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Whitecap Resources Inc.

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Whitecap Resources Inc. Announces Fourth Quarter, Year End 2017 Results, 2017 Reserves Evaluation and the Appointment of Ken Stickland as Board Chairman
Whitecap Resources Inc. Announces Fourth Quarter, Year End 2017 Results, 2017 Reserves Evaluation and the Appointment of Ken Stickland as Board Chairman

Canada NewsWire

CALGARY, Feb. 28, 2018 /CNW/ - Whitecap Resources Inc. ("Whitecap" or the "Company") (TSX: WCP) is pleased to report its operating and audited financial results for the year ended December 31, 2017.

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 ("MD&A") and Annual Information Form ("AIF") 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)

2017

2016

2017

2016

Petroleum and natural gas sales

285,009

209,149

1,001,343

635,306

Net income (loss)

(231,729)

191,104

(123,968)

170,748


Basic ($/share)

(0.61)

0.52

(0.33)

0.50


Diluted ($/share)

(0.61)

0.51

(0.33)

0.50

Funds flow (1)

143,543

117,792

508,627

384,725


Basic ($/share) (1)

0.38

0.32

1.37

1.13


Diluted ($/share) (1)

0.38

0.32

1.36

1.13

Dividends paid or declared

27,476

25,745

104,926

116,521


Per share

0.07

0.07

0.28

0.35

Total payout ratio (%) (1)

59

89

87

76

Development capital (1)

57,162

79,651

338,780

173,993

Property acquisitions

939,015

12,043

970,883

630,565

Property dispositions

(8,777)

35

(14,598)

(144,379)

Net debt (1)

1,295,906

818,580

1,295,906

818,580

Operating





Average daily production






Crude oil (bbls/d)

44,699

37,072

43,589

32,398


NGLs (bbls/d)

3,634

3,247

3,415

3,168


Natural gas (Mcf/d)

68,244

61,756

62,676

61,651


Total (boe/d)

59,707

50,612

57,450

45,841

Average realized price (2)






Crude oil ($/bbl)

63.60

53.88

57.28

47.58


NGLs ($/bbl)

37.22

23.60

30.44

17.31


Natural gas ($/Mcf)

1.75

3.23

2.27

2.26


  Total ($/boe)

51.89

44.92

47.75

37.87

Netbacks ($/boe)






Petroleum and natural gas sales before tariffs (1)

53.04

46.81

49.18

39.92


Tariffs (1)

(1.15)

(1.89)

(1.43)

(2.05)


Realized hedging gain (loss)

(2.19)

1.65

(1.15)

4.44


Royalties

(7.41)

(6.89)

(6.89)

(5.42)


Operating expenses

(10.88)

(10.18)

(10.61)

(9.54)


Transportation expenses

(1.93)

(1.00)

(1.63)

(0.89)

Operating netbacks (1)

29.48

28.50

27.47

26.46


General and administrative expenses

(1.29)

(1.15)

(1.31)

(1.29)


Interest and financing expenses

(1.87)

(1.91)

(1.77)

(2.14)


Transaction costs

(0.02)

-

-

(0.02)


Settlement of decommissioning liabilities

(0.16)

(0.14)

(0.13)

(0.07)

Funds flow netbacks (1)

26.14

25.30

24.26

22.94






Share information (000s)





Common shares outstanding, end of period

418,029

368,351

418,029

368,351

Weighted average basic shares outstanding

379,326

368,272

371,848

339,735

Weighted average diluted shares outstanding

381,574

371,193

373,944

341,893

Notes:


(1)    

Funds flow, funds flow per share, total payout ratio, development capital, net debt, petroleum and natural gas sales before tariffs, tariffs, operating netbacks and funds flow netbacks do not have a standardized meaning under GAAP. Refer to non-GAAP measures in this press release for additional disclosure and assumptions.

(2)    

Prior to the impact of hedging activities.

