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CALGARY, AB, Oct. 28, 2021 /CNW/ - Whitecap Resources Inc. ("Whitecap" or the "Company") (TSX: WCP) is pleased to report its operating and unaudited consolidated financial results for the three and nine months ended September 30, 2021.
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 for the three and nine months ended September 30, 2021 which are available at www.sedar.com and on our website at www.wcap.ca.
FINANCIAL AND OPERATING HIGHLIGHTS
Three months ended September 30
Nine months ended September 30
Financial ($000s except per share amounts)
Petroleum and natural gas revenues
Net income (loss)
Dividends paid or declared
Expenditures on property, plant and equipment ("PP&E")
Total payout ratio (%) (1)
Average daily production
Crude oil (bbls/d)
Natural gas (Mcf/d)
Total (boe/d) (2)
Average realized price (3)
Crude oil ($/bbl)
Natural gas ($/Mcf)
Petroleum and natural gas revenues
Processing & other income
Petroleum and natural gas sales
Realized hedging gain (loss)
Operating netbacks (1)
Share information (000s)
Common shares outstanding, end of period
Weighted average basic shares outstanding
Weighted average diluted shares outstanding
Total payout ratio and operating netbacks do not have a standardized meaning under GAAP. Refer to non-GAAP measures in this press release for additional disclosure and assumptions.
Disclosure of production on a per boe basis in this press release consists of the constituent product types and their respective quantities disclosed in this table. Refer to oil and gas advisories in this press release for additional disclosure.
Prior to the impact of hedging activities and tariffs.
MESSAGE TO SHAREHOLDERS
Whitecap is pleased to report another exceptional quarter of operating and financial performance. We achieved average production in the third quarter of 115,935 boe/d which was 1,935 boe/d higher than our forecast of 114,000 boe/d as both our base production and new well results continue to outperform our expectations. We remain disciplined on capital investments with only $135 million invested in the third quarter compared to our forecast of $165 million.
Record quarterly funds flow of $294 million ($0.46 per share) resulted in discretionary funds flow of $128 million after capital investments of $135 million and dividends paid to shareholders of $31 million. Net income of $1.5 billion includes an after-tax impairment reversal of $1.4 billion due to increases in forward benchmark commodity prices.
We highlight the following third quarter financial and operating results:
Operational Excellence. Third quarter production of 115,935 boe/d (75% liquids) was 12% higher on a per share basis than the prior year quarter and slightly lower than the second quarter due to previously announced downtime at Weyburn, impacting third quarter production by approximately 1,600 boe/d (net to Whitecap).
Significant Free Funds Flow. Record funds flow of $294 million ($0.46 per share) was 59% higher on a per share basis than the prior year quarter and resulted in free funds flow of $159 million in the third quarter. Operating netback of $30.88/boe was 37% higher than the prior year quarter and 11% higher than the second quarter.
Increasing Cash Returns to Shareholders. Whitecap paid $31 million ($0.05 per share) in dividends during the third quarter along with repurchasing 3.1 million shares under its normal course issuer bid ("NCIB"). Year to date, Whitecap has paid $83.8 million ($0.14 per share) in dividends and repurchased 5.1 million shares under its NCIB at a weighted average price of $5.98 per share. Since the beginning of the year, Whitecap has increased its monthly dividend by 58% to $0.0225 per share.
Consolidating Core Areas. Whitecap closed the acquisition of a private company in Southeast Saskatchewan for $67 million. The acquisition adds approximately 1,600 boe/d (94% light oil) and 23 net sections of land (99% working interest) in the Weir Hill area. Based on current strip prices, annual run rate operating income on the acquisition is $32 million.
Balance Sheet Strength. Whitecap's balance sheet remains in excellent shape with a debt to EBITDA ratio of 1.2x at the end of the third quarter and is expected to be 0.9x by the end of the year, based on strip prices. Whitecap's credit facility is a secured, covenant-based credit facility with an extendible four-year term and not subject to annual redeterminations. Subsequent to the quarter end, Whitecap extended the maturity date on its credit facility to May 31, 2026 and with strong support from its banking syndicate, has increased the credit facility to $1.6 billion. The credit facility, when combined with $595 million of private placement notes outstanding, results in total credit capacity of $2.2 billion which provides Whitecap with significant financial flexibility.
