Whitecap Resources Inc. Announces Record Funds Flow and Third Quarter 2018 Results

CALGARY, Nov. 1, 2018 /CNW/ - Whitecap Resources Inc. ("Whitecap" or the "Company") (TSX: WCP) is pleased to report its operating and unaudited financial results for the three and nine months ended September 30, 2018.

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 SHAREHOLDERS

Whitecap delivered another excellent quarter with strong operational and financial results. Production for the third quarter averaged 75,529 boe/d (84% oil and NGLs), approximately 1,000 boe/d higher than our internal forecast on lower than expected capital spending of $115 million. We now expect average annual production to increase to 74,500 boe/d on full year capital spending of approximately $450 million.

In the third quarter, we generated funds flow of $205 million ($0.49/share), invested $115 million to grow production per share and returned $33.8 million in dividends to shareholders which resulted in $56.2 million of free funds flow.

Property acquisitions in the third quarter totaled $18.4 million which included acquiring a facility working interest in the Deep Basin and a gross overriding royalty ("GORR") acquisition at Weyburn. We also had non-core property dispositions of $9.8 million.

Ownership of the facilities in the Deep Basin eliminates down-time risk of oil production and related funds flow, allows Whitecap to be proactive and control the pace of development in our highest growth area and reduces processing fees paid. The GORR acquisition provides both near-term accretion to the Weyburn operating netback and long-term enhancement of the well economics.

Whitecap's priority is to maintain a strong balance sheet. Net debt at the end of the quarter was approximately $1.3 billion on credit capacity of $1.7 billion and net debt to annualized Q3/18 funds flow ratio was 1.6 times. Despite the current wider than normal Canadian crude oil differentials, Whitecap continues to fund its organic growth program and dividend obligations well within the funds flow generated from its premium crude oil assets.

Q3/18 Highlights

• Increased average production to 75,529 boe/d compared to 57,898 boe/d in Q3/17, an increase of 30% (16% per share). Whitecap's oil and NGLs weighting continued to increase with Q3/18 at 84% compared to 82% in Q3/17.
  
  
• Realized an operating netback (prior to hedges) of $38.47/boe compared to $25.38/boe in Q3/17, a 52% increase. Operating netback was $32.78/boe compared to $25.46/boe in Q3/17, a 29% increase.
  
  
• Generated funds flow for the quarter of $205 million ($0.49 per share), an increase of 72% (53% per share) from Q3/17. Higher production volumes and realized prices in Q3/18 resulted in significantly higher funds flow.
  
  
• Invested $115 million in expenditures on PP&E, drilling 76 (61.3 net) horizontal oil wells with a 100% success rate.
  
  
• Achieved a total payout ratio of 73% including expenditures on PP&E and dividend payments.
  
  
• Returned $42.2 million to shareholders through dividends and share repurchases.

Operational Update

Operational execution and performance in the third quarter continued to be exceptional. Overall, our programs were completed slightly ahead of schedule with results exceeding expectations on both cost and productivity. In the third quarter, we drilled a total of 76 (61.3 net) wells across our five management units ("MU").

NW Alberta & BC

We drilled a total of 10 (7.3 net) horizontal oil wells in this MU of which 30% were extended reach horizontal ("ERH") wells. This included 7 (4.3 net) Cardium and 3 (3.0 net) Dunvegan wells.

Our Wapiti Cardium program continues to outperform with average IP(90) rates 13% higher than our expectations with average cost per well as estimated. We continue to refine our operational and technical designs and anticipate cost reductions to our drill, complete, equip and tie-in (DCE&T) costs by 5 to 10% going forward. We have de-risked the primary potential of this asset base and will work towards the full development of this area from its current production of 5,400 boe/d to an estimated 15,000 boe/d over the next five years in addition to concurrently evaluating the potential for future enhanced reserve recovery.

West Central Alberta

The third quarter was quiet operationally in this MU with no drilling activity. However, we have been seeing very encouraging response from our unstimulated horizontal water injectors in our operated Cardium oil properties in West Pembina and are currently reviewing options to accelerate expansion of our operated waterflood redevelopment.

We have also seen very encouraging results from the reconfiguration and expansion of our Elnora Nisku oil pool waterflood where we have substantially mitigated natural declines through repressurization of the reservoir and improved sweep of the oil in place. This reconfiguration has resulted in the reactivation of two wells that added 200 boe/d at much lower water cuts than when they were originally shut-in.

