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Whitecap Resources Inc. Announces 2019 Fourth Quarter / Year End Results and 2019 Reserves Evaluation


CALGARYFeb. 27, 2020 /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, 2019.

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 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)

2019

2018

2019

2018

Petroleum and natural gas revenues

369,190

272,397

1,418,476

1,519,845

Net income (loss)

(203,946)

6,966

(155,873)

65,128

Basic ($/share)

(0.50)

(0.02)

(0.38)

0.16

Diluted ($/share)

(0.50)

(0.02)

(0.38)

0.15

Funds flow

184,546

138,810

675,610

704,420

Basic ($/share)

0.45

0.33

1.64

1.69

Diluted ($/share)

0.45

0.33

1.63

1.67

Dividends paid or declared

35,018

33,611

138,341

132,295

Per share

0.09

0.08

0.34

0.32

Expenditures on PP&E

98,762

76,485

403,977

440,499

Total payout ratio (%) (1)

72

79

80

81

Property acquisitions

410

15,157

4,016

35,249

Property dispositions

(266)

(205)

(978)

(11,681)

Corporate acquisition

53,916

Net debt

1,193,267

1,296,330

1,193,267

1,296,330

Operating

Average daily production

Crude oil (bbls/d)

58,044

57,072

55,413

58,511

NGLs (bbls/d)

4,805

4,656

4,503

4,397

Natural gas (Mcf/d)

70,811

68,739

66,801

69,042

Total (boe/d) (2)

74,651

73,185

71,050

74,415

Average realized price (3)

Crude oil ($/bbl)

64.42

47.22

66.11

66.46

NGLs ($/bbl)

17.56

29.52

20.58

35.90

Natural gas ($/Mcf)

2.68

1.87

1.95

1.70

Total ($/boe)

53.76

40.46

54.70

55.96

Netbacks ($/boe)

Petroleum and natural gas revenues

53.76

40.46

54.70

55.96

Tariffs

(0.42)

(0.60)

(0.48)

(0.72)

Processing and other income

0.50

0.44

0.69

0.45

Blending revenue

1.05

1.13

1.17

0.47

Petroleum and natural gas sales

54.89

41.43

56.08

56.16

Realized hedging loss

(0.37)

4.77

(0.78)

(2.36)

Royalties

(8.88)

(6.77)

(9.79)

(9.87)

Operating expenses

(11.85)

(12.28)

(12.38)

(12.05)

Transportation expenses

(2.40)

(2.20)

(2.26)

(2.17)

Blending expenses

(1.05)

(0.92)

(1.14)

(0.38)

Operating netbacks (1)

30.34

24.03

29.73

29.33

Share information (000s)

Common shares outstanding, end of period

409,619

414,063

409,619

414,063

Weighted average basic shares outstanding

409,579

415,714

412,000

417,061

Weighted average diluted shares outstanding

412,026

418,784

414,072

420,587

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

We are pleased to report strong financial and operating results for 2019. We achieved average production of 71,050 boe/d on capital expenditures of $404 million compared to our guidance of 70,000 – 72,000 boe/d on capital expenditures of $425 – $475 million as press released on December 18, 2018. We subsequently reduced our capital budget on August 26, 2019 to $400 million with no change to our 2019 average production. We achieved mid case production guidance on much lower capital spending through the efficient execution of our capital program and reduced our net debt by $103.1 million. Our commitment to returning capital to shareholders in 2019 resulted in $19.6 million spent on share repurchases and a 5.6% increase to the annual dividend with total dividends paid in 2019 of $138.3 million.

In addition to the success of our capital program, we have been actively advancing our organic growth initiatives which resulted in enhanced economics on 27 (20.2 net) existing drilling locations and the identification of 244 (184.2 net) new drilling locations, of which 144 (84.2 net) were the result of the recent Montney oil joint venture in Karr. We have been able to organically replace 126% of the 193 (166.3 net) wells we drilled in 2019. Our drilling inventory was also upgraded in quality as reserves per location added were 1.8 times higher than reserves per location drilled.

