21 (B) pad that was drilled in the fourth quarter was tied into permanent facilities in early February, with test results showing similar characteristics as the 02-26 (B) pad.

Although early, we are encouraged by the initial results of these two pads and application of this well design and spacing strategy may be transferable to other areas of future Montney and Duvernay development. While we ultimately believe that individual pad design will be tailored to the various geological and reservoir characteristics across our asset base, successful application of this well design and spacing strategy across a broader area has the potential to meaningfully improve the overall economics of our unconventional drilling inventory well into the future.

We also spud our first two 4-well pads (8.0 net wells) at Musreau in the fourth quarter, which are expected to be completed and ready to be brought on production upon completion of our 20,000 boe/d battery. The ramp up of production into this facility will occur during the second quarter, and we target facility capacity being reached as our third and fourth 4-well pads (8.0 net wells) are brought on production at Musreau later this year.

At Lator, we recently drilled a 2-well (2.0 net) pad as part of our validation and delineation efforts of this future area of Montney growth. The wells have achieved IP(60) rates of 1,655 boe/d (45% liquids) per well which are approximately 15% above our expectations. Strong return characteristics along with a significant land position will make Lator an area of meaningful growth for the West Division in the coming years. We plan to drill an additional two (2.0 net) Montney wells at Lator in 2024. Engineering and commercial work is underway to establish the optimal development and infrastructure strategy for this area.

With respect to our Duvernay asset at Kaybob, our results continue to outperform our expectations as our first seven (7.0 net) wells (4-well and 3-well pads) achieved an average IP(90) rate of approximately 1,600 boe/d (36% liquids) per well, which is 24% above our expectations. We plan to bring eight (8.0 net) wells on during 2024 as we continue to increase production towards our target of 90% capacity of our 100% owned 15-07 gas processing facility by the end of 2025. The first 3 wells of our 2024 program are currently being drilled to a 4,200-metre lateral length, approximately 750 metres longer than our initial seven Duvernay wells.

As part of the execution of our 2024 capital spending program and long-range planning scenarios, we have an active water management strategy to mitigate impacts of potential drought conditions in Alberta. We have a combination of term and temporary licenses along with established water infrastructure to support our 2024 program.

East Division

2023 was a very strong operational year for our East Division with outperformance across all four regions. We drilled 181 (158.2 net) wells during the year, which included 151 (134.9 net) light oil wells into the Cardium, Frobisher, Glauconite, and Viking formations that are characterized by quick payouts and high netbacks. With over 50,000 boe/d of production under secondary and tertiary recovery, we also spent a total of $110 million on these assets in 2023. Approximately 60% of this capital was directed towards drilling producing wells in areas under secondary and tertiary recovery while the remaining 40% was directed towards injector drills and conversions along with base volume maintenance activities, to preserve our low decline rate of 20% for the Division.

In Eastern Saskatchewan, we drilled 46 (41.0 net) wells, primarily focused on the Frobisher formation. We have been utilizing open hole multi-lateral technology, drilling dual and triple leg laterals consistently since early 2021, and have incorporated longer laterals and additional lateral legs where viable. As a result, our average total lateral length increased by 45% (700 metres per well) as compared to 2022. After providing for the impact of longer laterals, our 2023 program has been very successful, generating average IP(90) results that are 13% above expectations. We have an active 2024 program underway with three rigs currently running in Eastern Saskatchewan with plans to drill 23 (21.1 net) wells in the first quarter.

Our Western Saskatchewan region includes both low decline waterflood assets along with quick payout, high netback Viking light oil assets. On average, our 2023 Western Saskatchewan well results exceeded our expectations by 9% on an IP(180) basis, which includes our Viking drilling program that averaged a capital payout⁷ of six months in 2023. The integration of the acquisition completed in late December is ongoing with combined production in the Elrose area now at 6,500 bbls/d which represents over 40% of our total high netback, Viking light oil production. Our secondary/tertiary recovery enhancements and greater use of extended reach horizontal wells are some of the many inventory enhancement initiatives that our technical team has undertaken in Western Saskatchewan over the past several years.

The profitability of our Weyburn asset is a function of an extremely low decline rate of 3% and a 100% oil and NGLs production base with 35% of rollout areas still to be converted for CO₂ injection. We drilled 4 (3.4 net) producing wells and 4 (3.7 net) injection wells in 2023, with our 2024 program increasing to 9 (6.3 net) producing wells and 8 (5.2 net) injection wells. Net operating income⁸ from this asset has paid out the purchase price of $940 million 1.2 times since we acquired it in December 2017. The property continues to produce 14,500 boe/d net to Whitecap at this time.

