WHITECAP RESOURCES INC. ANNOUNCES RECORD 2022 PER SHARE RESULTS AND STRONG YEAR END RESERVES GROWTH

CALGARY, AB, Feb. 22, 2023 /CNW/ - Whitecap Resources Inc. ("Whitecap" or the "Company") (TSX: WCP) is pleased to report its operating and audited financial results for the quarter and year ended December 31, 2022, and its 2022 year end reserves evaluation.

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 and twelve months ended December 31, 2022 which are available at www.sedar.com and on our website at www.wcap.ca.

Financial ($ millions except for share amounts and percentages)	Three months ended December 31		Twelve months ended December 31
	2022	2021	2022	2021
Petroleum and natural gas revenues	1,116.5	785.8	4,452.9	2,526.3
Net income	318.7	223.8	1,676.1	1,776.7
Basic ($/share)	0.52	0.36	2.72	2.97
Diluted ($/share)	0.52	0.35	2.70	2.95
Funds flow ^1	593.6	350.6	2,322.8	1,098.6
Basic ($/share) ^1	0.97	0.56	3.77	1.84
Diluted ($/share) ^1	0.97	0.55	3.74	1.82
Dividends paid or declared	67.2	42.3	237.2	126.1
Per share	0.11	0.07	0.39	0.21
Expenditures on property, plant and equipment ^2	179.0	1354.0	686.5	428.5
Total payout ratio (%) ^1	41	51	40	50
Net Debt ^1	1,913.1	1,154.6	1,913.1	1,154.6
Operating
Average daily production
Crude oil (bbls/d)	91,812	79,315	86,417	75,387
NGLs (bbls/d)	17,473	10,568	15,521	10,418
Natural gas (Mcf/d)	342,640	180,820	254,708	158,501
Total (boe/d) ^3	166,392	120,020	144,389	112,222
Average realized price ^1, 4
Crude oil ($/bbl)	102.50	89.40	114.68	77.90
NGLs ($/bbl)	46.84	52.24	55.30	41.16
Natural gas ($/Mcf)	5.56	4.97	5.62	3.91
Petroleum and natural gas revenues ($/boe) ^1	72.94	71.17	84.49	61.68
Operating netback ($/boe) ^1
Petroleum and natural gas revenues	72.94	71.17	84.49	61.68
Tariffs	(0.49)	(0.48)	(0.46)	(0.43)
Processing & other income	0.77	0.68	0.68	0.74
Marketing revenue	5.93	4.33	5.99	3.78
Petroleum and natural gas sales	79.15	75.70	90.70	65.77
Realized loss on commodity contracts	(1.43)	(8.13)	(4.66)	(5.94)
Royalties	(13.34)	(13.09)	(16.35)	(10.15)
Operating expenses	(14.13)	(13.49)	(14.54)	(13.58)
Transportation expenses	(2.12)	(2.12)	(2.18)	(2.20)
Marketing expenses	(5.87)	(4.34)	(5.94)	(3.80)
Operating netbacks	42.26	34.53	47.03	30.10
Share information (000s)
Common shares outstanding, end of period	608.7	615.8	608.7	615.8
Weighted average basic shares outstanding	610.8	627.8	616.5	598.6
Weighted average diluted shares outstanding	613.8	634.2	621.1	603.1

MESSAGE TO SHAREHOLDERS

2022 was an exceptional year for Whitecap with operational and financial results exceeding expectations. Production in the fourth quarter averaged 166,392 boe/d, ahead of our guidance of 165,000 boe/d despite unexpected downtime due to the extreme cold weather in December. We achieved record annual production of 144,389 boe/d on capital expenditures of $687 million, compared to guidance of 144,000 boe/d and $670 - $690 million, respectively.

Our 2022 year end reserves report highlights efficient and profitable organic growth with proved developed producing ("PDP") reserves per share increasing 19% and with our PDP finding and development ("F&D") cost¹ of $13.20 per boe generating a recycle ratio¹ of 3.6x. We continue to enhance long-term sustainability with total proved ("TP") finding, development and acquisitions ("FD&A") cost¹ of $16.15 per boe generating a recycle ratio of 2.9x and growing TP reserves per share by 49% over the prior year.

The XTO Energy Canada ("XTO") acquisition, which closed on August 31, 2022 for net cash consideration of $1.7 billion, was transformational to Whitecap as it added 32,000 boe/d from the Montney and Duvernay formations in Northwest Alberta and included 672,000 acres of land with over 2,000 drilling locations⁵, significantly increasing the sustainability of our dividend plus growth model.

