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Whitecap Resources Inc. Announces Strong 2020 Results, Completes Transformation to a Leading Light Oil Producer and Provides 2021 Budget

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CALGARY, AB, Feb. 24, 2021 /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, 2020.

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, 2020 which are available at www.sedar.com and on our website at www.wcap.ca.

FINANCIAL AND OPERATING HIGHLIGHTS


Three months ended December 31

Twelve months ended December 31

Financial ($000s except per share amounts)

2020

2019

2020

2019

Petroleum and natural gas revenues

238,489

369,190

901,556

1,418,476

Net income (loss)

331,951

(203,946)

(1,844,973)

(155,873)

    Basic ($/share)

0.81

(0.50)

(4.52)

(0.38)

    Diluted ($/share)

0.81

(0.50)

(4.52)

(0.38)

Funds flow

104,650

184,546

433,881

675,610

    Basic ($/share)

0.26

0.45

1.06

1.64

    Diluted ($/share)

0.25

0.45

1.06

1.63

Dividends paid or declared

17,468

35,018

87,276

138,341

    Per share

0.04

0.09

0.21

0.34

Expenditures on property, plant and equipment

21,713

98,762

195,886

403,977

Total payout ratio (%) (1)

37

72

65

80

Property acquisitions

26

410

5,381

4,016

Property dispositions

-

(266)

-

(978)

Corporate acquisition

-

-

18,417

-

Net debt

1,083,029

1,193,267

1,083,029

1,193,267

Operating





Average daily production





    Crude oil (bbls/d)

48,527

58,044

52,656

55,413

    NGLs (bbls/d)

4,874

4,805

4,982

4,503

    Natural gas (Mcf/d)

62,289

70,811

66,146

66,801

 Total (boe/d) (2)

63,783

74,651

68,662

71,050

Average realized price (3)





    Crude oil ($/bbl)

47.52

64.42

42.19

66.11

    NGLs ($/bbl)

22.48

17.56

16.75

20.58

    Natural gas ($/Mcf)

2.84

2.68

2.39

1.95

 Total ($/boe)

40.64

53.76

35.88

54.70

Netbacks ($/boe)





    Petroleum and natural gas revenues

40.64

53.76

35.88

54.70

    Tariffs

(0.54)

(0.42)

(0.48)

(0.48)

    Processing & other income

0.73

0.50

0.74

0.69

    Marketing revenue

0.95

1.05

0.94

1.17

    Petroleum and natural gas sales

41.78

54.89

37.08

56.08

    Realized hedging gain (loss)

1.81

(0.37)

3.62

(0.78)

    Royalties

(5.89)

(8.88)

(4.82)

(9.79)

    Operating expenses

(11.96)

(11.85)

(11.84)

(12.38)

    Transportation expenses

(2.27)

(2.40)

(2.36)

(2.26)

    Marketing expenses

(0.97)

(1.05)

(0.94)

(1.14)

    Operating netbacks (1)

22.50

30.34

20.74

29.73

Share information (000s)





Common shares outstanding, end of period

409,234

409,619

409,234

409,619

Weighted average basic shares outstanding

408,468

409,579

408,371

412,000

Weighted average diluted shares outstanding

411,807

412,026

410,880

414,072

Notes:


(1)     

Total payout ratio and operating netbacks do not have a standardized meaning under GAAP. Refer to non-GAAP measures in this press release for additional disclosure and assumptions.

(2)     

Disclosure of production on a per boe basis in this press release consists of the constituent product types and their respective quantities disclosed in this table.

(3)     

Prior to the impact of hedging activities and tariffs.

MESSAGE TO SHAREHOLDERS

2020 was a year of significant uncertainty that brought many challenges to the energy sector. In response to changing market conditions including the sharp decline in global crude oil prices, Whitecap took decisive actions in early 2020 to protect our balance sheet, preserve liquidity and retain long term value for our shareholders. Our proactive decisions in the first quarter of the year allowed us to maintain our balance sheet strength, deliver strong financial results and positioned Whitecap for the strategic consolidation opportunities we executed on later in the year.

