Whitecap Resources Inc. Announces First Quarter 2017 Results

CALGARY, May 3, 2017 /CNW/ - Whitecap Resources Inc. ("Whitecap" or the "Company") (TSX: WCP) is pleased to report its operating and unaudited financial results for the three months ended March 31, 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 www.sedar.com and on our website at www.wcap.ca.

FINANCIAL AND OPERATING HIGHLIGHTS

Message to our shareholders

In the first quarter of 2017, Whitecap efficiently executed one of its most active capital programs to date drilling 92 (81.2 net) wells with a 100 percent success rate. Development capital spending of $124.1 million was 17% below our budget of $145 - $150 million. We realized exceptional capital efficiencies and production additions which were partially offset by unseasonably warm weather in February and lack of service sector availability which delayed the completion of 11 wells. These drilled but uncompleted wells are now scheduled to be on production by the end of Q2/17. Despite the delays, we were able to achieve record production of 55,886 boe/d (82% oil and NGLs) which was at the high end of our 55,000 – 56,000 boe/d guidance.

Record production volumes and improving commodity prices resulted in funds flow of $124.2 million in Q1/17 compared to $67.7 million in Q1/16, an increase of 84%. Funds flow per share also increased by 50% from $0.22 per share for the comparable period to $0.33 per share in Q1/17.

Whitecap continues to maintain a strong balance sheet with unutilized credit capacity of $452 million and a net debt to funds flow ratio of 1.7 times at the end of the quarter. On strip pricing, we anticipate achieving a net debt to funds flow ratio of under 1.5 times in Q2/17 and anticipate that our total payout ratio in 2017 will be approximately 75% after capital spending and dividend payments. In addition, we were able to diversify our capital structure through the issuance of $200 million senior secured notes which have an annual coupon rate of 3.46% and mature on January 5, 2022.

Quarterly highlights:

• Average production in Q1/17 increased to a record 55,886 boe/d, 10% higher than Q4/16 and 30% higher than Q1/16. Whitecap's oil and NGLs weighting continued to increase in the quarter to 82% from 80% in Q4/16 and 76% in Q1/16.
  
• Whitecap's Q1/17 production per share increased 10% relative to Q4/16 and 7% relative to Q1/16.
  
• Funds flow for the quarter totalled $124.2 million ($0.33 per share), an increase of 84% (50% per share) from Q1/16. Higher production volumes in Q1/17 in combination with more robust commodity prices resulted in significantly higher funds flow.
  
• Whitecap continues to protect its funds flow through an active hedging program with 42% of the Company's remaining 2017 crude oil production, net of royalties hedged at an average floor price of C$63.44/bbl and 16% of 2018 crude oil production, net of royalties hedged at an average floor price of C$60.87/bbl. Whitecap also has 51% of its remaining 2017 natural gas production, net of royalties hedged at an average floor price of $3.06/mcf and 6% of first half 2018 natural gas production, net of royalties hedged at an average floor price of $2.76/mcf.
  
• Development capital expenditures for the quarter totalled $124.1 million compared to $45.2 million in Q1/16 as higher commodity prices supported a return to profitable per share growth. Whitecap drilled 92 (81.2 net) wells in the quarter.
  
• During the quarter, the Company completed $4.5 million (net) in property acquisitions further consolidating its working interest at Boundary Lake.
  
• In January, Whitecap issued $200 million senior secured notes which have an annual coupon rate of 3.46% and mature on January 5, 2022.

OPERATIONAL UPDATE

Southwest Saskatchewan

We continued to build off our strong Q4/16 drilling program in southwest Saskatchewan drilling an additional 12 (7.9 net) horizontal oil wells in Q1/17 including 7 (4.2 net) Atlas wells, 3 (2.7 net) Upper Shaunavon wells, 1 (0.5 net) Roseray well and 1 (0.5 net) Success well.

The Atlas capital program continued to deliver strong results with average IP(60) rates of 138 boe/d which was 70% above our budget type curve. Drill, complete and equip and tie-in costs averaged $0.96 million per well and were 18% below budget. Since closing the southwest Saskatchewan asset acquisition in June 2016, we have increased production from 11,400 boe/d to current production in excess of 14,000 boe/d by spending only $28.2 million of development capital. Operating costs per boe have decreased from $16.71/boe on acquisition to approximately $14.75/boe in Q1/17.

In the Upper Shaunavon, two wells are on production and trending within our budget type curve and one additional well will be completed and on production in Q2/17. Initial results from the Roseray and Success are positive but will need additional drilling results to support any changes to our current expectations.

In addition to completing the 1 (1.0 net) Upper Shaunavon well from our Q1/17 program, we plan on drilling another 21 (10.8 net) wells in southwest Saskatchewan for the remainder of the year as well as potentially increasing the program to leverage the better than anticipated results we have had to date.

West Central Saskatchewan

We had an active capital program in west central Saskatchewan with 3 rigs drilling a total 52 (48.3 net) Viking horizontal oil wells in Q1/17. This included 35 (34.0 net) extended reach horizontal ("ERH") wells and 1 (1.0 net) ERH water injection well in Kerrobert. Well productivity and costs for our Q1/17 program were as expected.

Timing delays due to unseasonably warm weather in February and limited fracture stimulation service availability in the Kindersley area resulted in 9 wells that were drilled but not completed in Q1/17. In addition to completing these 9 wells drilled in Q1/17, we plan on drilling 53 (48.3 net) wells over the remainder of the year. We will also continue to move forward on our waterflood expansion/optimization plans by converting 17 vertical wells and 8 horizontal wells to injection across our Viking fairway.