West Central Saskatchewan

We had a very active third quarter in this MU drilling 33 (28.6 net) horizontal Viking oil wells of which 55% were ERH wells. The strong results we achieved in the second quarter continued into the third quarter with operational results outperforming our expectations. Our operating netback for this MU remained exceptionally strong at approximately $52/boe in the quarter.

In addition, we have seen very encouraging results in our Kerrobert waterfloods where we now have over 30 wells exhibiting positive influence from the water injection support with flattening production declines or, in some cases, inclining production. This response trend is significant enough to now be clearly seen over the past two years on a group production plot of the wells in our most mature waterflood area and indicates the potential of significant incremental reserve recovery. We are actively evaluating our opportunities to accelerate and/or expand our waterflood initiatives at Kerrobert and Dodsland.

Southwest Saskatchewan

Activity in the third quarter in this MU included the drilling of 26 (21.2 net) wells including 14 (12.3 net) Atlas, 3 (2.4 net) Upper Shaunavon, 2 (2.0 net) Lower Shaunavon, 2 (1.0 net) Roseray and 5 (3.5) Success Sand wells.

The two Lower Shaunavon wells exceeded expectations with an average IP(30) rate of 229 boe/d. These results have opened a new development area where we have identified and further de-risked upwards of 180 gross locations.

We have had exceptional results extending our Atlas oil development program in the Beverley area. The two extension wells we drilled in the quarter had an average IP(30) rate of 196 boe/d, 25% above our expectations. In addition, the Atlas waterflood pilot project we had initiated earlier has recently shown very encouraging results and we are moving ahead on expanding the waterflood pilot area from three sections to six sections with a line of sight to a full development across 20+ sections.

The remainder of our operated 2018 program, which has been completed for the year, continues to exceed our expectations.

Southeast Saskatchewan (Weyburn)

In the third quarter, we drilled 7 (4.2 net) wells and anticipate a further 9 (5.6 net) wells to be drilled in the fourth quarter. Of the 16 (9.8 net) wells planned for 2018, 6 (3.6 net) are new CO₂/water injector drills. Results to date have met expectations.

We also purchased a Weyburn Unit GORR encumbrance for $12.5 million at a very attractive valuation. In addition to enhancing our netbacks in Weyburn, the acquisition greatly improves the economics on 57% of our future CO₂ expansion areas which was the primary objective of this acquisition.

For the nine months ended September 30, 2018, the Weyburn asset contributed $145 million of operating income on capital expenditures of approximately $30 million resulting in a surplus of $115 million. The operating income was higher and capital spending was lower than our expectations when we acquired this asset in late December last year. The asset's strong operating and financial performance continues to increase our confidence in the value of this asset into the future.

Corporately, across our asset base, we continue to see positive response from our enhanced oil recovery and waterflood development and expansion and anticipate being able to continue to positively impact our corporate base declines from the current 19%.

The drilling program for the remainder of the year is anticipated to be 35 (19.9 net) wells, including 13 (8.9 net) wells in west central Saskatchewan, 9 (5.6 net) wells in southeast Saskatchewan, 8 (4.4 net) wells in northwest Alberta and BC and 5 (1.0 net) wells in southwest Saskatchewan.

Outlook

West Texas Intermediate crude oil at approximately US$65/bbl remains robust and continues to be supported by strong oil demand, increasing geopolitical risk and a decrease in spare productive capacity globally. However, headwinds for Canadian oil producers remain. In the fourth quarter of 2018, the Western Canadian Select ("WCS") differential for Canadian heavy crude significantly widened to approximately US$45/bbl from what was historically US$15 to US$20/bbl. Whitecap is predominately a light oil producer and the light oil differential ("MSW") has also widened to approximately US$25/bbl from what was historically US$5 to US$8/bbl.

Whitecap has proactively mitigated the impact of the challenging differential environment by hedging approximately 32% of our Q4/18 light oil production at an average MSW differential of US$3.50/bbl and 54% of our Q4/18 medium oil production at an average WCS differential of US$15/bbl. In addition, Whitecap mitigates the impacts from pipeline apportionment through a diverse and growing portfolio of direct relationships with crude oil purchasers, refiners, pipelines, midstream operators and trucking providers. We optimize crude oil sales by utilizing our capacity at owned and operated facilities and storage assets across multiple pipelines and oil sales streams. We also utilize short and long-term firm pipeline transportation contracts and have apportionment protected our crude oil sales with certain purchasers. We are further insulated from pipeline apportionment as 50% of Whitecap's crude oil production is downstream of current pipeline apportionment points and garners higher pricing.