With respect to our reserves over the past year, we remained focused on profitably converting undeveloped reserves to proved developed reserves (“PDP”) and funds flow and, at the same time, growing our total proved (“TP”) and total proved plus probable (“TPP”) reserves to support future funds flow growth. Undeveloped reserves were converted to PDP reserves and funds flow at a low cost of $14.33/boe, resulting in a very profitable recycle ratio of 2.1 times. PDP, TP and TPP reserves increased per debt adjusted share by 7%, 9% and 11%, respectively.

In 2019, as part of our commitment to responsible development of our assets, we created a board level sustainability committee focused on evaluating risk, understanding our emissions and expanding the breadth and depth of our disclosures. Whitecap operates one of the largest carbon capture, utilization and storage (“CCUS”) projects in the world. At Weyburn, we store 1.8 million tonnes of CO2 annually which is more CO2 than we emit corporately on an annual basis. Whitecap continues to focus on reducing our direct and indirect emissions through optimization of our current operations and advancing low emission growth opportunities.

As a tangible demonstration of our commitment to continual improvement, Whitecap has reduced direct greenhouse gas emissions intensity each year since 2015 posting an overall intensity reduction of 40% during that time. We continue to look for additional opportunities to improve carbon efficiency and are in the process of setting specific targets to ensure our downward trend continues into the future. By mid-2020, we anticipate releasing our bi-annual sustainability report that will include a more thorough presentation of key metrics, differentiators and sustainability targets. We have also launched our new website featuring our CO2 carbon capture project which can be viewed at www.wcap.ca.

Whitecap’s balance sheet remains in strong condition with net debt at $1.19 billion on total credit capacity of $1.77 billion providing significant financial flexibility and liquidity. All of our debt has been termed out with no near-term maturities and the average effective cost of borrowing is low at 3.6% per annum. Whitecap’s debt to earnings before interest, taxes, depreciation and amortization (“EBITDA”) ratio was 1.6x for 2019. (1)

(1) Refer to Note 12(a) “Bank Debt” in the audited annual consolidated financial statements.

FOURTH QUARTER FINANCIAL HIGHLIGHTS

  • Funds flow was $184.5 million ($0.45 per share) compared to $138.8 million ($0.33 per share) in the prior year quarter, an increase of 33%. The funds flow increase of $45.7 million was attributed to $42.9 million from higher funds flow netbacks and $2.8 million from higher production volumes.
  • Operating netbacks improved to $30.34/boe compared to $24.03/boe in the prior year quarter primarily due to higher realized crude oil prices.
  • Production averaged 74,651 boe/d in the fourth quarter, an increase of 2% (5% per debt-adjusted share) from 73,185 boe/d in the prior year quarter.
  • Capital expenditures were $98.8 million in the quarter, compared to $76.5 million in the prior year quarter.
  • The Company returned $35.0 million in cash dividends to shareholders in the fourth quarter.

FOURTH QUARTER OPERATIONAL HIGHLIGHTS AND 2019 UPDATE

Southeast Saskatchewan

At Weyburn, we drilled 6 (3.4 net) infills wells in the fourth quarter. Production results for five wells with 30 days production history averaged 147 bopd or 2.4 times greater than our expectations. The property averaged 14,304 boe/d in 2019 and maintained a production decline rate of less than 3% while reinvesting only 23% ($37 million) of its operating income.

This asset continues to be a significant free funds flow engine for the Company generating $124 million of operating income after capital expenditures. We plan to complete our winter program in the first quarter of 2020 with the drilling of 10 (6.2 net) wells, including 2 (1.2 net) injection wells.

Southwest Saskatchewan

In southwest Saskatchewan, we drilled 6 (4.4 net) oil wells in the fourth quarter for a total of 48 (37.0 net) wells including 3 (1.7 net) injection wells for the year. We had exceptional results from our Atlas program, drilling 19 (15.5 net) wells of which 17 have been on production for 90 days with average IP(90) rates of 179 boe/d or 37% above our expectations. We drilled 13 (10.8 net) wells in the Lower Shaunavon with average IP(90) rates of 124 boe/d or 36% higher than our expectations.