Our strategy of operational execution enhanced by strategic acquisitions once again resulted in significant per share growth for our shareholders. Compared to the prior year, production per share⁶ increased 25%, funds flow per share increased 105%, free funds flow per share increased 137% and reserves per share also increased significantly in all categories.

Whitecap generated record funds flow of over $2.3 billion, and after capital expenditures of $687 million, had free funds flow¹ of $1.6 billion. 2022 was also another year of significant capital returns to shareholders. We started 2022 with a monthly dividend of $0.0225 per share and increased it by 63% to end 2022 at $0.0367 per share. Subsequent to year end, we increased the monthly dividend by another 32% to $0.0483 per share. We also repurchased 25 million common shares at an average price of $9.72 per share for total capital returned to shareholders (dividends plus share repurchases) of $480 million in 2022.

After the closing of the XTO acquisition, net debt was $2.2 billion and was quickly reduced to $1.9 billion (13%) within four months with the significant free funds flow generated by our consolidated asset base. Subsequent to year end, we further reduced net debt to $1.5 billion through the disposition of several non-strategic assets.

We highlight the following fourth quarter and full year 2022 financial and operating results:

• Record Funds Flow. Whitecap generated $2.3 billion of funds flow in 2022 ($3.74 per share), the highest in the Company's thirteen-year history and 82% higher than the second highest funds flow per share year in 2014. Fourth quarter funds flow of $594 million ($0.97 per share) was the second highest quarterly funds flow in Company history and was the first full quarter that included the acquired XTO assets. Full year and fourth quarter 2022 operating netback of $47.03 per boe and $42.26 per boe, respectively, were 56% and 22% higher than the full year and fourth quarter of 2021, respectively.
• Strong Operational Performance. Full year 2022 average production of 144,389 boe/d was a 25% increase on a per share basis over 2021, while fourth quarter production of 166,392 boe/d was up 15% over the third quarter and 43% over the fourth quarter of 2021, both on a per share basis. Asset level outperformance continued in the fourth quarter with average production exceeding fourth quarter guidance of 165,000 boe/d, despite extreme cold weather that reduced our production by approximately 10,000 boe/d for five days in December.
• Return of Capital Strategy. Shareholder returns totalled $480 million in 2022, including $237 million in base dividends plus $243 million of share repurchases. Our current annual base dividend of $0.58 per share is 49% higher than the $0.39 per share paid in 2022, which was already 86% higher than our base dividend of $0.21 per share paid in 2021. We remain focused on sustainable increases to our base dividend supplemented by share repurchases and/or special dividends to meet our return of capital framework.
• Balance Sheet Strength. Whitecap's year end net debt of $1.9 billion equates to a debt to EBITDA ratio⁷ of 0.7x and EBITDA to interest expense ratio⁷ of 45.4x, both well within our bank covenants of not greater than 4.0x and not less than 3.5x respectively. Net debt has been reduced to $1.5 billion on total debt capacity of $3.1 billion with the closing of three non-strategic asset dispositions subsequent to year end, further strengthening the Company's balance sheet.

2022 Year End Reserves

Our 2022 year end reserves were excellent across all categories and metrics as strong operational execution was enhanced by our successful acquisition strategy. We continue to see significant synergies through the integration of assets acquired since late 2020 and, when combined with operational outperformance, has led to increased profitability for our shareholders.

The strategic acquisitions completed in 2022, most notably the XTO acquisition with assets in the Montney and Duvernay, have further enhanced our unconventional asset base, adding multi-decade growth potential to complement our low decline, high netback conventional oil asset base. Pro forma the recent dispositions, we now have 6,584 (5,675 net) drilling locations⁵ of which only 36% of such locations have been booked in our reserve report, which provides us with over 25 years of profitable and sustainable growth in production and funds flow.

