CALGARY, AB, Feb. 14, 2022 /CNW/ - Whitecap Resources Inc. ("Whitecap" or the "Company") (TSX: WCP) is pleased to present the results of our 2021 year end reserves evaluation as prepared by McDaniel & Associates Consultants Ltd. ("McDaniel").

Our 2021 year end reserves were exceptional and are a direct result of the successful execution and development of our strategic acquisitions and the continued outperformance of our base assets. Whitecap's high quality drilling inventory provides years of highly profitable sustainable growth and free funds flow with our reserve life index of 17.6 years representing only 51% of our total internally estimated reserves potential.

We highlight the following 2021 year end reserve report results:

  • Acquisitions Drove Significant Reserve Additions. Proved developed producing ("PDP") reserves increased 53% to 320.3 million boe, total proved ("TP") reserves increased 50% to 545.9 million boe and total proved plus probable ("TPP") reserves increased 51%, compared to the prior year. Our successful acquisition strategy resulted in production replacement of 372% on a PDP basis, 545% on a TP basis and over 700% on a TPP basis at very attractive finding, development and acquisition ("FD&A") costs, increasing the profitability of our business.
  • Strong FD&A Metrics. Our strategic acquisitions, together with the efficient execution of our development capital program, resulted in strong low FD&A costs. Relative to 2020, PDP FD&A costs decreased 22% to $14.95 per boe, TP FD&A costs decreased 7% to $13.67 per boe and TPP FD&A costs decreased 10% to $11.22 per boe, generating recycle ratios of 2.0x, 2.2x and 2.7x, respectively. Whitecap's FD&A recycle ratio (TPP) increased 59% to 2.7x and our finding and development ("F&D") recycle ratio (TPP) has increased greater than 400% to 6.4x, meaningfully increasing the long-term sustainability of our business.
  • Growth in Net Present Value per Share. PDP net present value ("NPV"), using a 10% discount rate, increased by 56% to $7.51 per share, TP NPV increased by 70% to $10.80 per share and TPP NPV increased by 134% to $15.28 per share, as compared to the prior year. The NPV calculations performed by McDaniel used an average 2022-2026 WTI price of US$69.18/bbl (three consultants average) which is lower than current strip prices.
  • Long Reserve Life and Low Decline Rate Reinforce Sustainability. PDP, TP and TPP reserve life index of 7.3 years, 12.5 years and 17.6 years, respectively, combined with our low base decline rate of approximately 21% and our extensive unbooked drilling inventory, underpins our ability to sustainably grow production per share and generate significant free funds flow for our shareholders.

2021 RESERVES REVIEW

Our 2021 year end reserves were evaluated by independent reserves evaluator McDaniel & Associates Consultants Ltd. ("McDaniel") in accordance with the definitions, standards and procedures contained in the Canadian Oil and Gas Evaluation Handbook ("COGE Handbook") and National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities ("NI 51-101") as of December 31, 2021. The reserves evaluation was based on the average forecast pricing of McDaniel, GLJ Ltd. and Sproule Associates Limited and foreign exchange rates at January 1, 2022 which is available on McDaniel's website at www.mcdan.com.

Reserves included are Company share reserves which are the Company's total working interest reserves before the deduction of any royalties and including any royalty interests payable to the Company. Reserves related to the Central Alberta acquisition that closed subsequent to year end on January 10, 2022 are not included. Additional reserve information as required under NI 51-101 will be included in our Annual Information Form which will be filed on SEDAR on or before March 30, 2022. The numbers in the tables below may not add due to rounding.

Summary of Reserves

Reserves as at December 31, 2021


Company Share Reserves

Description

Light & Medium Oil
(Mbbl)

Tight Crude Oil
(Mbbl)

Conventional

Natural Gas (MMcf)

Proved developed producing

222,980

294

344,425

Proved developed non-producing

3,676

-

4,194

Proved undeveloped

115,735

10,197

148,408

Total proved

342,392

10,490

497,027

Probable

124,403

8,796

204,802

Total proved plus probable

466,796

19,286

701,829

 

Description

Shale Gas (MMcf)

Natural Gas Liquids
(Mbbl)

Total (Mboe)