 

MESSAGE TO SHAREHOLDERS

We are pleased to report another year of significant growth and long-term value creation for our Company in 2017. As a result of our continued pursuit of operational excellence, we were able to achieve strong operational results in a safe and environmentally responsible manner and also able to deliver robust financial results. We concluded the year with the acquisition of the world class Weyburn CO2 enhanced oil recovery project in southeast Saskatchewan (the "Weyburn Acquisition") that will provide substantial free funds flow and incremental value for Whitecap shareholders for many years to come.

In 2017, we allocated 66% of our funds flow to grow production organically by 15% per share and used 21% of our funds flow to return cash to shareholders through our cash dividend program. This resulted in a total payout ratio of 87% and $64.9 million of free funds flow which was used to reduce bank debt. Our development capital program included the drilling of 227 (193.6 net) horizontal oil wells. Whitecap's development capital program resulted in finding and development ("F&D") costs on proved developed producing ("PDP") reserves of $11.25/boe, including future development capital ("FDC"), a reduction of 22% compared to the prior year. This resulted in a very strong PDP recycle ratio of 2.4 times.

With respect to our business development initiatives, in December we were able to complete the Weyburn Acquisition for $940 million which included net production of 14,800 boe/d (100% light oil) with a low base decline rate and significant incremental growth and expansion opportunities. The acquisition is a continuation of our long-term strategy to focus on high netback, low decline assets that have the ability to grow production within their own funds flow. We anticipate this asset to not only grow production on an annual basis but to also provide significant free funds flow well into the future.

2017 FINANCIAL HIGHLIGHTS

  • Achieved record annual production of 57,450 boe/d in 2017 despite significant unexpected third party facility downtime in Q2/17. Annual production increased 25% or 15% per fully diluted share compared to the prior year.
  • Q4/17 production was 59,707 boe/d and impacted by approximately 500 boe/d due to extreme cold weather in the last week of December and the disposition of non-core production for $22 million. Despite the foregoing, Q4/17 average production increased 18% or 15% per fully diluted share compared to Q4/16.
  • Development capital spending was $338.8 million in 2017 of which $3.0 million was spent on the Weyburn assets. We drilled a total of 227 (193.6 net) oil wells including 125 (115.2 net) horizontal Viking oil wells in west central Saskatchewan, 32 (28.6 net) horizontal Cardium wells in west central Alberta, 38 (24.4 net) wells in southwest Saskatchewan, 6 (4.1 net) horizontal Dunvegan wells and 17 (12.6 net) horizontal Cardium wells at Wapiti in northwest Alberta, 6 (5.7 net) Boundary Lake (Triassic) wells in British Columbia, and 3 (3.0 net) wells at Elnora.
  • Supported by strong operational execution, stronger crude oil prices and free funds flow, we increased our dividend by 5% in 2017 and paid out $104.9 million of cash dividends to shareholders in the year. Whitecap generated $508.6 million of funds flow in 2017 which exceeded development capital spending and dividend payments by $64.9 million, resulting in a total payout ratio of 87%. Funds flow per share was $1.36 per fully diluted share compared to $1.13 per fully diluted share in 2016, an increase of 20%.
  • On the business development front, as outlined earlier, Whitecap closed the Weyburn Acquisition for $940 million on December 14, 2017. The acquisition significantly enhances Whitecap's free funds flow profile and reduces our base decline rate from 23% to 19% which provided us with the confidence to increase our dividend by an additional 5% in January 2018. Refer to our press release dated November 13, 2017 for further details.
  • Whitecap's balance sheet remains strong with year end net debt of $1.3 billion on a total credit facility of $1.7 billion, leaving significant unutilized credit capacity for financial flexibility. Of the $1.3 billion net debt at year end, $595 million was termed out with 5, 7 and 9 year terms at a very attractive blended average long-term interest rate of 3.63%. Our optimized capital structure reflects the stability of our low decline production base and the long reserve life characteristic of our asset base.
  • In addition to double-digit production per share growth, increasing the monthly dividend, closing on an accretive acquisition, shareholder returns were also enhanced by $10.5 million of share buybacks in 2017 which reduced our common shares outstanding by 1.2 million shares.