We have recently placed into service our new Carmichael battery to handle production from our Lower Shaunavon development. By processing volumes through this new 100% working interest facility, we anticipate operating netbacks to increase by $3.50/boe in the area in 2020. The southwest Saskatchewan business unit continues to generate significant operating income after capital expenditures as we only invested $80 million to maintain average production of approximately 15,000 boe/d resulting in operating income after capital expenditures of $109 million in 2019.

West Central Saskatchewan

We drilled 10 (8.6 net) horizontal Viking wells in west central Saskatchewan in the fourth quarter for a total of 95 (87.8 net) wells for the year, including 2 (2.0 net) injection wells to support our Kerrobert waterflood project.

The early time IP(30) performance of the wells is meeting budget expectations with lower production declines than forecasted with our average IP(180) wells performing 11% above our expectations. The shallower production decline profile is a direct result of maintaining and optimizing our waterfloods and drilling a higher percentage of wells in our revitalized waterflood areas.

Fourth quarter production increased 13% to 12,681 boe/d compared to 11,257 boe/d in the prior year quarter. The area averaged 10,777 boe/d in 2019 and generated operating income of $164 million on capital expenditures of $99 million.

Northwest Alberta and British Columbia

In northwest Alberta and British Columbia, we drilled 4 (3.4 net) wells in the fourth quarter including 1 (1.0 net) horizontal oil well in Boundary Lake, 1 (0.4 net) non-operated Charlie Lake horizontal oil well in the Peace River Arch area and 2 (2.0 net) earning wells in our Karr Montney oil joint venture (1.3 net wells post earning). In 2019, we drilled 26 (21.0 net wells) including 21 (15.6 net) Wapiti Cardium horizonal oil wells in this area.

We have now drilled all 3 of our earning wells for the Karr Montney oil joint venture of which one is on production and the second well is expected to be on stream by the end of March. We will have fully earned on 34 (21.5 net) sections of Montney rights once the third well is completed after break-up. In addition, we are currently participating in a fourth non-operated well (50% working interest) in the immediate area. We anticipate the remaining 2 (1.15 net) wells to be on production by the fourth quarter of 2020. Well performance and capital costs are within expectation at the early stage of development for this area.

Production at Wapiti is meeting expectations and currently producing approximately 7,000 boe/d. An additional 6 (5.2 net) wells are anticipated to be drilled in the first quarter of 2020. Our gas flood commenced injection in early 2020 and performance has been as expected.

The overall business unit continues to be a growth engine for the Company with fourth quarter average production increasing 9% to 17,235 boe/d compared to 15,847 boe/d in the prior year quarter. The business unit averaged 15,938 boe/d in 2019 and generated operating income of $132 million on capital expenditures of $111 million.

West Central Alberta

There was no drilling in this business unit in the fourth quarter. In 2019, we drilled a total of 18 (17.1 net) Cardium horizontal wells including 8 (8.0 net) wells in Ferrier, 8 (7.1 net) wells in West Pembina and 2 (2.0 net) wells in Willesden Green. On average, well performance has been at or above expectations in all areas.

Our focus continues to be on the waterflood redevelopment in West Pembina which to date has been performing above expectations. The waterflood performance has been partially recognized by our independent reserves evaluator in our 2019 year end reserves.

The business unit averaged 15,045 boe/d in 2019 and generated operating income of $144 million on capital expenditures of $69 million.

2019 RESERVE HIGHLIGHTS

Proved Developed Producing

  • Increased PDP reserves by 7% per debt-adjusted share to 225.3 MMboe.
  • Total PDP reserve additions of 25.9 MMboe replaced 100% of production at a finding, development and acquisition (“FD&A”) cost of $14.45/boe, including changes in future development cost (“FDC”), which results in a recycle ratio of 2.1 times ($15.42/boe, excluding changes in FDC resulting in a recycle ratio of 1.9 times)
  • PDP reserves represent 62% of the TP reserves, consistent with the prior year.

Total Proved

  • Increased TP reserves by 9% per debt-adjusted share to 363.1 MMboe.
  • Total TP reserve additions of 34.4 MMboe replaced 133% of production at an FD&A cost of $17.95/boe, including FDC, which results in a recycle ratio of 1.7 times ($11.59/boe, excluding FDC, which results in a recycle ratio of 2.6 times).
  • TP reserves represent 72% of the TPP reserves consistent with the prior year.