Proved developed producing

60,039

29,607

320,291

Proved developed non-producing

18,377

2,022

9,460

Proved undeveloped

218,424

29,107

216,178

Total proved

296,840

60,736

545,930

Probable

159,771

29,219

223,180

Total proved plus probable

456,611

89,955

769,110

Net Present Values of Future Net Revenue

Summary of Before Tax Net Present Values of Future Net Revenue (Forecast Pricing)
As at December 31, 2021


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


Discount Rate

Description

0%

5%

10%

15%

20%

Proved developed producing


6,506


5,639


4,686


4,011


3,532

Proved developed non-producing


269


212


176


151


132

Proved undeveloped


4,436


2,804


1,877


1,308


937

Total proved


11,210


8,655


6,738


5,469


4,601

Probable


7,850


4,291


2,796


2,011


1,540

Total proved plus probable


19,061


12,946


9,534


7,481


6,141



(1) 

Includes abandonment and reclamation costs as defined in NI 51-101 for all of our facilities, pipelines and wells including those without reserves assigned.

Future Development Costs ("FDC")

FDC reflects the best estimate of the capital cost to develop and produce reserves. FDC associated with our TPP reserves at year end 2021 is $5.2 billion undiscounted ($3.5 billion discounted at 10%).

Also included in FDC are 1,638 (1,333.2 net) proved booked drilling locations and 286 (226.7 net) probable booked drilling locations.

($000s)

Total Proved

Total Proved plus Probable

2022

518,189

544,431

2023

741,541

816,133

2024

776,803

888,002

2025

723,784

842,550

2026

628,885

787,562

Remainder

931,497

1,286,778

Total FDC, Undiscounted

4,320,698

5,165,458

Total FDC, Discounted at 10%

2,973,759

3,522,275

Performance Measures (Including FDC)

The following table highlights F&D and FD&A costs and associated recycle ratios, including FDC, based on the evaluation of our petroleum and natural gas reserves prepared by McDaniel:


2021

2020

2019

Three Year

Weighted

Average

Proved Developed Producing





F&D costs (1)

$16.28

$21.87

$14.33

$17.31

F&D recycle ratio (2)

1.8x

0.9x

2.1x

1.6x

FD&A costs (3)

$14.95

$19.25

$14.45

$16.03

FD&A recycle ratio (2)

2.0x

1.1x

2.1x

1.8x

Total Proved





F&D costs (1)

$5.05

$3.61

$17.87

$8.29

F&D recycle ratio (2)

5.9x

5.7x

1.7x

4.6x

FD&A costs (3)

$13.67

$14.74

$17.95

$15.19

FD&A recycle ratio (2)

2.2x

1.4x

1.7x

1.8x

Total Proved Plus Probable





F&D costs (1)

$4.63

$19.16

$21.00

$13.42

F&D recycle ratio (2)

6.4x

1.1x

1.4x

3.5x

FD&A costs (3)

$11.22

$12.51

$21.06

$14.39

FD&A recycle ratio (2)

2.7x

1.7x

1.4x

2.0x



(1) 

F&D costs are calculated as the sum of development capital of $413.8 million (excluding corporate and capitalized G&A) plus the change in FDC for the period of -$58.7 million (PDP), -$298.3 million (TP) and -$317.1 million (TPP), divided by the change in reserves volumes that are characterized as development for the period.

(2) 

Recycle ratio is calculated as operating netback divided by F&D or FD&A costs. Our estimated operating netback1 in 2021 is $29.80/boe.

(3) 

FD&A costs are calculated as the sum of development capital of $413.8 million (excluding corporate and capitalized G&A) plus acquisition capital of $1,888 million plus the change in FDC for the period of -$19.2 million (PDP), $756.2 million (TP) and $1,095.6 million (TPP), divided by the change in total reserves volumes, other than from production, for the period.

Production Replacement Ratio and Reserve Life Index

The following table highlights our production replacement ratio and reserve life index ("RLI") based on the evaluation of our petroleum and natural gas reserves prepared by McDaniel:


2021

2020

2019

Three Year

Weighted

Average

Proved Developed Producing





Production replacement (1)

372%

34%

100%

199%

RLI (years) (2)

7.3

9.0

8.3

8.1

Total Proved





Production replacement (1)

545%

101%

133%

302%

RLI (years) (2)

12.5

15.6

13.3

13.6

Total Proved Plus Probable





Production replacement (1)

737%

100%

169%

394%

RLI (years) (2)

17.6

21.8

18.6

19.1



(1) 

Production replacement ratio is calculated as total reserve additions (including acquisitions net of dispositions) divided by annual production. Whitecap's production averaged 112,222 boe/d in 2021.

