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.