We highlight the following 2022 year end reserve report results:

• Focused on Per Share Results. PDP reserves increased 18% to 377.2 million boe, TP reserves increased 47% to 803.5 million boe and total proved plus probable ("TPP") reserves increased 58% to 1,218.3 million boe, compared to the prior year. On a per share basis, PDP reserves increased 19%, TP reserves increased 49% and TPP reserves increased 61%.
• Long-Term Sustainability. PDP, TP and TPP reserve life index ("RLI") of 6.2 years, 13.2 years and 20.1 years, respectively, reflects our unique asset base, which combines low decline, long life oil weighted assets with a deep inventory of unconventional high impact assets, providing for long-term sustainable and profitable growth.
• Profitable Growth Drives Strong Recycle Ratios. Our TP FD&A cost of $16.15 per boe and TPP FD&A cost of $12.28 per boe generated recycle ratios of 2.9x and 3.8x, respectively. Our PDP F&D cost of $13.20 per boe generated a recycle ratio of 3.6x and reflects strong operational execution by our teams in 2022. Our TP and TPP recycle ratios increased 32% and 43%, respectively as compared to 2021.
• Growing Net Present Value per Share. PDP NPV, using a 10% discount rate¹, increased by 42% to $10.67 per share, TP NPV increased by 77% to $19.08 per share and TPP NPV increased by 81% to $27.60 per share, as compared to the prior year. The NPV calculations performed by McDaniel used an average 2023-2027 WTI price of US$78.51/bbl (three consultants average).

Outlook

Our focus in 2023 is continued operational execution to achieve our production guidance of 160,000 – 162,000 boe/d (13% production per share growth) and our capital expenditure guidance of $900 - $950 million.

Our 2023 financial milestones we look forward to reporting to shareholders on are (1) achieving net debt of $1.3 billion which represents a debt to EBITDA ratio of 1.0x at a stress test price deck of US$50/bbl WTI and $3.50/GJ AECO, (2) further increasing our monthly dividend by 26% to $0.0608 per share ($0.73 per share/annum), and (3) returning 75% of free funds flow back to shareholders which includes our targeted annual dividend of $0.73 per share.

Our balance sheet is in excellent shape, with net debt currently at $1.5 billion which represents a debt to EBITDA ratio of 0.7x at current strip prices⁸ and provides us with $1.6 billion of undrawn capacity. Our balance sheet will continue to strengthen further to approximately $1.0 - $1.2 billion by year end 2023.

Over the next five years, we are targeting organic production growth to 200,000 boe/d, which is forecasted to generate over $4.5 billion of free funds flow (~$7.35 per share) at US$75/bbl WTI and $3.50/GJ AECO.

Our strategy is to provide shareholders with sustainable production per share growth (3% - 8% per year) combined with a stable and growing dividend. Beyond 2023, we will continue to look for opportunities to enhance our organic growth plans and long-term value through business development initiatives.

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 updating you on our progress throughout the year.

NOTES

¹     Funds flow, funds flow basic ($/share), funds flow diluted ($/share) and net debt are capital management measures. Total payout ratio, average realized price, petroleum and natural gas revenues, and NPV (10% discount rate) per share figures are supplementary financial measures. Operating netback and free funds flow are non-GAAP financial measures. Operating netbacks ($/boe), F&D costs, FD&A costs, recycle ratio and free funds flow per share 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".

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 and Product Type Information in this press release for additional disclosure.

⁴   Prior to the impact of risk management activities and tariffs.

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.

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     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.

⁸   Based on the following commodity pricing and exchange rate assumptions: WTI of US$76/bbl, USD/CAD of $1.35 and AECO of C$2.49/GJ.

2022 RESERVES REVIEW

Our 2022 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, 2022. 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, 2023 which is available on McDaniel's website at www.mcdan.com.

Reserves included are Company share 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. Reserves related to the dispositions that closed subsequent to December 31, 2022, are included. Additional reserve information as required under NI 51-101 will be included in our Annual Information Form which will be filed on SEDAR. The numbers in the tables below may not add due to rounding.

Summary of Reserves

Reserves as at December 31, 2022

	Company Share Reserves
Description	Light & Medium Oil (Mbbl)	Tight Crude Oil (Mbbl)	Conventional Natural Gas (MMcf)
Proved developed producing	220,371	324	377,396
Proved developed non-producing	2,941	727	6,172
Proved undeveloped	106,514	9,393	190,648
Total proved	329,827	10,444	574,216
Probable	119,065	8,851	242,773
Total proved plus probable	448,892	19,295	816,989

Description	Shale Gas (MMcf)	Natural Gas Liquids Mbbl)	Total (Mboe)
Proved developed producing	266,241	49,224	377,192
Proved developed non-producing	47,926	4,101	16,786
Proved undeveloped	944,099	104,466	409,498
Total proved	1,258,266	157,791	803,475
Probable	877,640	100,163	414,815
Total proved plus probable	2,135,906	257,954	1,218,291