(2) 

RLI is calculated as total Company share reserves divided by the annualized fourth quarter actual production of 120,020 boe/d.

1 Non-GAAP financial measure. See "Specified Financial Measures".

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. In particular, and without limiting the generality of the foregoing, this press release contains forward-looking information with respect to: the continued outperformance on our base assets; the quality of our drilling inventory; our drilling inventory providing years of highly profitable sustainable growth and free funds flow; our reserve life index calculations, including as a percentage of our total internally identified reserve potential; our belief that our acquisition strategy has provided production replacement at very attractive FD&A metrics increasing the profitability of our business; our increased recycle ratios have meaningfully increased the long-term sustainability of our business; our RLI calculations , our low decline rate and our extensive unbooked drilling inventory reflect our ability to sustainably grow production per share and generate significant free funds flow for our shareholders; the future value of our reserves; our future abandonment and reclamation costs; and our future development costs. Statements relating to "reserves" are also deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated and that the reserves can be profitably produced in the future.

The forward-looking information is based on certain key expectations and assumptions made by our management, including expectations and assumptions concerning prevailing commodity prices, exchange rates, interest rates, applicable royalty rates and tax laws; 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, supplies 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 and 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, including the Central Alberta acquisition; ability to market oil and natural gas successfully; and our ability to access capital and the cost and terms thereof.

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, including the Central Alberta acquisition; ability to access sufficient capital from internal and external sources on acceptable terms or at all; 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, 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.

OIL AND GAS ADVISORIES

All reserve references in this press release are "Company share reserves". Company share reserves are our total working interest reserves before the deduction of any royalties and including any royalty interests payable to the company.

It should not be assumed that the present worth of estimated future amounts presented in the tables above represents the fair market value of the reserves. There is no assurance that the forecast prices and costs assumptions will be attained, and variances could be material. The recovery and reserve estimates of the crude oil, natural gas liquids and natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual crude oil, natural gas and natural gas liquids reserves may be greater than or less than the estimates provided herein.

References to petroleum, crude oil and natural gas in this press release refer to the light and medium crude oil, tight crude oil, conventional natural gas, shale gas and natural gas liquids product types, as applicable, as defined in NI 51-101.

"Boe" means barrel of oil equivalent. All boe conversions in this press release are derived by converting gas to oil at the ratio of six thousand cubic feet ("Mcf") of natural gas to one barrel ("Bbl") of oil. Boe may be misleading, particularly if used in isolation. A Boe conversion rate of 1 Bbl : 6 Mcf is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio of oil compared to natural gas based on currently prevailing prices is significantly different than the energy equivalency ratio of 1 Bbl : 6 Mcf, utilizing a conversion ratio of 1 Bbl : 6 Mcf may be misleading as an indication of value.

This press release contains metrics commonly used in the oil and natural gas industry which have been prepared by management, such as "acquisition capital", "development capital", "F&D costs", "FD&A costs", "operating netback", "production replacement", "production replacement ratio", "recycle ratio", and "reserve life index". These terms do not have a standardized meaning and may not be comparable to similar measures presented by other companies, and therefore should not be used to make such comparisons.

"Acquisition capital" includes net property acquisitions less any non-cash amounts and the announced purchase price of corporate acquisitions including any estimated working capital deficit or surplus rather than the amounts allocated to property, plant and equipment for accounting purposes and the aggregate exploration and development capital spending within the year on reserves that are categorized as acquisitions less the disposition of certain processing facilities. 

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

"F&D costs" are calculated as the sum of development capital (excluding corporate and capitalized general and administrative expense) plus the change in FDC for the period when appropriate, divided by the change in reserves that are characterized as development for the period.

"FD&A costs" are calculated as the sum of development capital (excluding corporate and capitalized general and administrative expense) plus acquisition capital plus the change in FDC for the period when appropriate, divided by the change in total reserves, other than from production, for the period.