Total Proved Plus Probable

  • Increased TPP reserves by 11% per debt-adjusted share to 507.4 MMboe.
  • Total TPP reserve additions of 43.8 MMboe replaced 169% of production at an FD&A cost of $21.06/boe, including FDC, which results in a recycle ratio of 1.4 times ($9.10/boe, excluding FDC, which results in a recycle ratio of 3.3 times)

OUTLOOK

The start to 2020 has been a busy one for Whitecap. In addition to an active drilling program with 10 drilling rigs currently in operation, we recently closed the acquisition of a private company with assets synergistic with our core southwest Saskatchewan business unit for $16.2 million. The acquisition includes current production of approximately 600 boe/d with a production decline rate of less than 15%, injection facilities and tax pools of $131.0 million including $80.5 million of non-capital losses. We see upside opportunities that include reactivation and recompletion opportunities in the enhanced oil recovery projects currently in operation as well as extending our resource plays on this acreage.

Our corporate average production guidance for 2020 of 71,000 – 72,000 boe/d remains unchanged. We reduced our first quarter capital program by approximately $10 million (primarily in the Viking program) to partially fund the acquisition and now expect capital expenditures in 2020 to be $350 – $370 million excluding the corporate acquisition.

We believe the current environment, wherein new equity financings are challenging and debt financings are limited and increasingly restrictive, provides opportunities for Whitecap to use our free funds flow and balance sheet as strategic assets to further enhance the return profile to our shareholders. We have the internal expertise to identify, evaluate and execute on these potential opportunities using a combination of joint venture transactions, acquisitions, partnerships and organic growth. In addition, we intend to accelerate the application of our technical expertise in CO2 sequestration and enhanced oil recovery, whether in Canada or globally, to continue to improve upon our standing as one of the lowest net greenhouse gas (“GHG”) emitters in the oil and gas industry and to invest in renewable projects that can complement our existing operations.

We will continue to differentiate ourselves with a business strategy that is sustainable for the long term and is focused on developing and growing our crude oil and natural gas resources in a manner that enhances our position as a leader in energy production with low GHG emissions intensity. This, combined with our production and funds flow growth targets and our disciplined approach to capital allocation, positions us to continue to increase the return of capital to our shareholders.

On behalf of our management team and board of directors, we would like to thank our shareholders for their ongoing support and look forward to providing updates as we progress through the year.

2019 RESERVES REVIEW

Our 2019 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, 2019. The reserves evaluation was based on the average forecast pricing of McDaniel’s, GLJ Petroleum Consultants and Sproule Associates Limited and foreign exchange rates at January 1, 2020 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, 2020. The numbers in the tables below may not add due to rounding.

Summary of Reserves
Reserves as at December 31, 2019

Company Share Reserves

Description

Oil (Mbbl)

Gas (MMcf)

NGL (Mbbl)

Total (Mboe)

Proved producing

180,317

190,532

13,250

225,322

Proved non-producing

2,107

1,427

44

2,388

Proved undeveloped

101,691

143,187

9,788

135,343

Total proved

284,115

335,145

23,081

363,053

Probable

101,281

180,433

12,959

144,312

Total proved plus probable

385,396

515,578

36,040

507,365

Net Present Values

Summary of Before Tax Net Present Values (Forecast Pricing)
As at December 31, 2019

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

Discount Rate

Description

0%

5%

10%

15%

20%

Proved producing

5,822

4,202

3,283

2,713

2,327

Proved non-producing

89

62

47

37

30

Undeveloped

2,959

1,822

1,168

769

514

Total proved

8,871

6,086

4,497

3,519

2,871

Probable

5,496

2,860

1,778

1,229

910

Total proved plus probable

14,367

8,947

6,275

4,748

3,781

Per fully diluted share

34.44

21.45

15.04

11.38

9.07

(1)

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

Future Development Costs

FDC reflects the best estimate of the capital cost to develop and produce reserves. FDC associated with our TPP reserves at year end 2019 is $4.0 billion undiscounted ($2.5 billion discounted at 10%) and includes polymer and CO2 purchases for our southwest and southeast Saskatchewan enhanced oil recovery projects. The TPP and TP FDC for these two items is $788 million undiscounted ($296 million discounted at 10%).