In the fourth quarter of 2020, our production was 5% higher than we forecasted. This allowed us to achieve average production in 2020 of 68,662 boe/d which generated funds flow of $434 million, invested $196 million in capital expenditures and returned $87 million to shareholders through cash dividends. Despite the extremely challenging environment, discretionary funds flow was $151 million which we used to improve our balance sheet strength by approximately $110 million resulting in year end net debt of $1.1 billion on total credit capacity of $1.77 billion.

Capital investment in 2020 decreased 52% to $195.9 million compared to $404.0 million in the prior year as we paused our drilling program at the end of March 2020, given the sharp decline in crude oil prices that had a severely negative impact on our expected return on capital employed. As a result of the limited capital program, our proved developed producing ("PDP") reserves decreased 7%, however, we were able to maintain total proved ("TP") and total proved plus probable ("TPP") reserves at levels comparable to the prior year.

We highlight the following 2020 financial and operating results:

  • Focus on sustainability. Funds flow of $433.9 million ($1.06 per share) and capital investment of $195.9 million resulted in free funds flow of $238.0 million. Free funds flow significantly exceeded dividend payments of $87.3 million in the year.

  • Balance sheet strength. Reduced net debt by $110.2 million to $1.08 billion on total credit capacity of $1.77 billion. The Company's credit facilities have two financial covenants being debt to earnings before interest, taxes, depreciation and amortization ("EBITDA") not exceeding 4.0 times and EBITDA to interest not less than 3.5 times. As at December 31, 2020, Whitecap's debt to EBITDA ratio was 2.2 times and its EBITDA to interest ratio was 11.2 times. For additional details refer to Note 11(a) "Bank Debt" in the audited annual consolidated financial statements for the year ended December 31, 2020.

  • Reduce and manage cost structure. Operating expenses per boe decreased 4% to $11.84/boe and general & administrative expenses per boe decreased 15% to $0.82/boe.

  • Capital discipline and operational excellence. Achieved average production of 68,662 boe/d compared to 71,050 boe/d in the prior year, a decrease of 3% on a significantly reduced capital program. Capital spending decreased 52% to $195.9 million compared to $404.0 million in the prior year.

  • Solid asset performance. Total proved finding, development and acquisition ("FD&A") costs decreased 18% to $14.74/boe compared to $17.95/boe in the prior year and total proved reserve additions replaced 101% of production. Total proved plus probable FD&A costs decreased 41% to $12.51/boe compared to $21.06 in the prior year and total proved plus probable reserve additions replaced 100% of production.

  • Prudent risk management. Realized commodity hedging gains of $10.6 million in the fourth quarter and $90.9 million for the year ended December 31, 2020.

In 2020, we also enhanced our ability to provide stronger shareholder returns through the announced strategic combinations with NAL Resources Limited ("NAL") and TORC Oil & Gas Ltd. ("TORC"). We closed the NAL acquisition on January 4, 2021 and closed the combination with TORC on February 24, 2021. Whitecap issued 58.3 million Whitecap common shares in exchange for all the issued and outstanding NAL shares and issued approximately 129.8 million Whitecap common shares in exchange for all the issued and outstanding TORC shares and assumed TORC's debt.

As a continuation of Whitecap's commitment to strong environment, social and corporate governance ("ESG") performance, we are also pleased to announce that Mary-Jo Case has been appointed to the Whitecap Board of Directors effective February 24, 2021 and will serve as a member of the Audit Committee and the Corporate Governance & Compensation Committee.

Ms. Case is an independent businesswoman with over 34 years of experience in the oil and gas industry. Prior to her retirement in 2015, Ms. Case was a member of the Senior Management Committee as Senior Vice President Land and Human Resources at Canadian Natural Resources Limited.  Ms. Case has a depth of experience in the areas of mergers, acquisitions and dispositions, negotiations, contracts, land administration and land systems.