Whitecap has significantly increased its production by 74% to 115,935 boe/d in the third quarter compared to 66,681 boe/d in the prior year quarter through our strategic acquisitions which closed in 2021. Our shareholders are now participating in the full integration and advancement of development opportunities on the acquired assets in addition to strengthening commodity prices.
Northern Alberta and BC
The most exciting developments in this business unit are associated with our Karr and Kakwa Montney assets. Since Whitecap took over operatorship of the Kakwa asset, we completed and brought on production 4 (4.0 net) wells with very encouraging results. The wells averaged 1,195 boe/d (47% liquids) per well over the first 30 days on production which includes a post frac clean-up period and in aggregate are currently producing 5,300 boe/d (47% liquids).
Average well costs of $10 million for these four wells are lower than our original expectations, with our 2022 budget incorporating a 5-10% improvement from our original estimate of $10.7 million per well and the potential for further improvements.
Our 02/13-1 Montney well at Karr, which was completed with an optimized frac design, has produced 275 Mboe (63% liquids) in the 203 days it has been on production. We will be spudding a 4 well pad at Karr offsetting the 02/13-1 well in the third quarter of 2022.
This business unit also contains our Charlie Lake assets in Northwest Alberta. The 2021 program included 2 (1.7 net) development wells and 1 (0.8 net) extensional test in a new Charlie Lake horizon. The two-mile extended reach horizontal ("ERH") development wells achieved strong results with average IP(180) rates of 1,236 boe/d (63% liquids) per well on average capital cost per well of $4.4 million.
Our Central Alberta business unit contains more mature assets, and diligent reservoir management and development design have improved capital efficiencies in this area. We recently drilled a conceptual horizontal well to initiate redevelopment into an extension of our Garrington area. The well was drilled with an advanced horizontal well bore and stimulation design and has significantly exceeded our expectations with an IP(60) rate of 682 boe/d (90% liquids) which is 42% above our budget expectations. We have identified 50 (31.6 net) analogous drilling locations, primarily two-mile ERH wells, in this area.
We also drilled 2 (2.0 net) two-mile ERH Cardium oil wells in the Kaybob/Rosevear area on lands acquired in 2021. We modified the wellbore placement and stimulation based on our advanced reservoir modelling and experience. These wells have recently been brought on production, with initial results indicating that our modifications were effective. Our redesign has resulted in a 25% reduction to drill and complete costs compared to previous wells.
The results from our 2021 Viking program have exceeded our expectations as our team continues to use geological review and recovery enhancement techniques to improve, and add to, our drilling inventory. We drilled 37 (32.5 net) Viking wells to date in 2021, all of which are ERH's. On an IP(180) basis, we have outperformed our budget expectations by 34% so far this year while maintaining capital costs.
In Southwest Saskatchewan, we drilled 27 (20.5 net) wells year to date, highlighted by significant cost improvements from our Lower Shaunavon program. Average well costs since we entered the play in 2018 have decreased approximately 30% to $1.2 million and spud to rig release times have decreased approximately 30% to 5 days with the potential to further reduce to $1.0 million per well and 4 days, respectively.
The integration of acquired assets in Southeast Saskatchewan has been seamless and significant benefits have been realized through strong collaboration between both prior and new team members. A total of 26 (22.8 net) Frobisher wells have been drilled in 2021 on these lands by Whitecap and its predecessors. Of these wells, 16 have more than 180 days of production history with an average IP(180) rate of 180 boe/d (93% liquids) which is double the rate of our initial dual leg budget expectations.