Net Present Values of Future Net Revenue

Summary of Before Tax Net Present Values of Future Net Revenue (Forecast Pricing)
As at December 31, 2022

	Before Tax Net Present Value ($ millions) ^(1)
	Discount Rate
Reserves Category	0 %	5 %	10 %	15 %	20 %
Proved Developed Producing	9,551	7,916	6,563	5,638	4,984
Proved developed non-producing	491	407	353	315	286
Proved undeveloped	9,962	6,728	4,813	3,584	2,747
Total Proved	20,004	15,051	11,729	9,537	8,016
Total Probable	14,061	7,967	5,240	3,754	2,845
Total Proved + Probable	34,065	23,018	16,969	13,291	10,861

⁽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 2022 is $6.3 billion undiscounted ($4.6 billion discounted at 10%).

Also included in FDC are 1,584 (1,359 net) proved booked drilling locations and 367 (304 net) probable booked drilling locations.

($ millions)	Total Proved	Total Proved plus Probable
2023	862	906
2024	1,164	1,214
2025	1,284	1,433
2026	1,132	1,275
2027	930	1,263
Remainder	940	2,216
Total FDC, Undiscounted	6,312	8,307
Total FDC, Discounted at 10%	4,576	5,797

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:

	2022	2021	2020	Three Year Weighted Average
Proved Developed Producing
F&D costs ^(1)	$13.20	$16.28	$21.87	$16.28
F&D recycle ratio ^(2)	3.6x	1.8x	0.9x	2.3x
FD&A costs ^(3)	$27.34	$14.95	$19.25	$21.10
FD&A recycle ratio ^(2)	1.7x	2.0x	1.1x	1.7x
Total Proved
F&D costs ^(1)	$16.90	$5.05	$3.61	$10.30
F&D recycle ratio ^(2)	2.8x	5.9x	5.7x	4.4x
FD&A costs ^(3)	$16.15	$13.67	$14.74	$15.06
FD&A recycle ratio ^(2)	2.9x	2.2x	1.4x	2.4x
Total Proved Plus Probable
F&D costs ^(1)	$19.53	$4.63	$19.16	$14.86
F&D recycle ratio ^(2)	2.4x	6.4x	1.1x	3.4x
FD&A costs ^(3)	$12.28	$11.22	$12.51	$12.00
FD&A recycle ratio ^(2)	3.8x	2.7x	1.7x	3.0x

⁽¹⁾  F&D costs are calculated as the sum of development capital of $669.9 million (excluding corporate and capitalized G&A) plus the change in FDC for the period of -$34.0 million (PDP), $200.5 million (TP) and $278.5 million (TPP), divided by the change in reserves volumes that are characterized as development for the period.

⁽²⁾  Recycle ratio is calculated as operating netback divided by F&D or FD&A costs. Our operating netback in 2022 was $47.03/boe.

⁽³⁾  FD&A costs are calculated as the sum of development capital of $669.9 million (excluding corporate and capitalized G&A) plus acquisition capital of $2,349.5 million plus the change in FDC for the period of $10.7 million (PDP), $1,791.1 million (TP) and $2,862.9 million (TPP), divided by the change in total reserves volumes, other than from production, for the period. 

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:

	2022	2021	2020	Three Year Weighted Average
Proved Developed Producing
Production replacement ^(1)	208 %	372 %	34 %	226 %
RLI (years) ^(2)	6.2	7.3	9.0	7.2
Total Proved
Production replacement ^(1)	589 %	545 %	101 %	471 %
RLI (years) ^(2)	13.2	12.5	15.6	13.5
Total Proved Plus Probable
Production replacement ^(1)	952 %	737 %	100 %	712 %
RLI (years) ^(2)	20.1	17.6	21.8	19.7

⁽¹⁾  Production replacement ratio is calculated as total reserve additions (including acquisitions net of dispositions) divided by annual production. Whitecap's production averaged 144,389 boe/d in 2022.

⁽²⁾  RLI is calculated as total Company share reserves divided by the annualized fourth quarter actual production of 166,392 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 23, 2023.

