CALGARY, AB, Feb. 10, 2022 /CNW/ - Bonterra Energy Corp.
(www.bonterraenergy.com) (TSX: BNE) ("Bonterra" or the "Company")
is pleased to announce the summary results of its independent
reserve report (the "Sproule Report") prepared by Sproule
Associates Limited ("Sproule") with an effective date of
December 31, 2021, while also
providing an operational update on key fourth quarter highlights
and recent activities. The Company has not released its audited
2021 financial results, and therefore the financial figures
provided herein are estimates and are unaudited.
The Sproule Report was prepared 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"). Additional reserves information as
required under NI 51-101 will be included in the Company's Annual
Information Form which is expected to be filed on or about
March 9th on SEDAR and
posted to Bonterra's website.
2021 CORPORATE OPERATIONS & RESERVES INFORMATION
- Averaged approximately 12,747 BOE per day1 of
production in 2021, representing a 21 percent increase over 2020
and in-line with the stated guidance range of 12,800 to 13,200 BOE
per day. Volumes in the fourth quarter of 2021 are expected to
average approximately 13,810 BOE per day2, an increase
of 37 percent compared to the fourth quarter of 2020.
- Invested capital of approximately $67.3
million3 during 2021, with $17.6 million invested in the fourth quarter of
2021.
- The Company's 2021 capital program contributed to reserves
growth of approximately four percent for both total proved ("TP")
and total proved plus probable ("TPP") reserves.
- In 2021, proved developed producing reserves ("PDP") totaled
32.5 million BOE (65 percent oil and liquids), TP reserves totaled
78.2 million BOE (64 percent oil and liquids), and TPP reserves
totaled 97.4 million BOE (65 percent oil and liquids), while growth
before production of 7,565 thousand BOE in the TP category resulted
in production replacement of 163 percent.
- TP per fully diluted share4 totaled 2.25 BOE in 2021
while TPP per fully diluted share4 was 2.80 BOE.
- TP represented 80 percent of total TPP in 2021, consistent with
80 percent in 2020, exemplifying the low-risk nature of Bonterra's
asset base.
- Net present value of future net revenue discounted at 10
percent (before tax) ("NPV10 BT") for TPP totaled $1.3 billion, while TP totaled $986.4 million and PDP totaled $542.9 million.
- Reserve Life Index ("RLI")5 for TPP, TP, and PDP was
approximately 20.9 years, 16.8 years and seven years, respectively
(based on 2021 average production of 12,747 BOE per day).
__________________________________
|
1 2021 volumes comprised of 7,204
bbl/d light and medium crude oil, 1,013 bbl/d NGLs and 27,176 mcf/d
of conventional natural gas.
|
2 Q4
2021 volumes comprised of 7,659 bbl/d light and medium crude oil,
1,105 bbl/d NGLs and 30,276 mcf/d of conventional natural
gas.
|
3 All
2021 financial amounts are unaudited. See advisories.
|
4 Based on fully diluted common
shares outstanding of 34,761,175.
|
5 "Reserve life index" does not have
a standardized meaning. See "Information Regarding Disclosure on
Oil and Gas Reserves and Operational Information" contained in this
news release.
|
Summary of Gross Oil and Gas Reserves as of December 31, 2021
|
Light and
Medium
Crude Oil
|
Conventional
Natural Gas4
|
Natural Gas
Liquids
|
Oil
equivalent5
|
Future
Development
Capital
|
|
(MBbl)
|
(MMcf)
|
(MBbl)
|
(MBoe)
|
($000s)
|
Proved
|
|
|
|
|
|
Developed
Producing
|
18,522
|
67,490
|
2,725
|
32,495
|
-
|
Developed
Non-producing
|
2,335
|
5,990
|
229
|
3,562
|
6,793
|
Undeveloped
|
22,613
|
93,315
|
4,008
|
42,174
|
547,379
|
Total
Proved
|
43,470
|
166,795
|
6,962
|
78,231
|
554,171
|
Total
Probable
|
10,760
|
40,478
|
1,694
|
19,200
|
-
|
Total Proved plus
Probable 1,2,3
|
54,231
|
207,273
|
8,655
|
97,431
|
554,171
|
|
Notes for table
above:
|
(1)
|
Reserves have been
presented on gross basis which are the Company's total working
interest share before the deduction of any royalties and without
including any royalty interests of the Company.