2017 OPERATIONAL HIGHLIGHTS

  • The Viking program continues to deliver excellent capital efficiencies highlighted by our standard length and extended reach horizontal ("ERH") well productivity. To balance the high production growth rate, we continue to flatten our base declines by re-developing and expanding our existing waterfloods in Eagle Lake and Kerrobert. In Kerrobert, we have seen encouraging response from the 18 injector conversions done in 2017, of which 4 were horizontals, which added 2,200 barrels of water per day of targeted injection support. In Eagle Lake, 5 injector conversions coupled with significant optimization of the existing injectors has resulted in improving pressure support for our infill wells which are exhibiting lower declines and averaging 40,000 barrels of oil in their first year of production.
  • Our SW Saskatchewan assets, purchased in June 2016, continue to perform above our initial expectations. To date we have drilled 27 (19.3 net) horizontal oil wells in the Atlas (Cantaur) resource play and the results have provided us with the confidence to increase our type curves by 14% in 2017. In addition, we continue to make inroads on optimizing our operating costs which averaged $13.78/boe in 2017 compared to $16.71 at the time of acquisition.
  • The Cardium program in west central Alberta was focused on the redevelopment of our legacy waterfloods in West Pembina. Our un-fractured horizontal injector is still performing extremely well and has injected cumulatively 40,000 barrels of water over its first 8 months of injection. We will be drilling an additional injection well as a follow up to this injector in Q1/18. We anticipate this pilot injector design will be integrated into the full development of the pool resulting in a savings of over $14 million or a 13% reduction in the total development cost estimate.
  • In the Deep Basin, we have been focused on the continued advancement of the Wapiti Cardium development spending 65% of the Deep Basin's total development capital budget. We continue to refine fracture design and well placement, which resulted in a further 30% increase in initial production rates when compared to earlier designs. We have over 163 (95.8 net) remaining undrilled locations at Wapiti on which to apply these learnings and 50% of these locations are not contained in our reserve report.

2017 RESERVES HIGHLIGHTS

The 2017 capital program focused on continuing to reduce our base production decline rate which, in turn, enhanced our ability to grow production per share, pay a sustainable and growing dividend and also generate significant free funds flow. The effective execution of this strategy with our development capital program has resulted in exceptional PDP reserve bookings and strong overall results from our reserves evaluation.

Proved Developed Producing ("PDP")

  • Development capital spending replaced 126% of production at an F&D cost of $11.25/boe which generated a recycle ratio of 2.4 times.
  • Increased PDP reserves by 49% or 31% per fully diluted share to 222.1 MMboe from 149.0 MMboe in 2016.
  • Total PDP reserve additions of 94.0 MMboe replaced 449% of production at an FD&A cost of $21.68/boe, including FDC, which results in a recycle ratio of 1.3 times.
  • PDP reserves represent 64% of the TP reserves compared to 59% in the prior year.

Total Proved ("TP")

  • Development capital spending replaced 115% of production at an F&D cost of $13.37/boe, including changes in FDC, which generated a recycle ratio of 2.1 times.
  • Increased TP reserves by 38% or 21% per fully diluted share to 347.0 MMboe from 251.8 MMboe in 2016.
  • Total reserve additions of 116.2 MMboe replaced 555% of production at an FD&A cost of $21.53/boe, including FDC, which results in a recycle ratio of 1.3 times.
  • TP reserves comprise 72% of TPP reserves compared to 71% in the prior year.

Total Proved Plus Probable ("TPP")

  • Development capital spending replaced 124% of production at an F&D cost of $12.66/boe, including changes in FDC, which generated a recycle ratio of 2.2 times.
  • Increased TPP reserves by 36% or 19% per fully diluted share to 482.9 MMboe from 355.8 MMboe in 2016.
  • Total TPP reserve additions of 148.0 MMboe replaced 707% of production at an FD&A cost of $17.05/boe, including FDC, which results in a recycle ratio of 1.6 times.
  • Net asset value based on total proved plus probable ("TPP") reserves discounted at 10% is $12.50 per fully diluted share. Net present value of reserves is adjusted for net debt of $1.3 billion and undeveloped land value of $70.1 million.

OUTLOOK

Whitecap's business strategy has been built on operational excellence to deliver predictable performance focused on per share growth on our high quality assets in order to provide top decile economic returns and sustainable total shareholder returns annually.