Ms. Case is a member of the Canadian Association of Petroleum Landmen, a member of the Institute of Corporate Directors, a member of the Women's Executive Network and a member of Board Ready Women.  Ms. Case holds a Diploma in Legal Office Administration from Fanshawe College and holds the ICD.D designation from the Institute of Corporate Directors, Rotman School of Management.

Outlook

We had a solid finish to 2020 which positioned us well heading into 2021. This year is starting off strong with the closing of both NAL and TORC, a very active first quarter drilling program with Whitecap operating six rigs and upward momentum in crude oil and natural gas prices. Our Board of Directors has approved a 2021 capital expenditure budget of $280 to $300 million which will generate average production of approximately 100,000 boe/d (78% oil and NGLs) during the year. With the recent surge in both crude oil and natural gas prices, we now anticipate generating funds flow of $810 million with free funds flow of $520 million and a total payout ratio of 49% based on commodity prices of US$60/bbl WTI and C$2.50/GJ AECO. We will remain disciplined in our approach to capital allocation with a focus on balance sheet strength and generating the strongest economic returns on our capital program while retaining the option to accelerate production per share growth and/or increase return of capital to shareholders in the latter part of the year while being opportunistic with respect to future business opportunities.

Advancing forward, we have created a New Energy team to leverage Whitecap's technology and expertise to significantly advance business opportunities associated with carbon capture and storage. This team is tasked with advancing the regulatory and business framework for low carbon solutions, the evaluation of low carbon hydrogen and other new energy opportunities, with the objective of creating additional sustainable revenue streams for our shareholders in the future.

Whitecap remains well positioned to deliver strong shareholder returns in 2021 and beyond with many competitive advantages, including the following:

  • Top tier balance sheet. Whitecap has a secured covenant-based credit facility that is not subject to annual redeterminations. Discretionary funds flow of approximately $415 million will result in net debt of $1.0 billion and a debt to EBITDA ratio of 1.1x at US$60/bbl WTI and C$2.50/CJ AECO. Concurrent with the TORC closing, we increased our credit capacity by $230 million to $2 billion providing us with ample liquidity to continue to manage commodity price volatility.

  • Significant free funds flow profile. Our premium assets are characterized by high netback, low base production declines and strong capital efficiencies. In 2021, Whitecap is expected to generate approximately $520 million of free funds flow, supported by a peer leading base production decline rate of approximately 17%.

  • Sustainable cash dividends. Monthly dividend increased 6% from $0.01425 per share to $0.01508 per share ($0.181 per share annualized) effective with the March 2021 dividend payable in April 2021. The 2021 annual dividend of $105 million is covered approximately five times by free funds flow.

  • Robust drilling inventory. 5,265 (4,108.0 net) drilling locations for organic growth and value creation. Corporate production over 100,000 boe/d allows us to drive down costs and improve capital efficiencies by eliminating redundancies, streamlining processes and negotiating preferential rates through size and economies of scale.

  • Leader in sustainability. Whitecap remains committed to best-in-class ESG practices and continuously improving its ESG standards. Whitecap is the majority owner and operator of the Weyburn Unit, one of the largest carbon capture, utilization and storage projects in the world, currently sequestering more than 2 million tonnes of CO2 annually and providing the Company with its net negative emitter status.

2021 BUDGET DETAILS

As referenced earlier, in 2021 we expect to deploy capital expenditures of approximately $280 - $300 million to generate average production of approximately 100,000 boe/d. The capital program comprises of drilling 100 (81.6 net) horizontal wells including 53 (47.2 net) extended reach horizontal ("ERH") wells and 8 (5.9 net) horizontal injection wells. In addition to our drill, complete, equip and tie-in costs, we will be investing approximately $67 million on enhanced oil recovery ("EOR") operations and optimizations as well as health, safety, and environmental initiatives throughout the year. This continued focus on enhancing our base assets through EOR capital will allow us to maintain, and potentially improve upon, our low base production decline rate of approximately 17% for 2021.