|
(2)
|
Totals may not add
due to rounding.
|
(3)
|
Based on Sproule's
December 31, 2021 industry average price deck.
|
(4)
|
Conventional
natural gas amounts shown include solution gas.
|
(5)
|
Oil equivalent
amounts have been calculated using a conversion rate of six
thousand cubic feet of natural gas to one barrel of
oil.
|
Reconciliation of Company Gross Reserves by Principal Product
Type as of December 31, 2021
1,2
|
Light &
Medium
Crude Oil
|
Conventional
Natural Gas5
|
Natural Gas
Liquids
|
Oil
Equivalent
|
|
Total
Proved
|
Proved
+ Probable
|
Total
Proved
|
Proved
+ Probable
|
Total
Proved
|
Proved +
Probable
|
Total
Proved
|
Proved
+ Probable
|
|
(MBbl)
|
(MBbl)
|
(MMcf)
|
(MMcf)
|
(MBbl)
|
(MBbl)
|
(MBoe)
|
(MBoe)
|
Opening
Balance,
December 31, 2020
|
43,067
|
53,729
|
150,476
|
187,462
|
7,172
|
8,938
|
75,319
|
93,910
|
Extensions &
Improved Recovery 2
|
3,856
|
4,823
|
15,621
|
19,510
|
731
|
914
|
7,191
|
8,989
|
Technical
Revisions
|
(2,858)
|
(3,833)
|
3,945
|
3,736
|
(848)
|
(1,100)
|
(3,048)
|
(4,310)
|
Discoveries
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
Acquisitions
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
Dispositions
3
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
Economic
Factors
|
2,034
|
2,141
|
6,673
|
6,484
|
276
|
273
|
3,423
|
3,495
|
Production
|
(2,630)
|
(2,630)
|
(9,919)
|
(9,919)
|
(370)
|
(370)
|
(4,653)
|
(4,653)
|
Closing
Balance,
December 31, 20214
|
43,470
|
54,231
|
166,795
|
207,273
|
6,962
|
8,655
|
78,231
|
97,431
|
|
Notes for table
above:
|
(1)
|
Gross Reserves
means the Company's working interest reserves before calculation of
royalties, and before consideration of the Company's royalty
interests.
|
(2)
|
Increases to
Extensions & Improved Recovery include infill drilling and are
the result of step-out locations drilled by Bonterra and other
operators on and near Company-owned lands.
|
(3)
|
Includes volumes
associated with Farm outs.
|
(4)
|
Totals may not add
due to rounding.
|
(5)
|
Conventional
natural gas amounts shown include solution gas.
|
Summary of Net Present Values of Future Net Revenue as of
December 31, 2021
|
|
($M)
|
Net Present
Value Before Income Taxes Discounted at (% per Year)
|
Reserves
Category:
|
0%
|
5%
|
10%
|
15%
|
Proved
|
|
|
|
|
Producing
|
742,567
|
651,462
|
542,915
|
463,927
|
Non-producing
|
102,439
|
71,406
|
55,012
|
45,066
|
Undeveloped
|
941,525
|
583,748
|
388,505
|
272,631
|
Total
Proved
|
1,786,531
|
1,306,616
|
986,432
|
781,625
|
Probable
|
678,326
|
404,334
|
279,419
|
212,060
|
Total Proved plus
Probable 1,2,3
|
2,464,857
|
1,710,950
|
1,265,851
|
993,685
|
|
Notes for table
above:
|
(1)
|
Evaluated by
Sproule as at December 31, 2021. Net present value of future net
revenue does not represent fair value of the
reserves.
|
(2)
|
Net present values
equal net present value before income taxes based on Sproule's
forecasted costs and industry average prices as of December 31,
2021. There is no assurance that the forecast prices and costs
assumptions will be attained and variances could be
material.
|
(3)
|
Includes
abandonment and reclamation costs as defined in NI
51-101.
|
FUTURE DEVELOPMENT CAPITAL, F&D COSTS6 AND
RECYCLE RATIOS6
Future development capital ("FDC") reflects the future capital
costs, as provided by the Company and included in the Sproule
Report, to bring Bonterra's proved and probable developed and
undeveloped reserves on production. Changes in forecasted FDC occur
annually as a result of development activities, acquisition and
disposition activities, changes in capital cost estimates based on
improvements in well design and performance, and changes in service
costs.