We have also recently started CO₂ injection at a pilot CO₂ flood into the Frobisher formation underlying the Weyburn Midale unit. We drilled two (2.0 net) producer wells and three (3.0 net) injection wells in 2023 and initiated CO₂ injection in late 2023. Early results are encouraging with a notable production response coming through approximately one month after injection, increasing oil rates on the two producer wells from approximately 40 bbls/d to over 200 bbls/d, per well. Further technical analysis to determine commerciality and large-scale development is ongoing, and we will provide updates as next steps are determined.

In Central Alberta, our focus is in the Cardium and Glauconite formations, drilling 16 (10.4 net) wells into the Cardium and 14 (12.8 net) wells into the Glauconite in 2023. Our West Pembina Cardium program achieved strong results with average IP(90) rates exceeding expectations by 10%. Our Glauconite continues to achieve strong results, with average production rates in line with our expectations and liquids rates outperforming by 5% on an IP(90) basis. Our consolidated land position has allowed us to continually test increasing lateral lengths. We plan to drill 5 (4.9 net) Glauconite wells with an average lateral length of 2,700 metres and 8 (5.8 net) Cardium wells in the first quarter. 

2023 RESERVES

Operational success and a deep set of highly economic inventory has resulted in strong year end reserve values. We continue to see the benefits of our consolidation strategy that began in late-2020 as greater scale and asset optimization opportunities have yielded consistent per share growth and increasing net present values.

One of the benefits of consolidating acreage has been an ability to drill longer laterals in areas that were previously restricted by ownership boundaries. In addition, we are consistently expanding the applicability of increased lateral lengths to greater portions of our asset base, giving potential for improved capital efficiencies and, therefore, increased profitability. At year end, we have identified 6,400 drilling locations⁹ in inventory which provides for over 25 years of sustainable and profitable growth.

We highlight the following 2023 year end reserve report results:

·      Per Share Focus. Debt-adjusted reserves per share¹⁰ increased 6% on a PDP basis, 10% on a TP basis and 7% on a total proven plus probable ("TPP") basis despite net dispositions decreasing total reserves. Our focus on per share metrics along with strong return on capital execution will maximize long-term profits for our shareholders.

·      Production Replacement. Prior to the impact of net dispositions, we replaced 107% of production on a PDP basis, 141% of production on a TP basis and 107% of production on a TPP basis. Strong operational execution along with a prolific asset base provide for increased sustainability over the long term.

·      Long-Dated Inventory. We have significant inventory life across all our assets, with a PDP reserve life index¹¹ ("RLI") of 6 years, a TP RLI of 13 years, and a TPP RLI of 19 years. These are consistent with the three-year average and are reflective of the expansive opportunity we have to develop these assets over time.

·      Strong Recycle Ratios. Our PDP F&D¹ cost of $14.68 per boe, our TP F&D cost of $17.62 per boe and our TPP F&D cost of $20.46 per boe resulted in strong recycle ratios of 2.4 times, 2.0 times and 1.8 times, respectively. The three-year average F&D recycle ratios range from 2.6 times to 3.3 times, which emphasizes our strong asset base and our focus on long-term profitability.

OUTLOOK

We have increased our 2024 average production guidance range to 165,000 – 170,000 boe/d (8% production per share growth) to reflect the Viking tuck-in acquisition along with the reduction in capital spending. Our capital budget is now expected to be $900 million to $1.1 billion, which is $100 million lower than originally budgeted, providing another year of strong operational execution underpinned by the technical enhancements undertaken in 2023.

WTI crude oil prices continue to be relatively volatile but have been rangebound between US$70/bbl and US$80/bbl and currently at approximately US$75/bbl for the balance of 2024. This, combined with the weak Canadian dollar, results in a very strong Canadian crude oil price in excess of $100/bbl. We also anticipate light and heavy oil differentials to tighten further throughout the year with the completion of the Trans Mountain Expansion project in the coming months, bringing further pricing upside to Canadian crude oil production.