Eastern Saskatchewan

This business unit includes our Weyburn property in addition to the TORC and NAL southeast Saskatchewan assets where we anticipate spending 30% of our capital budget which includes drilling 16 (11.0 net) wells.

At Weyburn, we will be following up on our very successful northeast CO2 flood pilot expansion by drilling 6 (3.9 net) wells in the second half of 2021. This includes two CO2 water-alternating-gas ("WAG") injectors and $29 million for CO2 purchases. The TORC acquisition has increased our working interest in the Weyburn Unit CO2 flood by 3.2% to 65.3%.

In southeast Saskatchewan, we anticipate drilling 10 (7.1 net) wells in the second half of the year, including 5 (2.1 net) non-operated wells. The operated activity is focused on assets where we can optimize economic returns by using our extensive experience with fracture stimulation design, extended reach horizontal drilling and EOR schemes.

Prior to closing, the TORC team completed a very active and successful January and February capital program where they drilled 25 (23.2 net) wells. On average, early well results are significantly exceeding our budget expectations.

Western Saskatchewan

This business unit includes our light oil Viking assets, as well as our southwest Saskatchewan properties, where we anticipate spending 28% of our capital budget drilling a total of 61 (52.5 net) wells.

In the first quarter, we will be drilling 38 (33.0 net) wells including 26 (22.5 net) Viking wells, 6 (5.6 net) Atlas wells and 4 (4.0 net) Lower Shaunavon horizontal oil wells. Capital efficiencies in our lower Shaunavon drilling program have been exceptional with average drill times down 30% and costs down 15%. Most of the gains can be attributed to a new wellbore design that has improved our meters per day drilled significantly.

Our second half 2021 program includes 23 (19.5 net) drills with 12 (9.5 net) wells in southwest Saskatchewan and 11 (10.0 net) Viking ERH oil wells. The 2021 southwest Saskatchewan program includes the drilling 3 (2.0 net) horizontal water injectors to mitigate production declines and increase resource recovery.

Central Alberta

This business unit consists primarily of the combined Whitecap, NAL and TORC Cardium light oil assets in Alberta and the liquids rich Ellerslie asset where we anticipate spending 15% of our capital budget drilling 13 (11.0 net) wells.

We will have drilled 6 (4.8 net) wells in Central Alberta by the end of the first quarter, all of which are expected to be on production prior to break-up. This includes 4 (3.7 net) Cardium oil producers, 1 (0.9 net) horizontal injector in West Pembina and 1 (0.2 net) non-operated Ellerslie liquids rich gas well.

The second half capital program of 7 (6.2 net) wells includes 2 (1.7 net) ERH Cardium wells with two-mile laterals in our new Kaybob/Rosevear area.  This area has suitable characteristics to apply ERH wellbores in combination with our optimized fracture stimulation design and placement which has proven successful in enhancing the economics in many analogous areas. The remaining drills will be 2 (2.0 net) 2-mile ERH Cardium oil wells in Olds and Garrington, 1 (0.8 net) horizontal liquids rich Ellerslie gas well and 2 (1.7 net) ERH wells in West Pembina, one of which will be a waterflood injector.

Capital allocation to the acquired assets from TORC and NAL is focused on accelerating the evaluation of the potential for enhancement of the existing inventory by utilizing methods and technology that Whitecap has repeatedly applied with success in analogous areas.

Northern Alberta & British Columbia

This business unit consists of our Boundary Lake, Deep Basin, Peace River Arch and Sturgeon assets where we expect to spend 23% of our capital budget drilling 10 (7.1 net) wells.

We will have an active first quarter in the area drilling 9 (6.1 net) wells including 6 (3.6 net) Cardium wells in Wapiti and 3 (2.5 net) Charlie Lake wells in our Valhalla area of which 6 (5.5 net) are ERH wells ranging from 1.5 to 2.0 miles in lateral length.