Our priorities continue to include (1) maintaining a strong balance sheet, (2) generating strong production and funds flow per share growth, (3) paying a sustainable and growing dividend, and (4) continued commitment to strong safety and responsible environmental standards.

We have experienced improving crude oil prices in 2018 with current prices above WTI US$60 per barrel, however, we expect to see continuing volatility as we move through the year. Even with the higher prices today, our strategy remains unchanged and we remain committed to demonstrating predictable operational and financial performance to drive superior returns through fluctuating commodity price cycles. We are on track to deliver another year of double digit production per share growth and anticipate funds flow to once again exceed capital expenditures and dividend payments. Our robust hedge portfolio provides significant downside protection and, as with previous years, we anticipate a total payout ratio of less than 100% in 2018 even with crude oil prices below WTI US$45 per barrel. We are also highly levered towards an improving crude oil price environment as we are 86% weighted towards oil and natural gas liquids.

Whitecap is well positioned to provide industry-leading production per share growth while generating substantial free funds flow given our lower base decline rate of 19%, high funds flow netbacks, and strong capital efficiencies. This provides us with optionality in 2018 to redeploy the free funds flow towards debt repayment, increasing our dividend, share buybacks or to fund future acquisitions without the issuance of equity while still maintaining a strong balance sheet.

In 2017, we delivered on our financial and operational metrics while also achieving a very strong health, safety and environmental record. We remain committed to demonstrating leadership on health, safety and the environment and will focus on increasing the transparency of our disclosures to our shareholders in 2018.

We are also pleased to announce, as part of our ongoing commitment to strong corporate governance, the appointment of Ken Stickland as Chairman of the Board of Directors. Mr. Stickland has been a valued member of Whitecap's Board of Directors since 2013 and has a strong legal and governance background, along with extensive experience in the energy sector at both the senior executive and board levels.

On behalf of our board of directors and the Whitecap management team, we would like to thank our shareholders for their ongoing support and look forward to providing strong financial and operational updates as we progress through 2018.

2017 RESERVES REVIEW

Our 2017 year end reserves were evaluated by independent reserves evaluator McDaniel & Associates Consultants Ltd. ("McDaniel") and GLJ Petroleum Consultants ("GLJ") 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, 2017. The reserves evaluation was based on McDaniel's forecast pricing and foreign exchange rates at January 1, 2018 which is available on their 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 include 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 31, 2017. The numbers in the tables below may not add due to rounding.

Summary of Reserves

Whitecap was once again able to deliver both absolute and per share reserves growth in all categories in 2017. Compared to the prior year, PDP, TP and TPP reserves increased 49%, 38% and 36% or 31%, 21% and 19% per fully diluted share, respectively.

Reserves


As at December 31, 2017





Company Share Reserves

Description

Oil (Mbbl)

Gas (MMcf)

NGL (Mbbl)

Total (Mboe)

Proved producing

178,472

192,419

11,542

222,084

Proved non-producing

3,037

4,887

98

3,949

Proved undeveloped

94,875

111,010

7,633

121,009

Total proved

276,384

308,315

19,272

347,042

Probable

104,297

135,352

9,021

135,877

Total proved plus probable

380,681

443,667

28,293

482,919

 

Net Present Values

Before tax net present value discounted 10% per share increased 8% to $15.37 per share on TPP reserves and 6% to $11.04 per fully diluted share on TP reserves despite a 6% decrease to the 5 year average Edmonton light price forecast and a 16% decrease to the 5 year average AECO price forecast.

Summary of Before Tax Net Present Values

(Forecast Pricing)


As at December 31, 2017



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


Discount Rate

Description

0%

5%

10%

15%

20%

Proved producing


5,665


4,159


3,257


2,682


2,290

Proved non-producing


129


90


67


53


44

Undeveloped


3,185


2,010


1,349


950


692

Total proved


8,979


6,259


4,674


3,686


3,025

Probable


5,714


2,927


1,831


1,292


983

Total proved plus probable


14,694


9,186


6,505


4,978


4,009

Per fully diluted share


$34.72


$21.71


$15.37


$11.76


$9.47

(1) Includes abandonment and reclamation costs as defined in NI 51-101.

