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Whitecap Resources Inc. Announces Second Quarter 2017 Results

CALGARY, Aug. 1, 2017 /CNW/ – Whitecap Resources Inc. (“Whitecap” or the “Company”) (TSX: WCP) is pleased to report its operating and unaudited financial results for the three and six months ended June 30, 2017.

Selected financial and operating information is outlined below and should be read with Whitecap’s unaudited interim consolidated financial statements and related Management’s Discussion and Analysis (“MD&A”) which are available at and on our website at


Three months ended June 30 Six months ended June 30
Financial ($000s except per share amounts) 2017 2016 2017 2016
Petroleum and natural gas sales 243,277 135,553 483,452 247,659
Net income 44,541 (28,311) 104,072 (26,706)
Basic ($/share) 0.12 (0.09) 0.28 (0.09)
Diluted ($/share) 0.12 (0.09) 0.28 (0.09)
Funds flow (1) 121,870 92,928 246,105 160,607
Basic ($/share) (1)                            0.33 0.29 0.67 0.52
Diluted ($/share) (1) 0.33 0.29 0.66 0.51
Dividends paid or declared 25,820 23,224 51,599 65,078
Per share 0.07 0.07 0.14 0.21
Total payout ratio (%) (1) 77 42 99 79
Development capital (1) 67,654 16,159 191,715 61,397
Property acquisitions (923) 596,244 6,906 617,535
Property dispositions (2,498) (42,498) (5,821) (144,133)
Net debt (1) 820,295 869,231 820,295 869,231
Average daily production
Crude oil (bbls/d) 43,204 26,771 42,817 28,166
NGLs (bbls/d) 3,333 3,231 3,259 3,218
Natural gas (Mcf/d) 58,373 62,315 60,006 61,931
Total (boe/d) 56,266 40,388 56,077 41,706
Average realized price (2)
Crude oil ($/bbl) 56.00 50.18 56.28 43.02
NGLs ($/bbl) 26.15 17.33 27.77 14.02
Natural gas ($/Mcf) 2.86 1.45 2.84 1.68
Total ($/boe) 47.51 36.88 47.63 32.63
Netbacks ($/boe)
Petroleum and natural gas sales 47.51 36.88 47.63 32.63
Realized hedging gain (loss) (1.28) 7.48 (1.24) 6.85
Royalties (7.16) (4.61) (7.14) (4.17)
Operating expenses (10.64) (9.73) (10.46) (9.40)
Transportation expenses (1.48) (0.90) (1.36) (0.89)
Operating netbacks (1) 26.95 29.12 27.43 25.02
General and administrative expenses (1.31) (1.36) (1.32) (1.35)
Interest and financing expenses (1.73) (2.36) (1.77) (2.41)
Transaction costs (0.07) (0.05)
Settlement of decommissioning liabilities (0.11) (0.04) (0.09) (0.05)
Funds flow netbacks (1) 23.80 25.29 24.25 21.16
Share information (000s)
Common shares outstanding, end of period 369,797 367,574 369,797 367,574
Weighted average basic shares outstanding 369,401 319,533 369,069 311,369
Weighted average diluted shares outstanding 371,410 322,586 371,056 313,907
(1) Funds flow, funds flow per share, total payout ratio, development capital, net debt, operating netbacks and funds flow netbacks do not have a standardized meaning under GAAP. Refer to non-GAAP measures in this press release.
(2) Prior to the impact of hedging activities.



The second quarter of 2017 was another busy quarter for Whitecap as we were able to restart our drilling program in Saskatchewan earlier than forecast due to the shortened breakup period. Of our $300 millioncapital budget for 2017, we spent $67.7 million in the quarter drilling 40 (36.4 net) wells with a 100% success rate and also completed the 11 drilled but uncompleted wells from our Q1/17 program. Production averaged 56,266 boe/d in Q2/17 which was within our guidance of 56,000 – 57,000 boe/d as noted in our press release dated May 31, 2017. Average production for the quarter was negatively impacted by approximately 1,600 boe/d due to unplanned third party facility downtime in our west central Saskatchewan (Coleville), Boundary Lake and Deep Basin areas, of which the most significant was the Coleville gas plant outage impacting our average Q2/17 production by 1,100 boe/d (83% natural gas). Whitecap’s current production is now approximately 58,500 boe/d.

Our underlying business continues to improve as our funds flow netback (prior to hedges) increased 41% to $25.08/boe in Q2/17 compared to $17.81/boe in Q2/16. The strong funds flow netback resulted in a total payout ratio of 77% in the quarter which allowed us to reduce our net debt by $48.9 million to $820.3 million at the end of the quarter. Our Q2/17 net debt to funds flow ratio was 1.7 times and we continue to target a net debt to funds flow ratio of <1.5 times.