Natural gas prices are currently challenged with the lack of winter demand resulting in weak AECO prices forecasted through to the end of the summer, and a seasonal increase into next winter is anticipated. While the liquids component of our unconventional assets currently drives the economics, our growth in natural gas volumes is anticipated to coincide with the commissioning of LNG Canada in 2025. Completion of this facility is an important step for Canada, as there will be an ability to deliver natural gas to overseas markets which should reduce gas-on-gas competition within Canada. Further to this, as part of our ongoing efforts to diversify our natural gas volumes, we have joined Rockies LNG Partners to contribute 100,000 mcf/d of natural gas towards the Ksi Lisims LNG project and add exposure to non-North American natural gas prices.

At current strip prices¹², we are forecasting 2024 funds flow of approximately $1.6 billion which results in free funds flow of $600 million, after capital investments. This is more than sufficient to fund our annual dividend obligation of $435 million. We have stress tested our dividend down to US$50/bbl WTI and $2.00/GJ AECO and have further flexibility to reduce our capital program to ensure dividends and capital investments are fully funded by cash flows. Our balance sheet remains in excellent shape with low leverage and ample liquidity to support the business throughout various commodity price cycles.

Our long term organic corporate growth outlook has been updated and increased to 210,000 boe/d by the end of 2028, which represents average organic growth of 5% on an annual basis, driven primarily by our liquids rich Montney and Duvernay assets. At the end of 2028, we will still have over 20 years of drilling inventory remaining, assuming a consistent 5% annual growth rate beyond 2028.

We would like to emphasize that our objective is to provide sustainable and profitable growth to our shareholders, including a disciplined level of debt, while remaining committed to responsible development of our assets. Our strategy includes advancing our emission reduction strategy and utilizing our expertise in carbon sequestration.

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 2024 and beyond.

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 ($/boe), F&D costs, funds flow netbacks ($/boe), free funds flow diluted ($/share) and recycle ratio are non-GAAP ratios. 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 spending".
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   Production per share is the Company’s total crude oil, NGL and natural gas production volumes for the applicable period divided by the weighted average number of diluted shares outstanding for the applicable period. Production per share growth is determined in comparison to the applicable comparative period.
⁶    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.
⁷   Also referred to herein as "half-cycle payout". Refer to Oil and Gas Metrics in this press release for additional disclosure.
⁸   Also referred to herein as "operating netback".
⁹   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.
¹⁰ "Debt-adjusted reserves per share" is calculated as year end reserves divided by year end fully diluted shares plus the annual change in net debt divided by the average annual share price. Debt-adjusted reserves per share growth is determined in comparison to the yar end reserves divided by year end fully diluted shares from the applicable comparative period.
¹¹ See "Production Replacement Ratio and Reserve Life Index".
¹² Based on the following strip commodity pricing and exchange rate assumptions for 2024: US$75/bbl WTI, $1.95/GJ AECO, USD/CAD of $1.35.

2023 RESERVES REVIEW

Our 2023-year end reserves were evaluated by independent reserves evaluator McDaniel & Associates Consultants Ltd. ("McDaniel") in accordance with the definitions, standards and procedures contained in the Canadian Oil and Gas Evaluation Handbook ("COGE Handbook") and National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities ("NI 51-101") as of December 31, 2023. 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, 2024 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 including any royalty interests payable to the Company. Additional reserve 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, 2023

	Company Share (Gross) Reserves
Description	Light & Medium Oil (Mbbl)	Tight Crude Oil (Mbbl)	Conventional Natural Gas (MMcf)
Proved developed producing	201,566	737	318,561
Proved developed non-producing	2,313	0	7,271
Proved undeveloped	102,255	8,664	162,792
Total proved	306,134	9,401	488,624
Probable	108,069	8,000	196,423
Total proved plus probable	414,203	17,400	685,046

 

Description	Shale Gas (MMcf)	Natural Gas Liquids (Mbbl)	Total (Mboe)
Proved developed producing	319,542	51,755	360,409
Proved developed non-producing	30,901	7,553	16,228
Proved undeveloped	997,087	111,426	415,658
Total proved	1,347,530	170,734	792,294
Probable	869,388	84,194	377,897
Total proved plus probable	2,216,918	254,927	1,170,191

 

Net Present Values of Future Net Revenue

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

As at December 31, 2023

	Before Tax Net Present Value ($ millions) (1)
	Discount Rate
Reserves Category	0%	5%	10%	15%	20%
Proved Developed Producing	8,052	6,765	5,593	4,779	4,201
Proved developed non-producing	487	386	324	283	252
Proved undeveloped	9,144	6,000	4,168	3,007	2,223
Total Proved	17,683	13,151	10,085	8,068	6,676
Total Probable	11,773	6,611	4,334	3,112	2,373
Total Proved + Probable	29,456	19,762	14,419	11,180	9,049

⁽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 2023 is $6.6 billion undiscounted ($4.9 billion discounted at 10%).