In the Wapiti program, we realized a step change in our drilling times and costs, decreasing both by approximately 20%. The gains were primarily through drilling design optimization and the benefits of multi well pad efficiencies. We anticipate these savings to be carried forward to future programs.

In addition to the drilling program, we participated in the completion of 1 (0.50 net) non-operated Montney oil well which was drilled in the fourth quarter of 2020. This well, along with the 1 (0.65 net) operated well which was completed in the fourth quarter of 2020, are in the process of being tied in and are expected to be on production by early April 2021. Production test results from both wells have been very encouraging.

2020 RESERVES REVIEW (WHITECAP PRIOR TO COMBINATIONS)

Our 2020 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, 2020. The reserves evaluation was based on the average forecast pricing of McDaniel, GLJ Petroleum Consultants ("GLJ") and Sproule Associates Limited ("Sproule") and foreign exchange rates at January 1, 2021 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. Additional reserve information as required under NI 51-101 will be included in our Annual Information Form which will be filed on SEDAR on or before March 30, 2021. The numbers in the tables below may not add due to rounding.

Summary of Reserves

Reserves as at December 31, 2020


Company Share Reserves

Description

Oil (Mbbl)

Gas (MMcf)

NGL (Mbbl)

Total (Mboe)

Proved producing

168,516

167,172

12,362

208,740

Proved non-producing

1,882

1,897

89

2,287

Proved undeveloped

113,536

164,887

11,214

152,232

Total proved

283,934

333,956

23,665

363,259

Probable

102,298

173,483

12,816

144,028

Total proved plus probable

386,233

507,439

36,481

507,287

Net Present Values

Summary of Before Tax Net Present Values (Forecast Pricing)
As at December 31, 2020


Before Tax Net Present Value ($MM) (1)


Discount Rate

Description

0%

5%

10%

15%

20%

Proved producing


2,680


2,472


2,013


1,679


1,444

Proved non-producing


57


39


29


23


18

Undeveloped


1,970


1,093


608


323


148

Total proved


4,707


3,603


2,649


2,025


1,610

Probable


4,271


2,196


1,359


937


693

Total proved plus probable


8,978


5,799


4,008


2,962


2,303

(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 TPP reserves at year end 2020 is $4.1 billion undiscounted ($2.6 billion discounted at 10%).

Also included in FDC are 1,307 (1,081.1 net) proved booked locations and 152 (106.6 net) probable booked locations.

($000s)

Total Proved

Total Proved plus Probable

2021

309,595

322,155

2022

508,464

521,500

2023

626,859

679,849

2024

567,548

617,478

2025

531,465

633,810

Remainder

1,020,576

1,295,107

Total FDC, Undiscounted

3,564,507

4,069,900

Total FDC, Discounted at 10%

2,301,218

2,614,045

Performance Measures (Including FDC)

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


2020

2019

2018

Three Year

Weighted

Average

Proved Developed Producing





F&D costs (1)

$21.87

$14.33

$13.06

$16.46

F&D recycle ratio (2)

0.9x

2.1x

2.2x

1.7x

FD&A costs (3)

$19.25

$14.45

$15.15

$16.30

FD&A recycle ratio (2)

1.1x

2.1x

1.9x

1.7x

Total Proved





F&D costs (1)

$3.61

$17.87

$22.70

$14.63

F&D recycle ratio (2)

5.7x

1.7x

1.3x

2.9x

FD&A costs (3)

$14.74

$17.95

$23.30

$18.61

FD&A recycle ratio (2)

1.4x

1.7x

1.3x

1.5x

Total Proved Plus Probable





F&D costs (1)

$19.16

$21.00

$24.83

$21.63

F&D recycle ratio (2)

1.1x

1.4x

1.2x

1.2x

FD&A costs (3)

$12.51

$21.06

$24.04

$19.15

FD&A recycle ratio (2)

1.7x

1.4x

1.2x

1.4x

(1)   

F&D costs are calculated as the sum of development capital of $187.7 million plus the change in FDC for the period of -$50.6 million (PDP), -$167.9 million (TP) and -$333.1 million (TPP), divided by the change in reserves 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 2020 was $20.74/boe.