 

Future Development Costs

FDC reflects the best estimate of the capital cost to produce reserves. FDC associated with our TPP reserves at year end 2017 is $2.2 billion and includes Polymer and CO2 purchases for our southwest and southeast Saskatchewan enhanced oil recovery projects. TPP FDC for these two items is $680 million undiscounted ($301 million discounted 10%) and TP FDC is $668 million undiscounted ($301 million undiscounted 10%).

Also included in FDC are 1,297 (1,052.9 net) booked locations of which 455 (391.9 net) are ERH. Booked locations represent 47% of Whitecap's total inventory at December 31, 2017 of 2,897 (2,251.7 net) locations of which 850 (711.7 net) are ERH wells.




($000s)

Total Proved

Total Proved plus Probable

2018

546,414

551,494

2019

565,098

594,083

2020

469,374

556,887

2021

349,145

397,156

2022

203,843

233,532

Remainder

758,264

817,139

Total FDC, Undiscounted

2,892,138

3,150,290

Total FDC, Discounted at 10%

1,982,988

2,155,262

 

Performance Measures

Highlights to our 2017 performance measures include very strong F&D costs as well as F&D recycle ratios above 2 times in each of the PDP, TP and TPP reserve categories. FD&A costs for the year were consistent with the 3 year average and reflect the long life, light oil, high netback acquisition of the Weyburn assets. 2016 had unusually low F&D and associated FD&A due to a significant correction in services costs which resulted in a one-time downward revision to FDC.

We were also able to drive record production replacement of produced reserves for PDP at 449%, TP at 555% and TPP at 707%. These exceptionally strong ratios on our high quality assets have extended our reserve life index to 10.2 years on PDP reserves, 15.9 years on TP reserves, and 22.2 years on TPP reserves.

The following table highlights annual performance ratios based on the evaluation of our petroleum and natural gas reserves prepared by McDaniel and GLJ:







2017

2016

2015

Three Year
Weighted
Average

Proved Developed Producing






F&D costs (1)

$11.25

$14.46

$12.57

$12.60


F&D recycle ratio (2)

2.4x

1.8x

 2.9x

2.3x


FD&A costs (3)

$21.68

$15.78

$29.46

$21.74


FD&A recycle ratio (2)

1.3x

1.7x

 1.2x

1.4x


Production replacement (4)

449%

313%

236%

353%


RLI (years) (5)

10.2

8.1

7.4

8.8

Total Proved






F&D costs (1)

$13.37

$2.42

$8.86

$8.76


F&D recycle ratio (2)

2.1x

10.9x

 4.1x

5.4x


FD&A costs (3)

$21.53

$13.32

$23.11

$19.31


FD&A recycle ratio (2)

1.3x

2.0x

 1.6x

1.6x


Production replacement (4)    

555%

409%

400%

470%


RLI (years) (5)

15.9

13.6

13.0

14.4

Total Proved Plus Probable






F&D costs (1)

$12.66

$2.34

$6.97

$7.95


F&D recycle ratio (2)

2.2x

11.3x

 5.2x

5.8x


FD&A costs (3)

$17.05

$11.51

$18.27

$15.59


FD&A recycle ratio (2)

1.6x

2.3x

 2.0x

1.9x


Production replacement (4)

707%

559%

499%

608%


RLI (years) (5)

22.2

19.3

18.2

20.3

 

(1)

F&D costs are calculated as the sum of field capital of $330.1 million plus the change in FDC for the period of -$32.5 million (PDP), -$8.1 million (TP) and -$1.4 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. Operating netback is calculated as revenue (including realized hedging gains and losses) minus royalties, operating expenses, and transportation expenses. Our operating netback in 2017 was $27.47/boe.

(3)

FD&A costs are calculated as the sum of field capital of $330.1 million plus acquisition capital of $944.3 million plus the change in FDC for the period of $764.0 million (PDP), $1,226.3 million (TP) and $1,250.0 million (TPP), divided by the change in total reserves, other than from production, for the period.