We anticipate the extremely wide differential pricing environment to be temporary and see a line of sight to improving Canadian oil differentials in 2019 as U.S. Midwest refinery maintenance season comes to an end, increasing crude by rail takeaway, and activation of Enbridge's Line 3 replacement expansion which should add 375,000 bbl/d of incremental export capacity around the end of 2019.

Whitecap continues to be well positioned to deliver meaningful returns to our shareholders with a solid balance sheet, strong operational performance and significant free funds flow. We look forward to releasing our 2019 budget on December 5, 2018.

On behalf of the Board of Directors and the Whitecap management team, we would like to thank our shareholders for their ongoing support.

Conference Call and Webcast

Whitecap has scheduled a conference call and webcast to begin promptly at 9:00 am MT (11:00 am ET) on Thursday, November 1, 2018.

The conference call dial-in number is: 1-888-390-0605 or (587) 880-2175 or (416) 764-8609

A live webcast of the conference call will be accessible on Whitecap's website at www.wcap.ca by selecting "Investors", then "Presentations & Events". Shortly after the live webcast, an archived version will be available for approximately 14 days.

An archived recording of the conference call will also be available approximately two hours after the completion of the call until November 15, 2018 by dialing 1-888-390-0541, passcode 409325#.

Note Regarding Forward-Looking Statements

This press release contains forward-looking statements and forward-looking information (collectively "forward-looking information") within the meaning of applicable securities laws relating to the Company's plans and other aspects of our anticipated future operations, management focus, strategies, financial, operating and production results and business opportunities. Forward-looking information typically uses words such as "anticipate", "believe", "continue", "trend", "sustain", "project", "expect", "forecast", "budget", "goal", "guidance", "plan", "objective", "strategy", "target", "intend", "estimate", 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; the Company's hedging program; expected annual production and full year capital spending; benefits of the GORR acquisition; anticipated reduction to DCE&T costs; ability to develop Wapiti Cardium production over the next 5 years; the potential for future reserve recovery enhancements; options to accelerate and/or expand waterfloods; potential of significant incremental recovery in west central Saskatchewan potential to expand into a new development area; the drilling program for the remainder of 2018; ability to positively impact the Company's corporate base declines; the future potential of the Weyburn asset; and the impact of widening crude oil differentials.

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

"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, such as "operating netbacks" and "operating netbacks (prior to hedges)". . See "Non-GAAP Measures". These terms have been calculated by management and 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. Management uses these oil and gas metrics for its own performance measurements and to provide Shareholders with measures to compare our operations over time. Readers are cautioned that the information provided by these metrics, or that can be derived from the metrics presented in this press release, should not be relied upon for investment or other purposes.

Production Rates

Any references in this news release to initial production rates (IP(30) or IP(90)) 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.

Drilling Locations

This press release discloses drilling inventory in the Bench area of Southwest Saskatchewan 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, 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 180 total drilling locations identified herein, 1.0 are proved locations, 2.0 are probable locations and 177 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. See the Company's Management's Discussion and Analysis of financial condition and results of operation for the period ended September 30, 2018 for a reconciliation of the non-GAAP measures.  

"Free funds flow" represents funds flow less dividends paid or declared and expenditures on PP&E. Management believes that free funds flow provides a useful measure of Whitecap's capital reinvestment and dividend policy.

"Operating income" is determined by adding blending revenue and processing income, deducting realized hedging losses or adding realized hedging gains and deducting tariffs, royalties, operating expenses, transportation expenses and blending expenses from petroleum and natural gas revenues. Operating income is used in operational and capital allocation decisions. Management uses operating income to better analyze performance among its management units.

"Operating netbacks" are determined by dividing operating income by total production for the period. Operating netbacks are per boe measures used in operational and capital allocation decisions. Presenting operating netbacks on a per boe basis allows management to better analyze performance against prior periods on a comparative basis.

"Operating netbacks (prior to hedges)" are determined by adding blending revenue and processing income, and deducting tariffs, royalties, operating expenses, transportation expenses and blending expenses from petroleum and natural gas revenues. Operating netbacks (prior to hedges) are per boe measures used in operational and capital allocation decisions excluding the impact of the Company's hedging program. Presenting operating netbacks (prior to hedging) on a per boe basis allows management to better analyze performance against prior periods on a comparative basis.

"Total payout ratio" is calculated as dividends paid or declared plus expenditures on PP&E, divided by funds flow. Management believes that total payout ratio provides a useful measure of Whitecap's capital reinvestment and dividend policy, as a percentage of the amount of funds flow.

SOURCE Whitecap Resources Inc.

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