At Weyburn, we made another step change in the design and optimization of our CO2 enhanced oil recovery ("EOR") development. Year to date, we drilled 6 (3.9 net) wells of which two were injectors. The four producing wells have average IP(60) rates of 162 bbl/d of crude oil which is double our budget expectations for a CO2 EOR infill well. As a result, we increased our long-term production forecasts, incorporating the improved results into future design of CO2 flood development programs.
The continued operational success and recent corporate activities are advancing Whitecap towards our short and long-term targets, within our stated priorities of balance sheet strength, modest growth (3-5%) and sustainable and growing return of capital to shareholders through dividends and share buybacks.
We are well on track towards achieving our 2021 average production of 111,000 – 112,000 boe/d (76% liquids) on development capital investment of $425 – $435 million, putting us in a strong position to achieve our 2022 average production of 121,000 – 123,000 boe/d (73% liquids) on capital spending of $470 - $490 million.
We closed the Weyburn royalty sale for $188 million on October 26, 2021, further solidifying our balance sheet strength and our expectation of reaching our net debt target of $1 billion by year end 2021. Our balance sheet is in pristine condition with an expected debt to EBITDA ratio of 0.9x at year end 2021.
In addition to recently increasing our base monthly dividend by 38% to $0.0225 per share, we have committed to returning 50% of 2022 discretionary funds flow back to our shareholders through further dividend increases and/or share buybacks. We will direct the remaining 50% towards our balance sheet to provide increased financial flexibility for continued advancement of our business through targeted acquisitions and/or New Energy initiatives to enhance total shareholder returns.
We are expecting continued strength in both crude oil and natural gas prices for the fourth quarter of 2021 and into 2022. Fossil fuel energy continues to be critical for meeting global energy demand especially as we move into the colder winter season and will remain an important part of the energy transition for many years to come. Whitecap is well positioned to participate in the strong pricing environment while responsibly developing and producing our assets.
On behalf of our management team and Board of Directors, we would like to thank our shareholders for their ongoing support and look forward to providing updates as we progress through the remainder of the year and into 2022.
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, October 28, 2021.
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.
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", "potential", 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, focus, objectives, priorities and position; the anticipated benefits of the Southeast Saskatchewan acquisition; our expected debt to EBITDA ratio of 0.9x by year end 2021 based on strip prices; estimated $10.7 million per well costs, ability to reduce such original estimate by 5-10% and potential for further improvements with the Karr and Kakwa assets; timing to spud a 4 well pad at Karr; potential to further reduce well costs to $1.0 million per well and spud to rig release times to 4 days in Whitecap's Lower Shaunavon program; the anticipated benefits of future CO2 flood well designs; that operational success and corporate activities will translate to meet short and long term targets; our 2021 average production and capital spending; our 2022 average production and capital spending; our expectation to reach $1.0 billion net debt by year end 2021; our anticipation to direct 50% of 2022 discretionary funds flow to shareholders and 50% towards our balance sheet and the benefits to be derived therefrom; the expected strength in crude oil and natural gas prices in the fourth quarter of 2021 and into 2022; and that fossil fuel energy will remain an important part of the energy transition for many years to come.
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; the impact (and the duration thereof) that the COVID-19 pandemic will have on (i) the demand for crude oil, NGLs and natural gas, (ii) our supply chain, including our ability to obtain the equipment and services we require, and (iii) our ability to produce, transport and/or sell our crude oil, NGLs and natural gas; 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. These include, but are not limited to: the risks associated with the oil and gas industry in general such as operational risks in development, exploration and production; pandemics and epidemics; delays or changes in plans with respect to exploration or development projects or capital expenditures; the uncertainty of estimates and projections relating to reserves, production, costs and expenses; health, safety and environmental risks; commodity price and exchange rate fluctuations; interest rate fluctuations; marketing and transportation; loss of markets; environmental risks; competition; incorrect assessment of the value of acquisitions; failure to complete or realize the anticipated benefits of acquisitions or dispositions; ability to access sufficient capital from internal and external sources; failure to obtain required regulatory and other approvals; reliance on third parties and pipeline systems; and changes in legislation, including but not limited to tax laws, production curtailment, royalties and environmental regulations. 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.
