2024
Annual Report
Bonterra Energy Corp.
December 31, 2024
2 | Page
ABOUT BONTERRA
Bonterra Energy Corp. is a conventional oil and gas corporation
forging a grounded path forward for Canadian energy.
Operations include a large, concentrated land position in
Alberta’s Pembina Cardium, one of Canada’s largest oil plays.
Bonterra’s liquids-weighted Cardium production provides a
foundation for implementing a return of capital strategy over
time, which is focused on generating long-term, sustainable
growth and value creation for shareholders.
Emerging Charlie Lake and Montney resource plays are
expected to provide enhanced optionality and an expanded
potential development runway for the future. Our shares are
listed on the Toronto Stock Exchange under the symbol "BNE"
and we invite stakeholders to follow us on LinkedIn and X
(formerly Twitter) for ongoing updates and developments.
TABLE OF CONTENTS
About Bonterra
2
Report to Shareholders
3
Highlight Tables
7
Statistical Review
9
Management’s Discussion and Analysis
13
Financial Statements
34
Notes to Financial Statements
42
Corporate Information
IBC
CONTACT INFORMATION
HEAD OFFICE
Suite 901, 1015-4th Street SW
Calgary, AB T2R 1J4
T: (403) 262-5307
F: (403) 265-7488
OFFICERS
Patrick G. Oliver, President & CEO
Scott Johnston, CFO & Corporate Secretary
Brad A. Curtis, Senior VP, Business Development
3 | Page
REPORT TO SHAREHOLDERS
As we look back on the past year, I am proud to share the great progress and important
achievements that Bonterra Energy made in 2024. It was a transformative year that saw
us strategically reposition the Company for long-term growth and sustainability, while
navigating market volatility with discipline and resilience.
Transformative Pivot
In 2024, we executed on our refreshed corporate strategy, thereby reshaping our asset
portfolio to better align with our growth objectives. We successfully transitioned from a sole
focus on the Cardium to a more diversified approach, integrating high-impact, oil-weighted
plays in the Charlie Lake and Montney formations. These additions complement our low-
risk, high-netback legacy asset in the Cardium, enhancing our overall asset base and
positioning us for sustainable growth.
In March, we closed the Charlie Lake acquisition for $24.1 million, adding 79 net sections
to our existing 37 sections acquired through Crown land sales. This strategic move
significantly expanded our drilling inventory, ensuring a longer development runway and
enhancing our ability to generate high-margin production. The Charlie Lake acquisition
also provides significant development flexibility, enabling us to strategically allocate capital
to the most capital efficient projects.
We are particularly pleased with the early-stage drilling results from the Charlie Lake and
Montney plays, which exceeded expectations and validated our strategic pivot. The
Montney formation, known for its robust economics and prolific resource potential, offers
an exciting growth avenue that further diversifies our production base. Our team’s
operational excellence allowed us to deliver record production volumes in the fourth
quarter, contributing to an annual production of 14,846 BOEPD, exceeding our original
guidance. This operational success underscores our commitment to disciplined execution
and value creation.
Strength and Flexibility
We took significant steps to strengthen our financial position, ensuring the Company is
well-capitalized to execute its strategic initiatives. After year-end, we closed $135 million
of Senior Secured Second Lien 10.5% Notes, refinancing two tranches of junior debt. This
strategic refinancing fortified our balance sheet, providing enhanced liquidity and financial
flexibility supported by five years of committed debt capital. This long-term debt capital
structure not only enhances our financial stability but also allows us to pursue strategic
opportunities with confidence.
Our strong financial position enables us to pursue strategic acquisitions in our core
operating areas, further enhancing our scale, drilling inventory, and cost efficiencies. We
remain committed to maintaining a disciplined capital allocation strategy focused on
generating free funds flow to facilitate debt reduction and prepare for a return of capital to
4 | Page
shareholders through share buybacks and dividends. Our capital allocation framework is
designed to maximize shareholder value while maintaining financial flexibility to adapt to
changing market conditions.
2024 Financial and Operating Snapshot
Production averaged 14,846 BOE per day during the year, which exceeded the
midpoint of our original guidance range of 14,000 BOE per day;
We efficiently invested $101.1 million of capital in 2024, on guidance and a
significant reduction from $126.5 million in 2023;
Funds flow1 totaled $118.7 million ($3.18 per fully diluted share) in 2024;
Net earnings totaled $10.2 million ($0.27 per diluted share) in the year;
Net debt1 totaled $167.2 million at year-end 2024, of which $46,211 is bank debt;
Production costs of $16.54 per BOE in 2024 were three per cent higher than the
$16.02 per BOE in 2023; and
The Company invested $7.2 million in decommissioning liabilities for 2024,
exceeding its mandatory spend requirements under the Alberta Energy Regulator’s
Liability Management Program.
Operational Excellence in a Mid-Cycle Crude Oil Pricing Environment
Of the $101.1 million capital invested this year, $69.1 million was directed to the drilling of
20 gross (18.9 net) operated wells and completing, equipping, tying-in and placing on
production 24 gross (22.7 net) operated wells, of which four gross (3.6 net) were drilled in
Q4 of 2023. An additional $32.0 million was directed primarily to related infrastructure,
recompletions and drilling, completing, equipping and tying-in a water disposal well to
reduce water handling costs in the Montney area.