Over the past three years, Bonterra has incurred the following
finding, development and acquisition ("FD&A")6 and
finding and development ("F&D")6 costs both
excluding and including FDC:
|
TP Reserves Net
Additions
|
|
TPP Reserves Net
Additions
|
|
2021
|
2020
|
2019
|
3 Yr
Avg4
|
|
2021
|
2020
|
2019
|
3 Yr
Avg4
|
FD&A Costs per
BOE 1,2,3,6
|
|
|
|
|
|
|
|
|
|
Including
FDC
|
$6.90
|
$12.46
|
$14.32
|
$9.44
|
|
$5.64
|
$9.87
|
$18.24
|
$10.06
|
Excluding
FDC
|
$8.68
|
$(18.21)
|
$9.94
|
$15.27
|
|
$8.23
|
$(13.26)
|
$12.35
|
$17.86
|
F&D Costs per
BOE 1,2,3,6
|
|
|
|
|
|
|
|
|
|
Including
FDC
|
$6.90
|
$12.46
|
$14.32
|
$9.44
|
|
$5.64
|
$9.87
|
$18.24
|
$10.06
|
Excluding
FDC
|
$8.68
|
$(18.21)
|
$9.94
|
$15.27
|
|
$8.23
|
$(13.26)
|
$12.35
|
$17.86
|
|
|
|
|
|
|
|
|
|
|
Recycle Ratio
2,5,6
|
|
|
|
|
|
|
|
|
|
F&D (including
FDC)
|
4.3
|
1.2
|
1.8
|
2.5
|
|
5.3
|
1.5
|
1.5
|
2.8
|
|
Notes for table
above:
|
(1)
|
Barrels of oil
equivalent 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.
|
(2)
|
The aggregate of
the exploration and development costs incurred in the most recent
financial year and the change during that year in estimated future
development capital generally will not reflect total finding and
development costs related to reserve additions for that
year.
|
(3)
|
The calculation of
F&D and FD&A costs both includes or excludes, as labelled,
the change in FDC required to bring proved undeveloped and
developed reserves into production. The F&D or FD&A
number is calculated by dividing the identified capital
expenditures by applicable reserve additions including extensions,
infills. Revisions, acquisitions and disposals, and economic
factors, after or before changes in FDC costs (as
labelled).
|
(4)
|
Three-year average
is calculated using three-year total capital costs and reserve
additions on both a TP and TPP reserves on a weighted average
basis.
|
(5)
|
Recycle ratio is
defined as field netback per BOE divided by F&D costs on a per
boe basis. Field netback is a Non-IFRS Measure and
calculated as revenue minus royalties, operating expenses and
realized gain or loss on risk management contracts.
Bonterra's field netback in 2021, used in the above calculations,
averaged $29.62 per BOE (unaudited).
|
(6)
|
"FD&A Cost",
"F&D Cost", and "Recycle Ratio" do not have standardized
meanings and therefore may not be comparable with the calculation
of similar measures for other entities. See "Information
Regarding Disclosure on Oil and Gas Reserves and Operational
Information" in this news release.
|
OPERATIONAL UPDATE6
During the last quarter of 2021, Bonterra invested a total of
$17.6 million, taking advantage of
stronger commodity prices and successfully brought six gross
operated (6.0 net) new wells onto production into a more robust
price environment, further supporting its objective of increasing
Funds Flow. Bonterra has continued to be active executing its 2022
capital program budgeted at $55 to
$65 million, and in the first six
weeks of 2022 have drilled six gross operated (5.8 net) wells,
completed 11 gross operated (10.8 net) wells and brought on
production six gross operated (6.0 net) wells which were previously
drilled in 2021.
As part of its ongoing field operations, the Company has
continued to focus on responsible environmental initiatives,
including a targeted abandonment and reclamation program.
Throughout 2021, Bonterra successfully abandoned 221 wells, and
plans to abandon an additional 120 wells in 2022 based on
expenditures between $4 million and
$5 million, supported by the Alberta
Site Rehabilitation Program. By the end of 2022, this abandonment
and reclamation activity will represent approximately 60 percent of
all wells that have no further potential identified.