(3)   

FD&A costs are calculated as the sum of development capital of $187.7 million plus acquisition capital of $22.4 million plus the change in FDC for the period of -$45.5 million (PDP), $163.5 million (TP) and $103.3 million (TPP), divided by the change in total reserves, other than from production, for the period.

Production Replacement and Reserve Life Index

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


2020

2019

2018

Three Year

Weighted

Average

Proved Developed Producing





Production replacement (1)

34%

100%

112%

82%

RLI (years) (2)

9.0

8.3

8.4

8.6

Total Proved





Production replacement (1)

101%

133%

128%

121%

RLI (years) (2)

15.6

13.3

13.3

14.1

Total Proved Plus Probable





Production replacement (1)

100%

169%

124%

131%

RLI (years) (2)

21.8

18.6

18.3

19.6

(1)

Production replacement ratio is calculated as total reserve additions (including acquisitions net of dispositions) divided by annual production. Whitecap's production averaged 68,662 boe/d in 2020.

(2)

RLI is calculated as total Company share reserves divided by the annualized fourth quarter actual production of 63,783 boe/d.

RESERVES EVALUATION (NAL & TORC)

The below tables reflect NAL's 2020 year end reserves as evaluated by independent reserves evaluator McDaniel and TORC's year end reserves as evaluated by independent reserves evaluator Sproule. All evaluated in accordance with the definitions, standards and procedures contained in the COGE Handbook and NI 51-101 as of December 31, 2020. The reserves evaluation was based on the average forecast pricing of McDaniel, GLJ and Sproule and foreign exchange rates at January 1, 2021 which is available on McDaniel's website at www.mcdan.com.

NAL Summary of Reserves

Reserves as at December 31, 2020


Company Share Reserves

Description

Oil (Mbbl)

Gas (MMcf)

NGL (Mbbl)

Total (Mboe)

Proved producing

15,505

149,020

9,783

50,125

Proved non-producing

-

3,655

80

690

Proved undeveloped

1,340

2,600

319

2,092

Total proved

16,844

155,275

10,182

52,906

Probable

4,697

39,435

2,493

13,762

Total proved plus probable

21,541

194,710

12,675

66,668

NAL Net Present Values

Summary of Before Tax Net Present Values (Forecast Pricing)
As at December 31, 2020


Before Tax Net Present Value ($MM) (1)


Discount Rate

Description

0%

5%

10%

15%

20%

Proved producing


16


269


282


263


241

Proved non-producing


3


2


1


-


-

Undeveloped


19


13


8


5


3

Total proved


39


283


291


268


244

Probable


235


151


107


82


66

Total proved plus probable


273


434


398


350


310

(1)       

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

TORC Summary of Reserves

Reserves as at December 31, 2020


Company Share Reserves

Description

Oil (Mbbl)

Gas (MMcf)

NGL (Mbbl)

Total (Mboe)

Proved producing

38,301

37,117

2,953

47,441

Proved non-producing

2,711

3,897

218

3,578

Proved undeveloped

22,563

30,670

1,929

29,604

Total proved

63,575

71,684

5,100

80,622

Probable

37,048

50,427

3,190

48,642

Total proved plus probable

100,623

122,112

8,290

129,265

TORC Net Present Values

Summary of Before Tax Net Present Values (Forecast Pricing)
As at December 31, 2020


Before Tax Net Present Value ($MM) (1)


Discount Rate

Description

0%

5%

10%

15%

20%

Proved producing


426


550


508


453


407

Proved non-producing


69


52


41


34


28

Undeveloped


388


237


143


83


45

Total proved


883


840


692


570


480

Probable


1,122


685


460


331


250

Total proved plus probable


2,006


1,524


1,152


901


730

(1)       

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

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.