(4)

Production replacement ratio is calculated as total reserve additions (including acquisitions net of dispositions) divided by annual production. Whitecap's production averaged 57,450 boe/d in 2017.

(5)

Reserve life index ("RLI") is calculated as total Company share reserves divided by the annualized fourth quarter actual production of 59,707 boe/d.

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", "sustain", "project", "expect", "forecast", "budget", "goal", "guidance", "plan", "objective", "strategy", "target", "intend" 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, objectives, priorities and focus, long-term value creation, production per share growth, funds flow netbacks, funds flow,  free funds flow and total payout ratio; the benefits to be obtained from our hedging program; the anticipated benefits of the Weyburn Acquisition; timing of drilling a follow up to the injector in west central Alberta; expectations on the integration of the pilot injector design and anticipated savings derived from such integration in west central Alberta; our expectations regarding volatility in crude oil prices in 2018; flexibility to redeploy free funds flow in 2018; future development costs; quantity of drilling locations in inventory; expectations with respect to 2018 production; and industry conditions. 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; 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. 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.

Oil and Gas Advisories
All reserve references in this press release are "Company share reserves". Company share reserves are the Company's total working interest reserves before the deduction of any royalties and including any royalty interests payable the Company.

It should not be assumed that the present worth of estimated future cash flow 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 Whitecap's 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.

"Boe" means barrel of oil equivalent on the basis of 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 "recycle ratio", "operating netback", "finding and development costs", "finding, development and acquisition ("FD&A") costs", "production replacement ratio", "reserve life index", "field capital", "acquisition capital" and "net asset value". 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.

"Finding and development costs" are calculated as the sum of field capital plus the change in FDC for the period divided by the change in reserves that are characterized as development for the period and "finding development and acquisition costs" are calculated as the sum of field capital plus acquisition capital plus the change in FDC for the period divided by the change in total reserves, other than from production, for the period.

Both finding and development costs and finding development and acquisition costs take into account reserves revisions during the year on a per boe basis. The aggregate of the exploration and development costs incurred in the financial year and changes during that year in estimated future development costs generally will not reflect total finding and development costs related to reserves additions for that year. Finding and development costs both including and excluding acquisitions and dispositions have been presented in this press release because acquisitions and dispositions can have a significant impact on our ongoing reserves replacements costs and excluding these amounts could result in an inaccurate portrayal of our cost structure.

"Field capital" means the aggregate exploration and development costs incurred in the financial year on reserves that are categorized as development. Field capital excludes capitalized administration costs.

"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 costs within the year on reserves that are categorized as acquisitions less the disposition of certain processing facilities.

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

"Operating netback" is calculated using production revenues including realized hedging gains and losses on commodity contracts minus royalties, operating and transportation expenses calculated on a per boe basis.

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

"Reserve life index" is calculated as total company share reserves divided by the annualized fourth quarter actual production.

"Net asset value" is based on present value of future net revenues discounted at 10% before tax on TPP reserves, plus our internally estimated undeveloped land value, net of estimated net debt at year end divided by the fully diluted shares outstanding at year end.

Management uses these oil and gas metrics for its own performance measurements and to provide shareholders with measures to compare Whitecap's operations over time. Readers are cautioned that the information provided by these metrics, or that can be derived from 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 and GLJ's reserves evaluation effective December 31, 2017 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 2,767 total drilling locations identified herein, 1,171 are proved locations, 126 are probable locations and 1,470 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 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 actually 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 Rates
Any references in this news release to initial production rates are useful in confirming the presence of hydrocarbons, however, such rates are not determinative of the rates at which such wells will continue production and decline thereafter. While encouraging, readers are cautioned not to place reliance on such rates in calculating the aggregate production for Whitecap.

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.

"Cash dividends declared per share" represents cash dividends declared or paid per share by Whitecap.

"Development capital" represents expenditures on property, plant and equipment ("PP&E") excluding corporate and other assets.