Bonterra is pleased to reiterate its previously released 2022
guidance:
- Capital expenditure budget ranging from $55 to $65 million,
allocated approximately 75 percent to drilling and completing new
Cardium wells in Pembina and Willesden Green, with the balance
directed to facilities, pipelines and a continued commitment to
ongoing abandonment and reclamation activities;
- 2022 production volumes are expected to average between 13,300
and 13,700 BOE per day7, driving year-over-year
production growth of approximately five percent; and
- Based on pricing (assuming US$70
WTI) and production assumptions for 2022, outlined fully in the
Company's December 16, 2021 press
release, Bonterra anticipates generating approximately $150 million in corporate Funds Flow8
for the year, resulting in meaningful Free Funds Flow (defined as
Funds Flow net of development capital and decommissioning
expenditures settled) of approximately $90
million8, which is expected to drive a 33 percent
reduction in forecasted year end 2022 net debt.
Certain financial and operating information, such as production
information, and F&D costs included in this press release are
based on estimated unaudited financial results for the quarter and
year ended December 31, 2021 and are
subject to the same limitations as discussed under Forward Looking
Statements set out below. These estimated amounts may change upon
the completion of audited financial statements for the year ended
December 31, 2021 and changes could
be material.
__________________________________
|
6 All
2021 financial amounts are unaudited. See advisories.
|
7 2022 volumes are anticipated to be
comprised of 7,320 bbl/d light and medium crude oil, 1,320 bbl/d
NGLs and 29,200 mcf/d of conventional natural gas based on a
midpoint of 13,500 BOE/d.
|
8 Funds Flow is estimated using a
Canadian realized oil price of $79.66/bbl, a realized natural gas
price of $3.96/mcf; and a realized NGL price of CAD
$45.92/bbl.
|
Cautionary Statements
This summarized news release should not be considered a suitable
source of information for readers who are unfamiliar with Bonterra
Energy Corp. and should not be considered in any way as a
substitute for reading the full report. For the full report, please
go to www.bonterraenergy.com.
Use of Non-IFRS Financial Measures
Throughout this release the Company uses the terms "funds flow",
"free funds flow", "net debt" and "field netback" to analyze
operating performance, which are not standardized measures
recognized under IFRS and do not have a standardized meaning
prescribed by IFRS. These measures are commonly utilized in the oil
and gas industry and are considered informative by management,
shareholders and analysts. These measures may differ from those
made by other companies and accordingly may not be comparable to
such measures as reported by other companies.
The Company defines funds flow as funds provided by operations
excluding effects of changes in non-cash working capital items and
commissioning expenditures settled. Free funds flow is defined as
funds flow less dividends paid to shareholders, capital and
decommissioning expenditures settled. Net debt is defined as
current liabilities less current assets plus long-term subordinated
debt and subordinated debentures. Field netback is defined as
revenue minus royalties, operating expenses and realized gain or
loss on risk management contracts.
Information Regarding Disclosure on Oil and Gas Reserves and
Operational Information
All amounts in this news release are stated in Canadian dollars
unless otherwise specified. Bonterra's oil and gas reserves
statement for the year ended December 31,
2021, which will include complete disclosure of its oil and
gas reserves and other oil and gas information in accordance with
NI 51-101, will be contained within its Annual Information Form
which will be available on Bonterra's SEDAR profile at
www.sedar.com or on the Company's website on or before March 30, 2022. The recovery and reserve
estimates contained herein are estimates only and there is no
guarantee that the estimated reserves will be recovered. In
relation to the disclosure of estimates for individual properties
or subsets thereof, such estimates may not reflect the same
confidence level as estimates of reserves and future net revenue
for all properties, due to the effects of aggregation. The
Company's belief that it will establish additional reserves over
time with conversion of probable undeveloped reserves into proved
reserves is a forward-looking statement and is based on certain
assumptions and is subject to certain risks, as discussed below
under the heading "Forward-Looking Information and Statements".
This press release contains metrics commonly used in the oil and
natural gas industry, such as "reserve life index", "recycle
ratio", "finding and development costs", "finding and development
recycle ratio", "finding, development and acquisition costs", and
"field netbacks". Each of these metrics are determined by Bonterra
as specifically set forth in this news release. These terms do
not have standardized meanings or standardized methods of
calculation and therefore may not be comparable to similar measures
presented by other companies, and therefore should not be used to
make such comparisons. Such metrics have been included to provide
readers with additional information to evaluate the Company's
performance however, such metrics should not be unduly relied upon
for investment or other purposes. Management uses these metrics for
its own performance measurements and to provide readers with
measures to compare Bonterra's performance over time.