West Central Alberta

In West Pembina, during the quarter we were active drilling 14 (12.2 net) Cardium horizontals wells of which 4 (3.8 net) were ERH wells. Results were predictable and in-line with our current type curve for both production and capital costs. In addition, we re-initiated a suspended waterflood offsetting the actively waterflooded units by converting an existing horizontal producer to an injector. We plan on drilling an additional 8 (7.0 net) Cardium horizontal oil wells in West Pembina which will focus on redevelopment of one of our legacy waterflood units.

In Ferrier, we focused on redeveloping this light oil waterflood asset by drilling 4 (4.0 net) Cardium horizontal wells. The initial production rates and development capital expenditures were in line with expectation and set the stage for continued optimization and re-development of this proven legacy waterflood asset.

In the Elnora Nisku light oil pool, we drilled 2 (2.0 net) horizontal development wells and 1 (1.0 net) vertical extension well in Q1/17. The vertical extension well encountered approximately 24 meters of net pay that significantly extended the pool boundaries and potentially increased the pool size by 15-20%. Production results from existing and new wells in combination with our reservoir simulation model has indicated that a more conservative withdrawal rate of the reserves in combination with optimized injection patterns will lead to increased recoveries and value. As a result, we have curtailed the pool production rates by approximately 20%. We anticipate additional injection and maintenance capital to optimize the pool to remain low at approximately $3 - $6 million per year moving forward.

Deep Basin Alberta

At Wapiti, we drilled 3 (3.0 net) Cardium horizontal oil wells as a continuation of our Q4/16 program for a total of 6 (6.0 net) wells to date. As part of this 6 well program we focused on redesigning and optimizing our well placement and stimulation which has resulted in average IP(30) rates of 370 barrels of oil per day, 49% higher than our type curve expectations. These results will have significant implications for the development of the remaining 101 (41.6 net) locations of which 78% are un-booked locations. We plan to drill an additional 3 (3.0 net) Cardium horizontal wells at Wapiti over the balance of the year.

At the end of the quarter, we successfully drilled 1 (0.5 net) and completed 2 (1.0 net) two-mile horizontal Dunvegan wells in Karr. Initial production rates on these two-mile wells are encouraging with average IP(30) rates of 450 barrels of oil per day. Break-up conditions have limited our ability to perform a full evaluation of the Karr horizontal wells as these wells are producing at approximately 50% of anticipated full capability. We also participated in 1 (0.5 net) non-operated Dunvegan horizontal well in Q1/17 which will be completed in Q2/17. We plan to drill an additional 5 (4.4 net) Dunvegan horizontal oil wells in the Deep Basin in 2017.

Boundary Lake British Columbia

In Boundary Lake, we drilled 2 (1.8 net) Triassic horizontal oil wells as a continuation of our successful Q4/16 program for a total of 6 (5.6 net) wells. The 5 (4.5 net) horizontal wells in this program had an average IP(60) rate of 228 boe/d, a 33% increase compared to the Q1/16 program average IP(60) rate of 171 boe/d. In addition to drilling 4 (3.7 net) horizontal wells over the balance of the year, we have also allocated $5 million of our 2017 capital towards waterflood optimization and expansion to further increase reserve recovery which will result in further mitigating production declines at Boundary Lake.

OUTLOOK

We are excited with the results from our Q1/17 capital program, and post break-up, will move quickly to complete the wells that were deferred into Q2/17. We currently have one rig operating in West Pembina and will continue to do so through break-up. Post break-up we intend to have two drilling rigs operational in west central Saskatchewan and as we enter Q3/17 to add an additional 3-4 drilling rigs to complete our capital program in southwest Saskatchewan, the Deep Basin and Boundary Lake.

We anticipate Q2/17 production volumes to be 57,000 – 59,000 boe/d and with the exceptional Q1 results, we remain on track to meet our full year guidance of 57,000 boe/d on $300 million of development capital.

Crude oil prices continue to be volatile heading into the OPEC meeting on May 25, 2017 as the market balances the potential for continued production cuts among OPEC and non-OPEC members with concerns over growing U.S. production output. Our business remains solid despite the volatility and we believe, at times, our prevailing share price does not reflect the underlying value of our assets. As such, Whitecap intends to make an application to implement a normal course issuer bid ("NCIB") through the facilities of the Toronto Stock Exchange and alternate Canadian trading platforms, pursuant to which Whitecap would have an option to repurchase its common shares for cancellation. The NCIB is another tool available to management to increase long-term total shareholder returns. Our first priority is to ensure our net debt to funds flow ratio is under 1.5 times and believe that we are well positioned to further allocate our free funds flow to both enhancing our per share metrics and increasing our dividend as we move through 2017 and into 2018.

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", "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, planned waterflood and enhanced oil recovery projects, our strategy to enhance long-term sustainability and our free funds flow profile, capital spending plans, future production, plans to implement an NCIB and the anticipated benefits therefrom, future commodity prices, plans to allocate future funds flow, ability to increase long-term total shareholder return, enhance our per share metrics, increase our dividend, 2017 funds flow, 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 (www.sedar.com).

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.

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 & Associates Consultants Ltd.'s reserves evaluation effective December 31, 2016 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 101 drilling locations in the Cardium at Wapiti identified herein, 20 are proved locations, 2 are probable locations and 79 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.

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 and make capital investments. 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):

"Development capital" represents expenditures on property, plant and equipment excluding corporate and other assets.

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

"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, 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 bank 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 bank debt (a GAAP measure) to net debt (a non-GAAP measure):

SOURCE Whitecap Resources Inc.

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