 Also included in FDC are 1,590 (1,374 net) proved booked drilling locations and 323 (271 net) probable booked drilling locations.

($ millions)	Total Proved	Total Proved plus Probable
2024	999	1,024
2025	1,206	1,244
2026	1,218	1,341
2027	1,154	1,269
2028	1,112	1,331
Remainder	954	2,160
Total FDC, Undiscounted	6,641	8,370
Total FDC, Discounted at 10%	4,856	5,857

Performance Measures (Including FDC)

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

	2023	2022	2021	Three Year Weighted Average
Proved Developed Producing
F&D costs per boe (1)	$14.68	$13.20	$16.28	$14.64
F&D recycle ratio (2)	2.4x	3.6x	1.8x	2.6x
FD&A costs per boe (3)	$17.30	$24.01	$11.75	$18.01
FD&A recycle ratio (2)	2.1x	2.0x	2.6x	2.2x
Total Proved
F&D costs per boe (1)	$17.62	$16.90	$5.05	$14.15
F&D recycle ratio (2)	2.0x	2.8x	5.9x	3.3x
FD&A costs per boe (3)	$22.64	$14.98	$11.48	$16.92
FD&A recycle ratio (2)	1.6x	3.1x	2.6x	2.4x
Total Proved Plus Probable
F&D costs per boe (1)	$20.46	$19.53	$4.63	$16.25
F&D recycle ratio (2)	1.8x	2.4x	6.4x	3.2x
FD&A costs per boe (3) (4)	nm	$11.55	$9.60	nm
FD&A recycle ratio (2) (4)	nm	4.1x	3.1x	nm

 

⁽¹⁾     F&D costs are non-GAAP ratios and are calculated as the sum of development capital of $939.6 million (excluding corporate and capitalized G&A) plus the change in FDC for the period of -$40.7 million (PDP), $479.6 million (TP) and $312.8 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 netback divided by F&D or FD&A costs. Our operating netback in 2023 was $35.82/boe. See "Oil and Gas Metrics" and "Specified Financial Measures".
⁽³⁾     FD&A costs are non-GAAP ratios and are calculated as the sum of development capital of $939.6 million (excluding corporate and capitalized G&A) plus acquisition capital of -$228.9 million plus the change in FDC for the period of -$13.0 million (PDP), $329.2 million (TP) and $62.9 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 $85.74 per boe is deemed not material to our reserve performance measures. 

Production Replacement Ratio and Reserve Life Index

The following table highlights our production replacement ratio and reserve life index ("RLI") based on the evaluation of our petroleum and natural gas reserves prepared by McDaniel, including the impact of net dispositions in 2023:

In 2023, prior to the impact of net dispositions, we replaced 107% of production on a PDP reserves basis, 141% of production on a TP reserves basis and 107% of production on a TPP reserves basis.

	2023	2022	2021	Three Year Weighted Average
Proved Developed Producing
Production replacement (1)	71%	208%	372%	211%
RLI (years) (2)	5.9	6.2	7.3	6.4
Total Proved
Production replacement (1)	80%	589%	545%	389%
RLI (years) (2)	13.0	13.2	12.5	12.9
Total Proved Plus Probable
Production replacement (1)	16%	952%	737%	553%
RLI (years) (2)	19.1	20.1	17.6	19.1

⁽¹⁾     Production replacement ratio is calculated as total reserve additions (including acquisitions net of dispositions) divided by annual production. Whitecap’s production averaged 156,501 boe/d in 2023.
⁽²⁾     RLI is calculated as total Company share reserves divided by the annualized fourth quarter actual production of 166,554 boe/d.

CONFERENCE CALL AND WEBCAST

Whitecap has scheduled a conference call and webcast to begin promptly at 9:00 am MT (11:00 am ET) on Thursday, February 22, 2024.

The conference call dial-in number is: 1-888-390-0605 or (587) 880-2175 or (416) 764-8609

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.

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.​​​​​