The following table reconciles expenditures on PP&E (a GAAP measure) to development capital (a non-GAAP measure):


                Three months ended

        Twelve months ended


                             December 31

                       December 31

($000s)

2017

2016

2017

2016

Expenditures on PP&E

57,698

79,703

339,761

174,358

Expenditures on corporate and other assets

(536)

(52)

(981)

(365)

Development capital

57,162

79,651

338,780

173,993

 

"Funds flow" represents cash flow from operating activities adjusted for changes in non-cash working capital.

"Funds flow per share" represents funds flow divided by the basic or diluted weighted average shares outstanding in the period. Management considers funds flow and funds flow per share to be key measures 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 provides a useful measure of Whitecap's ability to generate cash that is not subject to short-term movements in non-cash operating working capital.

The following table reconciles cash flow from operating activities (a GAAP measure) to funds flow and free funds flow (non-GAAP measures):


          Three months ended

        Twelve months ended


                       December 31

                       December 31

($000s)

2017

2016

2017

2016

Cash flow from operating activities

127,232

98,803

489,119

365,138

Changes in non-cash working capital

16,311

18,989

19,508

19,587

Funds flow

143,543

117,792

508,627

384,725

Cash dividends declared

27,476

25,745

104,926

116,521

Development capital

57,162

79,651

338,780

173,993

Free funds flow

58,905

12,396

64,921

94,211

Total payout ratio (%)

59

89

87

76

 

"Free funds flow" represents funds flow less cash dividends declared and development capital.

"Funds flow netbacks" are determined by deducting cash general and administrative expenses, interest and financing expenses, transaction costs and settlement of decommissioning liabilities from operating netbacks.

"Operating netbacks" are determined by deducting realized hedging losses or adding realized hedging gains and deducting royalties, operating expenses and transportation expenses from petroleum and natural gas sales. Operating netbacks are per boe measures used in operational and capital allocation decisions.

"Net debt" is calculated as long-term debt plus working capital surplus or deficit adjusted for risk management contracts. Net debt is used by management to analyze the financial position and leverage of Whitecap.

The following table reconciles long-term debt (a GAAP measure) to net debt (a non-GAAP measure):

($000s)

        December 31
2017

           December 31
2016

Long-term debt

1,284,232

773,395

Current liabilities

211,285

231,416

Current assets

(161,650)

(111,194)

Risk management contracts

(37,961)

(75,037)

Net debt

1,295,906

818,580

 

"Petroleum and natural gas sales before tariffs" are determined by adding back tariffs netted against petroleum and natural gas sales. Management believes that petroleum and natural gas sales before tariffs provides a useful measure of Whitecap's realized commodity prices before the impact of transporting products to market.

The following table reconciles petroleum and natural gas sales (a GAAP measure) to petroleum and natural gas sales before tariffs (a non-GAAP measure):


Three months ended

December 31

Twelve months ended
December 31

($000s)

2017

2016

2017

2016

Petroleum and natural gas sales

285,009

209,149

1,001,343

635,306

Tariffs

6,367

8,809

29,897

34,447

Petroleum and natural gas sales, before tariffs

291,376

217,958

1,031,240

669,753

 

"Tariffs" represent pipeline tariffs incurred by commodity purchasers and marketing companies subsequent to the delivery of the Company's product, which have been charged back to Whitecap. Under IFRS, tariffs are reflected on a net basis (tariffs are netted against petroleum and natural gas sales). Tariffs will fluctuate quarterly based on pipeline connectivity or downtime, weather, shipper status and pipeline shipping arrangements. As the amount of tariffs recognized decreases, there is an offsetting increase in transportation expense. Management believes that presenting tariffs separately provides a useful measure of the total costs of transporting a product to market as, on a combined basis, tariffs plus transportation expenses are generally consistent with prior periods.

"Total payout ratio" is calculated as cash dividends declared plus development capital, divided by funds flow.

SOURCE Whitecap Resources Inc.

View original content: http://www.newswire.ca/en/releases/archive/February2018/28/c2216.html

Grant Fagerheim, President & CEO, or Thanh Kang, CFO, Whitecap Resources Inc., 3800, 525 - 8th Avenue SW, Calgary, AB T2P 1G1, Phone (403) 266-0767, www.wcap.caCopyright CNW Group 2018

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