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 belief that we continue to enhance our long term sustainability; the future value of our reserves; our estimated future drilling locations associated with the XTO acquisitions; our belief that the XTO acquisition significantly increases the sustainability of our dividend plus growth model; our strategy of operational execution enhanced by strategic acquisitions; our focus on sustainable increases to our base dividend supplemented by share repurchases and/or special dividends to meet our return of capital framework; that we continue to see significant synergies through the integration of assets acquired since late 2020; our belief that the strategic acquisitions completed in 2022 added multi-decade growth potential to complement our low decline, high netback conventional oil asset base; our estimated future drilling locations associated with our assets, which provide us with over 25 years of profitable and sustainable growth in production and funds flow; our RLI calculations;  our belief that our unique asset base, which combines low decline, long life oil weighted assets with a deep inventory of unconventional high impact assets, provides for long-term sustainable and profitable growth; that our focus in 2023 is continued operational execution; our forecasts for average daily production (including by product type) production per share growth and capital expenditures for 2023; our 2023 financial milestones including, (1) achieving net debt of $1.3 billion which represents a debt to EBITDA ratio of 1.0x at a stress test price deck of US$50/bbl WTI and $3.50/GJ AECO, (2) further increasing our monthly dividend by 26% to $0.0608 per share, and (3) returning 75% of free funds flow back to shareholders which includes our targeted annual dividend of $0.73 per share; that our balance sheet will continue to strengthen further through 2023; our target net debt of $1.0 - $1.2 billion; that over the next five years we are targeting organic production growth to 200,000 boe/d, which is forecasted to generate over $4.5 billion of free funds flow at US$75/bbl WTI and $3.50/GJ AECO; that our strategy is to provide shareholders with sustainable production per share growth (3% - 8% per year) combined with a stable and growing dividend; that beyond 2023 we will continue to look for opportunities to enhance our organic growth plans and long-term value through business development initiatives; and, our future development costs. Statements relating to "reserves" are also deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated and that the reserves can be profitably produced in the future.

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 other than as disclosed herein); 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 impact (and the duration thereof) that the COVID-19 pandemic will have on (i) the demand for crude oil, NGLs and natural gas, (ii) our supply chain, including our ability to obtain the equipment and services we require, and (iii) our ability to produce, transport and/or sell our crude oil, NGLs and natural gas; 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 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 state of the economy and the exploration and production business; results of operations; performance; 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; and our ability to access capital and the cost and terms thereof.

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 they involve 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 buybacks 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 2023 forecasts and forecasts for the next five years (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; 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; 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; ability 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 regulations; 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, 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.sedar.com).

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 Whitecap's forecast 2023 capital expenditures, our 2023 financial milestones including reaching net debt of $1.3 billion, our targeted annual base dividend level of $0.73 per share, and the percent of free funds flow to be returned to shareholders based on reaching our net debt target of $1.3 billion, our 2023 targeted net debt of $1.0 - $1.2 billion, our forecasted cumulative free funds flow over the next five years (including on a per share basis) at US$75/bbl WTI and $3.50/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

Reserves Volumes and Net Present Values

All reserve references in this press release are "Company share reserves". Company share reserves are our total working interest reserves before the deduction of any royalties and including any royalty interests payable to the Company.

It should not be assumed that the present worth of estimated future amounts presented in the tables above represents the fair market value of the reserves. There is no assurance that the forecast prices and costs assumptions will be attained, and variances could be material. The recovery and reserve estimates of the crude oil, natural gas liquids and natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual crude oil, natural gas and natural gas liquids reserves may be greater than or less than the estimates provided herein.

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.

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 "acquisition capital", "development capital", "F&D costs", "FD&A costs", "operating netback", "production replacement", "production replacement ratio", "recycle ratio", and "reserve life index". 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.

"Acquisition capital" is a non-GAAP financial measure used in the determination of FD&A costs, which is a non-GAAP ratio.  The most directly comparable GAAP measure to acquisition capital is expenditures on corporate acquisitions, net of cash acquired, and expenditures on property acquisitions. Acquisition capital includes net property acquisitions less any non-cash amounts and the announced purchase price of corporate acquisitions including any estimated working capital deficit or surplus rather than the amounts allocated to property, plant and equipment for accounting purposes and the aggregate exploration and development capital spending within the year on reserves that are categorized as acquisitions less the disposition of certain processing facilities. The following table details the calculation of Acquisition capital:

	Year ended Dec. 31,
($ millions)	2022	2021	2020
Expenditures on property acquisitions	8.0	130.8	5.4
Add: non-cash consideration for property acquisitions	0.6	21.9	-
Corporate acquisitions	2,364.9	1,848.8	17.0
Less: Property dispositions	24.0	113.5	-
Acquisition Capital	2,349.5	1,888.0	22.4