In the first half of 2017, we made positive long-term enhancements to our capital structure and now have $200 million of senior secured notes at a fixed interest rate of 3.46% per annum for 5 years and $200 million of senior secured notes at a fixed interest rate of 3.54% per annum for 7 years. At the end of the quarter, the Company’s unutilized credit capacity was approximately $480 million.

Quarterly highlights:

  • Average production in Q2/17 increased 39% (21% per share) to 56,266 boe/d compared to 40,388 boe/d in Q2/16. Whitecap’s oil and NGLs weighting continued to increase with Q2/17 at 83% compared to 74% in Q2/16.
  • Funds flow for the quarter totalled $121.9 million ($0.33 per share), an increase of 31% (14% per share) from Q2/16. Higher production volumes and realized prices in Q2/17 resulted in significantly higher funds flow.
  • As part of Whitecap’s ongoing risk management program, the Company has hedged approximately 40% of its 2H/17 crude oil production (net of royalties) and 21% of its 2018 crude oil production (net of royalties) at an average floor price of approximately C$60.00/bbl in both cases.
  • Invested $67.7 million in development capital expenditures, drilling 40 (36.4 net) wells including 22 (22.0 net) Viking wells, 8 (6.9 net) Cardium wells and 10 (7.5 net) wells in southwest Saskatchewan, all with a 100% success rate.
  • Issued $200 million senior secured notes which have an annual coupon rate of 3.54% and mature on May 31, 2024. We now have a total of $400 million of outstanding senior secured notes.
  • Implemented a Normal Course Issuer Bid (“NCIB”) that allows Whitecap to purchase up to 18.5 million shares over a 12 month period commencing May 18, 2017. In Q2/17, we repurchased 338,711 common shares at an average cost of $9.18 per share for total consideration of $3.1 million.


West Central Saskatchewan

In west central Saskatchewan, 22 (22.0 net) wells were drilled including 9 (9.0 net) extended reach horizontal (“ERH”) wells. In addition, we also completed and tied-in 9 wells that were drilled but uncompleted in Q1/17. Well results continue to meet or exceed our expectations on both cost and productivity.

In Q2/17, we were able to modify our drilling program and reallocate development capital from Lucky Hills and Whiteside, which were areas impacted by the Coleville gas plant outage, to Kerrobert where gas takeaway was not an issue. As a result, spud to on-stream times on our Q2/17 wells were not affected and there was minimal impact to our Q2/17 production additions. This, combined with an early start to our post breakup drilling program (two rigs in mid-May), puts us back on track to meeting our production targets for the area.

The redevelopment of our Viking waterfloods in Eagle Lake and Kerrobert continues to show positive results, supporting further waterflood capital allocation in the future. In Eagle Lake, 3 (2.9 net) Q1/17 wells drilled in the southeast extension of the waterflood are still producing at an average rate of 225 bbls/d per well after 90 days of production with no decline to date. These wells have cumulative recoveries of 16 Mbbls of oil per well after 90 days of production which is 25% above our 1.5 ERH resource type curve (12 Mbbls). At Kerrobert, we now have multiple examples of the positive impacts of the waterflood from the optimization of our injection profiles. This provides the potential for further upside from our ongoing injection expansion project that will see us convert an additional 4 horizontal and 14 vertical wells to water injection in the 2H/17.

West Central Alberta

In West Pembina, we drilled 8 (6.9 net) wells of which 6 (5.2 net) were ERH wells focused on the redevelopment of one of our operated legacy waterflood units (Cynthia Cardium Unit #1). The program included the drilling of our first unfractured horizontal water injector. The potential benefits of unfractured horizontal water injectors are cost savings of approximately $0.5 million to $0.75 million per well and better sweep efficiencies. Early indications are encouraging and could have significant implications for our Cardium pool recovery efficiencies and economic returns. We will continue the redevelopment of this Unit and anticipate a broader implementation of this injection strategy in 2018 once we have fully assessed the operational results.

The 7 producing wells drilled in Q2/17 are meeting or exceeding productivity expectations and costs are as forecasted.

Southwest Saskatchewan 

We were active in southwest Saskatchewan drilling 10 (7.5 net) horizontal oil wells including 6 (4.5 net) Atlas wells, 1 (1.0 net) Roseray well, 1 (0.5 net) Success well and 2 (1.5 net) Upper Shaunavon wells.

Since acquiring this asset, we have drilled 4 (2.5 net) infill development wells in our conventional legacy waterflood pools (Roseray and Success formations). On average, the initial production results are strong with average IP(60) rates of 150 bbls/d which are 50% higher than initial expectations on these very low decline pools.

The Atlas capital program continues to deliver solid production results with the most recent 6 wells on track to meet our average IP(30) expectations. In addition, a waterflood pilot application for the Atlas formation horizontal development has been submitted for regulatory approval and is expected to commence in Q3/17.