Both F&D and FD&A costs take into account reserves
revisions during the year on a per boe basis. The aggregate of
the costs incurred in the financial year and changes during that
year in estimated FDC may not reflect total F&D costs related
to reserves additions for that year. Finding and development
costs both including and excluding acquisitions and dispositions
have been presented in this press release because acquisitions and
dispositions can have a significant impact on Bonterra's ongoing
reserves replacement costs and excluding these amounts could result
in an inaccurate portrayal of its cost structure.
Management uses these oil and gas metrics for its own
performance measurements and to provide shareholders with measures
to compare Bonterra's performance over time, however, such measures
are not reliable indicators of the Company's future performance and
future performance may not compare to the performance in previous
periods. 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.
Forward Looking Information
Certain statements contained in this release include statements
which contain words such as "anticipate", "could", "should",
"expect", "seek", "may", "intend", "likely", "will", "believe" and
similar expressions, relating to matters that are not historical
facts, and such statements of our beliefs, intentions and
expectations about development, results and events which will or
may occur in the future, constitute "forward-looking information"
within the meaning of applicable Canadian securities legislation
and are based on certain assumptions and analysis made by us
derived from our experience and perceptions. Forward-looking
information in this release includes, but is not limited to:
expected cash provided by continuing operations; future asset
retirement obligations; future capital expenditures, including the
amount and nature thereof; oil and natural gas prices and demand;
expansion and other development trends of the oil and gas industry;
business strategy and outlook; expansion and growth of our business
and operations; and maintenance of existing customer, supplier and
partner relationships; supply channels; accounting policies; credit
risks; the impact of the COVID-19 pandemic; and other such
matters.
All such forward-looking information is based on certain
assumptions and analyses made by us in light of our experience and
perception of historical trends, current conditions and expected
future developments, as well as other factors we believe are
appropriate in the circumstances. The risks, uncertainties, and
assumptions are difficult to predict and may affect operations, and
may include, without limitation: foreign exchange fluctuations;
equipment and labour shortages and inflationary costs; general
economic conditions; industry conditions; changes in applicable
environmental, taxation and other laws and regulations as well as
how such laws and regulations are interpreted and enforced; the
ability of oil and natural gas companies to raise capital or
maintain its syndicated bank facility; the effect of weather
conditions on operations and facilities; the existence of operating
risks; volatility of oil and natural gas prices; oil and gas
product supply and demand; risks inherent in the ability to
generate sufficient cash flow from operations to meet current and
future obligations; increased competition; stock market volatility;
opportunities available to or pursued by us; and other factors,
many of which are beyond our control.
Actual results, performance or achievements could differ
materially from those expressed in, or implied by, this
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, what
benefits will be derived there from. Except as required by law,
Bonterra disclaims any intention or obligation to update or revise
any forward-looking information, whether as a result of new
information, future events or otherwise.
The forward-looking information contained herein is expressly
qualified by this cautionary statement.
Frequently recurring terms
Bonterra uses the following frequently recurring terms in this
press release: "WTI" refers to West Texas Intermediate, a grade of
light sweet crude oil used as benchmark pricing in the United States; "MSW Stream Index" or
"Edmonton Par" refers to the mixed sweet blend that is the
benchmark price for conventionally produced light sweet crude oil
in Western Canada; "AECO" is the
benchmark price for natural gas in Alberta, Canada; "bbl" refers to barrel; "NGL"
refers to Natural gas liquids; "MCF" refers to thousand cubic feet;
"MMBTU" refers to million British Thermal Units; "GJ" refers to
gigajoule; and "BOE" refers to barrels of oil equivalent.
Disclosure provided herein in respect of a BOE may be misleading,
particularly if used in isolation. A BOE conversion ratio of 6 MCF:
1 bbl is based on an energy conversion method primarily applicable
at the burner tip and does not represent a value equivalency at the
wellhead.
Numerical Amounts
The reporting and the functional currency of the Company is
the Canadian dollar.
The TSX does not accept responsibility for the
accuracy of this release.
SOURCE Bonterra Energy Corp.