Also included in FDC are 1,494 (1,229.4 net) proved plus probable booked locations.

($000s)

Total Proved

Total Proved plus Probable

2020

310,312

337,325

2021

467,873

486,361

2022

570,917

650,445

2023

512,521

634,590

2024

532,365

648,252

Remainder

1,007,026

1,209,584

Total FDC, Undiscounted

3,401,014

3,966,556

Total FDC, Discounted at 10%

2,174,452

2,545,469

Performance Measures (Including FDC)

The following table highlights our 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:

2019

2018

2017

Three Year

Weighted

Average

Proved Developed Producing

F&D costs (1)

$14.33

$13.06

$11.25

$12.90

F&D recycle ratio (2)

2.1x

2.2x

2.4x

2.2x

FD&A costs (3)

$14.45

$15.15

$21.68

$17.04

FD&A recycle ratio (2)

2.1x

1.9x

1.3x

1.8x

Total Proved

F&D costs (1)

$17.87

$22.70

$13.37

$18.00

F&D recycle ratio (2)

1.7x

1.3x

2.1x

1.7x

FD&A costs (3)

$17.95

$23.30

$21.53

$20.89

FD&A recycle ratio (2)

1.7x

1.3x

1.3x

1.4x

Total Proved Plus Probable

F&D costs (1)

$21.00

$24.83

$12.66

$19.54

F&D recycle ratio (2)

1.4x

1.2x

2.2x

1.6x

FD&A costs (3)

$21.06

$24.04

$17.05

$20.74

FD&A recycle ratio (2)

1.4x

1.2x

1.6x

1.4x

(1)

F&D costs are calculated as the sum of development capital of $396.1 million plus the change in FDC for the period of -$25.1 million (PDP), $218.8 million (TP) and $524.2 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 2019 was $29.73/boe.

(3)

FD&A costs are calculated as the sum of development capital of $396.1 million plus acquisition capital of $3.1 million plus the change in FDC for the period of -$25.1 million (PDP), $218.8 million (TP) and $524.2 million (TPP), divided by the change in total reserves, other than from production, for the period.

Performance Measures (Excluding FDC)

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

2019

2018

2017

Three Year

Weighted

Average

Proved Developed Producing

F&D costs (1)

$15.30

$15.06

$12.48

$14.30

F&D recycle ratio (2)

1.9x

1.9x

2.2x

2.0x

FD&A costs (3)

$15.42

$17.01

$13.55

$15.34

FD&A recycle ratio (2)

1.9x

1.7x

2.0x

1.9x

Total Proved

F&D costs (1)

$11.51

$14.28

$13.71

$13.14

F&D recycle ratio (2)

2.6x

2.1x

2.0x

2.2x

FD&A costs (3)

$11.59

$14.94

$10.97

$12.50

FD&A recycle ratio (2)

2.6x

2.0x

2.5x

2.4x

Total Proved Plus Probable

F&D costs (1)

$9.04

$15.67

$12.71

$12.43

F&D recycle ratio (2)

3.3x

1.9x

2.2x

2.5x

FD&A costs (3)

$9.10

$15.37

$8.61

$11.01

FD&A recycle ratio (2)

3.3x

1.9x

3.2x

2.8x

(1)

F&D costs are calculated as development capital of $396.1 million 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 2019 was $29.73/boe.

(3)

FD&A costs are calculated as the sum of development capital of $396.1 million plus acquisition capital of $3.1 million, 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:

2019

2018

2017

Three Year

Weighted

Average

Proved Developed Producing

Production replacement (1)

100%

112%

449%

218%

RLI (years) (2)

8.3

8.4

10.2

9.0

Total Proved

Production replacement (1)

133%

128%

555%

269%

RLI (years) (2)

13.3

13.3

15.9

14.1

Total Proved Plus Probable

Production replacement (1)

169%

124%

707%

330%

RLI (years) (2)

18.6

18.3

22.2

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 71,050 boe/d in 2019.

(2)

RLI is calculated as total Company share reserves divided by the annualized fourth quarter actual production of 74,651 boe/d.

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