CONFERENCE CALL AND WEBCAST

Whitecap has scheduled a conference call and webcast to begin promptly at 8:00 am MT (10:00 am ET) on Thursday, February 25, 2021.

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.

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; our budgeted 2021 capital expenditures and average production for 2021; our anticipated 2021 funds flow, free funds flow and payout ratio and the underlying assumptions; Whitecap's position to deliver strong shareholder returns in 2021 and beyond; our expected 2021 discretionary funds flow, net debt and debt to EBITDA ratio; our 2021 decline rate; our anticipated 2021 dividends; quantity of drilling locations in inventory; our ability to drive down costs and improve capital efficiencies by eliminating redundancies, streamlining processes and negotiating preferential rates through economies of scale; our 2021 capital program and the allocation thereof; the  number  of  wells  to  be  drilled in 2021 and  the  timing, location, and target  thereof; EOR  projects  and  anticipated  benefits  therefrom; capital efficiencies in our lower Shaunavon drilling program, including new wellbore design, and  anticipated  benefits  therefrom; use of ERH technology in combination with our optimized fracture stimulation design and placement and  anticipated  benefits  therefrom; timing of certain wells to be on production; our ability to significantly upgrade the existing inventory on the acquired assets from TORC and NAL; our Wapiti design optimization and multi well pad efficiencies and the anticipated benefits therefrom. 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 expectations and assumptions concerning prevailing commodity prices, exchange rates, interest rates, applicable royalty rates and tax laws; 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 reduce crude oil production and thereby arrest and reverse the steep decline in world crude oil prices; future production rates and estimates of operating costs; performance of existing and future wells; reserve volumes; anticipated timing and results of capital expenditures; 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; the impact of increasing competition; ability to efficiently integrate assets and employees acquired through acquisitions, ability to market oil and natural gas successfully and our ability to access capital.

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 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; health, safety and environmental risks; commodity price and exchange rate fluctuations; interest 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; failure to obtain required regulatory and other approvals; reliance on third parties and pipeline systems; and changes in legislation, including but not limited to tax laws, production curtailment, royalties and environmental regulations. 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 budgeted 2021 capital investments, funds flow, free funds flow, discretionary funds flow, net debt, debt to EBITDA ratio and dividends, 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 in this presentation 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

All reserve references in this press release are "Company share reserves". Company share reserves are the applicable company's 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.

References to crude oil or natural gas production in this press release refer to the light and medium crude oil and conventional natural gas, respectively, product types as defined in NI 51-101.

"Boe" means barrel of oil equivalent based on 6 mcf of natural gas to 1 bbl of oil. Boe's may be misleading, particularly if used in isolation. A boe conversion ratio of 6 mcf: 1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. In addition, given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value.

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 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" includes net property acquisitions less any non-cash amounts and the announced purchase price of corporate acquisition 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.

"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.

"F&D costs" are calculated as the sum of development capital plus the change in FDC for the period when appropriate, divided by the change in reserves that are characterized as development for the period.

"FD&A costs" are calculated as the sum of development capital 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.

"Operating netback" see "Non-GAAP Measures".

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

"Recycle ratio" is measured by dividing operating netback by F&D or FD&A cost per boe for the year.

"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 three categories: (i) proved locations; (ii) probable locations; and (iii) unbooked locations. Proved locations and probable locations are derived from McDaniel's reserves evaluation effective December 31, 2020 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 5,265 (4,108.0 net) total drilling locations identified herein, 1,738 (1,441.1 net) are proved locations, 305 (234.2 net) are probable locations, and 3,222 (2,432.7 net) are unbooked locations.
  • Of the 1,459 (1,187.7 net) FDC drilling locations identified herein, 1,307 (1,081.1 net) are proved locations, and 152 (106.6 net) are probable 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 unbooked 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