"Development capital" is a non-GAAP financial measure used in the determination of F&D costs and FD&A costs, which are non-GAAP ratios.  The most directly comparable GAAP measure to development capital is expenditures on property, plant and equipment. Development capital means the aggregate exploration and development costs incurred in the financial year on reserves that are categorized as development. Development capital excludes capitalized administration costs. The following table reconciles expenditures on property, plant and equipment to Development Capital:

	Year ended Dec. 31,
($ millions)	2022	2021	2020
Expenditures on property, plant and equipment	686.5	428.5	195.9
Less: expenditures on corporate and capitalized general and administrative expenses	16.6	14.6	8.2
Development Capital	669.9	413.9	187.7

"F&D costs" are calculated as the sum of development capital (excluding corporate and capitalized general and administrative expense) plus the change in FDC for the period when appropriate, divided by the change in reserves that are characterized as development for the period. Development capital is a non-GAAP financial measure used as a component of F&D costs. Management uses F&D costs as a measure of capital efficiency for organic reserves development.

"FD&A costs" are calculated as the sum of development capital (excluding corporate and capitalized general and administrative expense) plus acquisition capital plus the change in FDC for the period when appropriate, divided by the change in total reserves, other than from production, for the period. Development capital and acquisition capital are non-GAAP financial measures used as components of FD&A costs. Management uses FD&A costs as a measure of capital efficiency for organic and acquired reserves development.

"Production replacement ratio" or "production replacement" is calculated as total reserve additions (including acquisitions net of dispositions) divided by annual production.

"Recycle ratio" is calculated by dividing operating netback per boe by F&D costs or FD&A costs for the year. Operating netback per boe is a non-GAAP ratio that uses operating netback, a non-GAAP financial measure, as a component. Development capital, a non-GAAP financial measure, is used as a component of F&D costs. Development capital and acquisition capital, both non-GAAP financial measures, are used as components of FD&A costs. Management uses recycle ratio to relate the cost of adding reserves to the expected cash flows to be generated.

"Reserve life index" or "RLI" is calculated as total Company share reserves divided by annualized fourth quarter actual production.

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.

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's reserves evaluation effective December 31, 2022 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 6,584 (5,675 net) total drilling locations identified herein, 1,440 (1,238 net) are proved locations, 309 (254 net) are probable locations, and 4,835 (4,183 net) are unbooked locations.
• Of the over 2,000 drilling locations identified herein on the XTO lands, there are 2,024 (1,910 net) total locations, of which 148 (130 net) are proved locations, 89 (83 net) are probable locations, and 1,787 (1,697 net) are unbooked locations.

Unbooked locations 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 & 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 NI 51-101. 

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.

The Company's average daily production for the quarters and years ended December 31, 2022 and 2021, forecast average daily production for the quarter and year ended December 31, 2022, average daily production acquired from the XTO transaction, average daily production impacted by weather related downtime, and forecast average daily production for 2023 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:

	Q4/2022	Q4/2022 Guidance	2022	2022 Guidance
Light and medium oil (bbls/d)	80,776	81,210	80,441	80,550
Tight oil (bbls/d)	11,036	8,750	5,976	5,400
Crude oil (bbls/d)	91,812	89,960	86,417	85,950
NGLs (bbls/d)	17,473	17,625	15,521	15,555
Shale gas (Mcf/d)	181,478	189,820	97,299	99,400
Conventional natural gas (Mcf/d)	161,162	154,668	157,409	155,570
Natural gas (Mcf/d)	342,640	344,488	254,708	254,970
Total (boe/d)	166,392	165,000	144,389	144,000

		Q4/2021	2021	2023 Guidance (Mid-point)
Light and medium oil (bbls/d)		75,628	73,458	72,500
Tight oil (bbls/d)		3,687	1,929	13,000
Crude oil (bbls/d)		79,315	75,387	85,500
NGLs (bbls/d)		10,568	10,418	17,000
Shale gas (Mcf/d)		42,993	20,402	207,000
Conventional natural gas (Mcf/d)		137,827	138,099	144,000
Natural gas (Mcf/d)		180,820	158,501	351,000
Total (boe/d)		120,020	112,222	161,000

			XTO Acquisition	Weather Downtime
Light and medium oil (bbls/d)			-	5,350
Tight oil (bbls/d)			7,100	400
Crude oil (bbls/d)			7,100	5,750
NGLs (bbls/d)			2,700	800
Shale gas (Mcf/d)			133,200	8,800
Conventional natural gas (Mcf/d)			-	11,900
Natural gas (Mcf/d)			133,200	20,700
Total (boe/d)			32,000	10,000

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.