"Operating netback" is a non-GAAP financial measure.  See "Specified Financial Measures".

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

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

"Reserve life index" or "RLI" is calculated as total Company share reserves divided by annualized fourth quarter actual production.

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.

Drilling Locations & Internally Estimated Reserve Potential

This press release discloses drilling inventory in two categories: (i) proved locations; and (ii) probable locations. Proved and probable locations are derived from McDaniel's reserves evaluation effective December 31, 2021 and account for drilling locations that have associated proved and/or probable reserves, as applicable.

This press release also discloses internally estimated reserves potential, which is the summation of proved plus probable reserves per the McDaniel's reserve evaluation effective December 31, 2021 plus an internal estimate prepared by members of Whitecap's management team who are qualified reserve evaluators and is based on our technical assessment of the resource in place on our acreage and the potential recoverable portion of this resource using industry standard evaluation methods for determining the spacing and number of wells required to obtain this recovery.

Internally estimated reserves potential consists of drilling locations that 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 of these 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.

Production & Product Type Information

This press release includes references to petroleum, crude oil, NGLs, natural gas and total average daily production.

NI 51-101 includes condensate within the natural gas liquids ("NGLs") product type. The Company has disclosed condensate as combined with crude oil and separately from other natural gas liquids since the price of condensate as compared to other natural gas liquids is currently significantly higher and the Company believes that this crude oil and condensate presentation provides a more accurate description of its operations and results therefrom. Crude oil therefore refers to light, medium, tight oil and condensate. NGLs refers to ethane, propane, butane and pentane combined. Natural gas refers to conventional natural gas and shale gas combined.

The Company's average production for the quarter and year ended December 31, 2021 disclosed in this press release consist of the following product types, as defined in NI 51-101 and using a conversion ratio of 1 Bbl : 6 Mcf where applicable:


2021

Q4/21

Light and medium oil (bbls/d)

74,863

78,814

Tight oil (bbls/d)

524

501

Crude oil (bbls/d)

75,387

79,315




NGLs (bbls/d)

10,418

10,568




Shale gas (Mcf/d)

20,402

42,993

Conventional natural gas (Mcf/d)

138,099

137,827

Natural gas (Mcf/d)

158,501

180,820




Total (boe/d)

112,222

120,020

SPECIFIED FINANCIAL MEASURES

This press release includes various specified financial measures, including non-GAAP financial measures and non-GAAP ratios as further described herein. These 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.

 "Acquisition Capital", "Development Capital", "F&D Costs", "FD&A Costs" are non-GAAP financial measures. See "Oil and Gas Advisories".

"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.

The following table sets forth a reconciliation of petroleum and natural gas revenues to operating netback on a per boe basis (all figures unaudited):

($/boe)


Petroleum and natural gas revenues

61.59

Tariffs

(0.45)

Processing income

0.70

Realized hedging losses

(5.94)

Royalties

(10.15)

Operating expenses

(13.70)

Transportation expenses

(2.25)

Operating netback

29.80

"Recycle Ratio" is a non-GAAP financial ratio. See "Oil and Gas Advisories".

Unaudited Financial Information

Certain financial and operating information included in this press release for the year ended December 31, 2021 including, without limitation, development capital, acquisition capital, finding and development costs, finding, development and acquisition costs, recycle ratio and operating netbacks, are based on estimated unaudited financial results for the year then ended, and are subject to the same limitations as discussed under Note Regarding Forward Looking Statements set out in this press release. These estimated amounts may change upon the completion of audited financial statements for the year ended December 31, 2021 and changes could be material.

Per Share Amounts

Per share amounts noted in this press release are based on 623.9 million fully diluted shares outstanding as at December 31, 2021.

SOURCE Whitecap Resources Inc.

Copyright 2022 Canada NewsWire

Whitecap Resources (TSX:WCP)
Graphique Historique de l'Action
De Juil 2022 à Août 2022 Plus de graphiques de la Bourse Whitecap Resources
Whitecap Resources (TSX:WCP)
Graphique Historique de l'Action
De Août 2021 à Août 2022 Plus de graphiques de la Bourse Whitecap Resources