The following table indicates our average daily production (including production from our major areas). Disclosure of production on a per boe basis in this press release consists of the constituent product types and their respective quantities as disclosed in the following table:


Crude oil
(bbls/d)

NGLs
(bbls/d)

Natural gas
(Mcf/d)

Total
(boe/d)

Three months ended December 31, 2020





 Northwest Alberta and British Columbia

9,571

2,190

27,965

16,421

 Southeast Saskatchewan

13,920

501

2

14,422

 Southwest Saskatchewan

12,901

2

2,114

13,255

 West Central Alberta

6,380

1,968

26,111

12,700

 West Central Saskatchewan

5,744

213

6,083

6,971

 Other minor areas

11

-

14

14

 Total

48,527

4,874

62,289

63,783






Three months ended December 31, 2019





 Northwest Alberta and British Columbia

10,132

2,055

30,289

17,235

 Southeast Saskatchewan

13,815

429

29

14,249

 Southwest Saskatchewan

14,943

8

2,731

15,406

 West Central Alberta

8,247

1,968

29,103

15,065

 West Central Saskatchewan

10,896

344

8,644

12,681

 Other minor areas

11

1

15

15

 Total

58,044

4,805

70,811

74,651



 


Crude oil
(bbls/d)

NGLs
(bbls/d)

Natural gas
(Mcf/d)

Total
(boe/d)

Twelve months ended December 31, 2020





 Northwest Alberta and British Columbia

10,277

2,123

28,154

17,093

 Southeast Saskatchewan

13,777

518

12

14,297

 Southwest Saskatchewan

14,093

5

2,434

14,503

 West Central Alberta

6,833

2,070

27,616

13,506

 West Central Saskatchewan

7,655

266

7,925

9,242

 Other minor areas

21

-

5

21

 Total

52,656

4,982

66,146

68,662






Twelve months ended December 31, 2019





 Northwest Alberta and British Columbia

9,506

1,819

27,677

15,938

 Southeast Saskatchewan

13,845

457

15

14,304

 Southwest Saskatchewan

14,599

7

2,213

14,975

 West Central Alberta

8,269

1,933

29,062

15,045

 West Central Saskatchewan

9,180

288

7,856

10,777

 Other minor areas

14

(1)

(22)

11

 Total

55,413

4,503

66,801

71,050

Disclosure of production on a per boe basis in this press release consists of the constituent product types and their respective quantities as disclosed in the following table:


Crude oil
(bbls/d)

NGLs
(bbls/d)

Natural gas
(Mcf/d)

Total
(boe/d)

2021 Budget

69,560

8,990

128,700

100,000

NON-GAAP MEASURES

This press release includes non-GAAP measures as further described herein. These non-GAAP measures do not have a standardized meaning prescribed by International Financial Reporting Standards ("IFRS" or, alternatively, "GAAP") and, therefore, may not be comparable with the calculation of similar measures by other companies. See the Company's Management's Discussion and Analysis of financial condition and results of operation for the period ended December 31, 2020 for a reconciliation of the non-GAAP measures.

"Discretionary funds flow" represents funds flow less expenditures on property, plant and equipment ("PP&E") and dividends. Management believes that discretionary 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" represents funds flow less expenditures on 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. Previously, Whitecap also deducted dividends paid or declared in the calculation of free funds flow. The Company believes the change in presentation better allows comparison with both dividend paying and non-dividend paying peers.

"Operating netbacks" are determined by adding marketing revenue and processing & other income, deducting realized hedging losses or adding realized hedging gains and deducting tariffs, royalties, operating expenses, transportation expenses and marketing expenses from petroleum and natural gas revenues. Operating netbacks are per boe measures used in operational and capital allocation decisions. Presenting operating netbacks on a per boe basis allows management to better analyze performance against prior periods on a comparative basis.

"Total payout ratio" is 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.

SOURCE Whitecap Resources Inc.

Cision View original content: http://www.newswire.ca/en/releases/archive/February2021/24/c9012.html

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