The initial results from our Upper Shaunavon wells are encouraging and continue to meet our type curve expectations.


It has been a full year since acquiring the southwest Saskatchewan assets in June 2016.  We are very pleased with the seamless integration and the strong operating results from the assets which is attributable to the performance of our field personnel. Since acquiring the assets, we have increased production by 23% to 14,000 boe/d, spent $41.6 million of capital and reduced operating costs by 17% in southwest Saskatchewan.

The results of our 1H/17 development capital program have been strong and we are well underway on executing the program for the remainder of the year. Whitecap currently has 4 drilling rigs operational; 2 in west central Saskatchewan, 1 in southwest Saskatchewan and 1 in the Deep Basin area of Alberta. We anticipate drilling  64 (51.6 net) wells in 2H/17 including 34 (29.4 net) Viking wells in west central Saskatchewan, 11 (4.8 net) wells in southwest Saskatchewan, 5 (4.9 net) Cardium wells in west central Alberta, 10 (8.7 net) horizontal oil wells in Deep Basin and 4 (3.8 net) Boundary Lake horizontal wells in northeast British Columbia.

Whitecap is well hedged in 2017 and, despite the current commodity price environment, we do not anticipate reducing our $300 million development capital budget for this year. Based on strip pricing, we are forecasting a 2017 total payout ratio of approximately 85% demonstrating our ability to continue to grow production within funds flow while paying our dividend to shareholders and reducing corporate net debt. We anticipate our 2017 total payout ratio can remain under 100% at a crude oil price as low as US$40/bbl WTI. Our drilling program for the current year will be completed by October 2017 and, as part of our ongoing review of the 2018 development capital program, we may consider accelerating a portion of our drilling plans from Q1/18 into Q4/17 in order to smooth out our operations and to mitigate the service sector constraints we experienced in Q1/17 for a more efficient drilling program. Although the impact to 2017 would be minimal, it provides for a more balanced and efficient drilling program and, more importantly, positions us for continued per share growth in 2018. We will look to balance the use of free funds flow to enhance our per share growth metrics and to increase the dividend as we monitor and adapt to the commodity price environment.

Once again, our Management team and Board of Directors would like to thank you for your ongoing support of Whitecap.

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”, “project”, “expect”, “forecast”, “budget”, “goal”, “plan”, “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, priorities, objectives and focus, completion plans, expectations regarding well results and initial production, benefits associated with unfractured water injectors, planned waterflood and enhanced oil recovery projects and the benefits therefrom, drilling program for 2H/17, our strategy to enhance long-term sustainability and our free funds flow profile including net debt to funds flow ratio, capital spending plans, future production and ability to meet future production targets, the anticipated benefits from the NCIB, future commodity prices, plans to allocate future funds flow, ability to increase long-term total shareholder return, enhance our per share metrics, anticipated and targeted net debt to funds flow ratio, acquisition plans, and our future dividend policy.

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 and resource 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 (

This press release contains future-oriented financial information and financial outlook information (collectively, “FOFI”) about Whitecap’s prospective results of operations, funds flow, and components thereof, all of which are subject to the same assumptions, risk factors, limitations, and qualifications as set forth in the above paragraphs. FOFI contained in this document was made as of the date of this document and was provided for the purpose of providing further information about Whitecap’s future business operations. Whitecap disclaims any intention or obligation to update or revise any FOFI contained in this document, whether as a result of new information, future events or otherwise, unless required pursuant to applicable law. Readers are cautioned that the FOFI contained in this document should not be used for purposes other than for which it is disclosed herein.

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.

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.

Oil and Gas Advisories

“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.

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.

“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 NCIB. 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                Six months ended
                                 June 30                                  June 30
($000s) 2017 2016 2017 2016
Cash flow from operating activities 146,526 93,485 261,624 176,864
Changes in non-cash working capital (24,656) (557) (15,519) (16,257)
Funds flow 121,870 92,928 246,105 160,607
Cash dividends declared 25,820 23,224 51,599 65,078
Development capital 67,654 16,159 191,715 61,397
Free funds flow 28,396 53,545 2,791 34,132
Total payout ratio (%) 77 42 99 79


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                Six months ended
                                 June 30                                  June 30
($000s) 2017 2016 2017 2016
Expenditures on PP&E 67,934 16,196 192,030 61,521
Expenditures on corporate and other assets (280) (37) (315) (124)
Development capital 67,654 16,159 191,715 61,397


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

“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.

“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.

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

“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)  June 30
 December 31
Long-term debt 760,950 773,395
Current liabilities 190,733 231,416
Current assets (116,980) (111,194)
Risk management contracts (14,408) (75,037)
Net debt 820,295 818,580


SOURCE Whitecap Resources Inc.

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