This press release contains future-oriented financial information and financial outlook information (collectively, "FOFI") about run rate operating income on the Southeast Saskatchewan acquisition; Whitecap's 2021 capital investments; 2021 year-end net debt; 2022 capital investments; total credit capacity; and debt to EBITDA ratio, all of which are subject to the same assumptions, risk factors, limitations, and qualifications as set forth in the above paragraphs. The actual results of operations of Whitecap and the resulting financial results will likely vary from the amounts set forth in this presentation and such variation may be material. Whitecap and its management believe that the FOFI has been prepared on a reasonably basis, reflecting management's best estimates and judgments. However, because this information is subjective and subject to numerous risks, it should not be relied on as necessarily indicative of future results. Except as required by applicable securities laws, Whitecap undertakes no obligation to update such FOFI. FOFI contained in this press release was made as of the date of this press release and was provided for the purpose of providing further information about Whitecap's anticipated future business operations. Readers are cautioned that the FOFI contained in this press release should not be used for purposes other than for which it is disclosed herein.
Oil and Gas Advisories
References to crude oil or natural gas production in this press release refer to the light and medium crude oil and conventional natural gas, respectively, product types as defined in National Instrument 51-101, Standards of Disclosure for Oil and Gas Activities ("NI 51-101").
"Boe" means barrel of oil equivalent based on 6 mcf of natural gas to 1 bbl of oil. Boe may be misleading, particularly if used in isolation. A boe conversion ratio of 6:1 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.
Any references in this news release to initial production rates (Current, IP(30), IP(60), IP(180)) 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.
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's reserves evaluation effective December 31, 2020 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 50 (31.6 net) Garrington drilling locations identified herein, 4 (3.0 net) are proved locations, 2 (1.0 net) are probable locations, and 44 (27.6 net) 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 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.
Q3 2021 Forecast
Southeast Saskatchewan Acquisition
Kakwa 30 day average per well
Kakwa current average per well
Charlie Lake IP(180) per well
Frobisher IP(180) per well
74,600 – 75,200
10,100 – 10,400
157,800 – 158,400
111,000 – 112,000
78,000 – 79,200
10,300 – 10,600
196,200 – 199,200
121,000 – 123,000
Disclosure of production on a per boe basis of amounts in the above table in this press release consists of the constituent product types and their respective quantities disclosed in this table.
02/13-01 Karr Montney Well
Disclosure of production on a per boe basis of amounts in the above table in this press release consists of the constituent product types and their respective quantities disclosed in this table.
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, 2021 for a reconciliation of the non-GAAP measures.
"Debt to EBITDA" is calculated in accordance with the Company's credit agreements, copies of which may be accessed through the SEDAR website (www.sedar.com).
"Discretionary funds flow" represents funds flow less expenditures on PP&E and dividends. Management believes that discretionary funds flow provides a useful measure of Whitecap's ability to increase returns to shareholders and to grow the Company's business.
"Free funds flow" represents funds flow less expenditures on PP&E. Management believes that free funds flow provides a useful measure of Whitecap's ability to increase returns to shareholders and to grow the Company's business. Previously, Whitecap also deducted dividends paid or declared in the calculation of free funds flow. The Company believes the change in presentation better allows comparison with both dividend paying and non-dividend paying peers.
"Run rate operating income" is determined by adding marketing revenue and processing & other income, deducting realized hedging losses or adding realized hedging gains and deducting tariffs, royalties, operating expenses, transportation expenses and marketing expenses from petroleum and natural gas revenues that are projected over the following twelve months based on forward commodity prices.
"Operating netbacks" are determined by adding marketing revenue and processing & other income, deducting realized hedging losses or adding realized hedging gains and deducting tariffs, royalties, operating expenses, transportation expenses and marketing expenses from petroleum and natural gas revenues. 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.
"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.
Per Share Amounts
Per share amounts noted in this press release are on a fully diluted basis.
SOURCE Whitecap Resources Inc.
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