"Acquisition Capital" and "Development Capital" are non-GAAP financial measures and, "F&D Costs", "FD&A Costs" and "recycle ratio" are non-GAAP ratios. See "Oil and Gas Metrics".

"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 audited annual consolidated financial statements for the year ended December 31, 2022, 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 Payout Ratios" section of our management's discussion and analysis for the year ended December 31, 2022 which is incorporated herein by reference, and available on SEDAR at www.sedar.com. In addition, see the following table which reconciles cash flow from operating activities to funds flow and free funds flow:

	Three months ended Dec. 31,		Year ended Dec. 31,
($ millions)	2022	2021	2022	2021
Cash flow from operating activities	555.8	329.2	2,183.1	1,124.0
Net change in non-cash working capital items	37.8	21.4	139.7	(25.3)
Funds flow	593.6	350.6	2,322.8	1,098.7
Expenditures on PP&E	179.0	135.0	686.5	428.5
Free funds flow	414.6	215.6	1,636.3	670.2
Total payout ratio (%)	41	51	40	50
Funds flow per share, basic	0.97	0.56	3.77	1.84
Funds flow per share, diluted	0.97	0.55	3.74	1.82

"Free funds flow per share" is a non-GAAP ratio calculated by dividing free funds flow by the weighted average number of diluted shares outstanding for the relevant period. Free funds flow is a non-GAAP financial measure component of free funds flow per share. Free funds flow per share 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.

"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 audited annual consolidated financial statements for the year ended December 31, 2022 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 audited annual consolidated financial statements for the year ended December 31, 2022 for additional disclosures. The following table reconciles the Company's long-term debt to net debt:

			Year ended Dec. 31,
Net Debt ($ millions)			2022	2021
Long-term debt			1,844.6	1,055.7
Accounts receivable			(480.2)	(304.8)
Deposits and prepaid expenses			(22.7)	(10.5)
Accounts payable and accrued liabilities			549.1	400.4
Dividends payable			22.3	13.8
Net Debt			1,913.1	1,154.6

"NPV (10% discount rate) per share figures" are supplementary financial measures and are comprised of the before tax NPV for PDP, TP and TPP reserves, discounted at 10 percent, as determined in accordance with NI 51-101, divided by diluted weighted average common shares outstanding for the period.

"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 year ended December 31, 2022, which is incorporated herein by reference, and available on SEDAR at www.sedar.com. A reconciliation of operating netbacks to petroleum and natural gas revenues is set out below:

	Three months ended Dec. 31,		Year ended Dec. 31,
Operating Netbacks ($ millions)	2022	2021	2022	2021
Petroleum and natural gas revenues	1,116.5	785.8	4,452.9	2,526.3
Tariffs	(7.5)	(5.3)	(24.1)	(17.6)
Processing & other income	11.8	7.5	35.9	30.5
Marketing revenues	90.8	47.9	315.7	154.8
Petroleum and natural gas sales	1,211.6	835.9	4,780.4	2,694.0
Realized loss on commodity contracts	(21.9)	(89.8)	(245.5)	(243.3)
Royalties	(204.2)	(144.5)	(861.8)	(415.9)
Operating expenses	(216.3)	(149.0)	(766.3)	(556.3)
Transportation expenses	(32.5)	(23.4)	(114.8)	(90.2)
Marketing expenses	(89.8)	(48.0)	(313.0)	(155.8)
Operating netbacks	646.9	381.2	2,479.0	1,232.5

"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.

"Petroleum and natural gas revenues ($/boe)" is a supplementary financial measure calculated by dividing this component of petroleum and natural gas sales, disclosed in Note 16 "Revenue" to the Company's audited annual consolidated financial statements for the year ended December 31, 2022, by the Company's total production volumes for the period.

"Total payout ratio" is a supplementary financial measure calculated as dividends paid or declared plus expenditures on PP&E, divided by funds flow. Management believes that total payout ratio provides a useful measure of Whitecap's capital reinvestment and dividend policy, as a percentage of the amount of funds flow.

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]