WTI prices averaged $70.27 USD per barrel in Q4 of 2024, reflecting a 10% decline
compared to Q4 2023. This decrease was driven by supply and demand volatility
influenced by various macroeconomic and geopolitical factors, including global supply
growth and OPEC+ signaling its intent to reintroduce supply to the market starting in Q2
of 2025.
Beyond the WTI benchmark, the Company’s realized crude oil price is affected by the
MSW Stream Index, or Edmonton Par differential. In Q4 2024, the differential averaged
($2.37) USD per barrel, tightening by $2.79 USD per barrel from Q4 2023. While the
Differential has improved year over year, near-term volatility is expected as the market
assesses the potential impact of tariffs on all grades of Canadian crude production.
On the natural gas side, AECO daily spot prices averaged $1.47 per mcf in Q4 2024, down
36% from Q4 2023. This decline was primarily due to a significant supply-demand
imbalance, leading to record storage levels and downward pressure on prices.
5 | Page
Team Strength
None of our achievements would have been possible without our highly skilled and
motivated team. Their commitment to operational excellence and strategic execution has
been instrumental in driving Bonterra’s success. We have strengthened our internal
technical team and are well-equipped to capitalize on the significant growth potential
offered by our expanded asset base. We continue to bolster our technical capabilities to
execute complex drilling programs efficiently and safely.
Our team’s depth of experience and industry knowledge is a key competitive advantage,
enabling us to navigate operational challenges and optimize production. We are proud of
our team’s adaptability and resilience, which have been crucial in executing our strategic
transformation.
Looking Ahead: 2025 and Beyond
We are excited about the opportunities that lie ahead and are focused on building on the
momentum achieved in 2024. Our priorities for 2025 include:
Executing a successful 6-well capital program in the Charlie Lake, leveraging the
early-stage drilling success achieved in 2024 and optimizing completion techniques
to maximize productivity and returns;
Generating significant free funds flow to facilitate debt reduction and setting the
stage for initiating a return of capital strategy; and
Pursuing strategic acquisitions within our core areas to enhance our scale, drilling
inventory, and cost synergies.
Bonterra is pleased to reiterate its previously announced 2025 annual guidance with
average production between 14,600 and 14,800 BOE per day based on a fully funded
2025 capital expenditure budget between $65 million to $75 million.
We are confident that our strategic transformation and strengthened financial position
provide a solid foundation for sustainable growth and shareholder value creation. We are
excited about the future and are committed to delivering on our strategic goals.
Closing Remarks
Reflecting on a successful 2024, I want to express my sincere gratitude to our
shareholders, employees, and partners for their continued trust and support. Our journey
of transformation and growth is just beginning, and we are more confident than ever in our
ability to navigate market dynamics and create long-term value for our shareholders. We
remain focused on disciplined execution, strategic capital allocation, and sustainable
growth to enhance shareholder value.
My personal thanks to our Board of Directors for their continued support and guidance and
shared commitment to excellence.
6 | Page
Thank you for your continued support and confidence in Bonterra Energy.
Sincerely,
Patrick Oliver
President & Chief Executive Officer
7 | Page
ANNUAL HIGHLIGHTS
FINANCIAL AND OPERATIONAL HIGHLIGHTS
(1) Funds flow, while not recognized under IFRS®, is used by management to assess the Company's ability to generate cash from
operations. For these purposes, the Company defines funds flow as funds provided by operations including proceeds from sale of
investments and investment income received excluding the effects of changes in non-cash working capital items and
decommissioning expenditures settled.
(2) On March 1, 2024, the Company acquired the Charlie Lake Assets for cash consideration of $23.6 million and $0.3 million in non-
core mineral rights, including closing adjustments. The Charlie Lake Assets has been accounted for as an asset acquisition, which
resulted in an increase of $24.2 million in PP&E and the assumption of $0.3 million in decommissioning liabilities.
(3) Net debt is not a recognized measure under IFRS. The Company defines net debt as current liabilities less current assets plus long-
term bank debt, subordinated debentures and subordinated term debt.
(4) 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.
As at and for the year ended
($000s except $ per share)
FINANCIAL
Revenue - realized oil and gas sales
279,957
319,517
384,197
Funds flow
(1)
118,668
147,305
185,583
Per share - basic
3.18
3.96
5.16
Per share - diluted
3.18
3.95
4.98
Cash flow from operations
114,952
140,183
183,553
Per share - basic
3.08
3.77
5.10
Per share - diluted
3.08
3.76
4.92
Net earnings
10,203
44,943
79,023
Per share - basic
0.27
1.21
2.20
Per share - diluted
0.27
1.20
2.12
Capital expenditures
101,076
126,478
79,769
Oil and gas property acquisition
(2)
24,234
- -
Total assets
975,043
967,870
919,682
Net debt
(3)
167,210
145,440
154,786
Bank debt
46,211
14,822
17,601
Shareholders' equity
540,639
528,258
479,839
OPERATIONS
Light oil
-bbl per day
6,639
7,209
7,095
-average price ($ per bbl)
94.35
97.58
113.93
NGLs
-bbl per day
1,513
1,359
1,141
-average price ($ per bbl)
46.97
48.80
66.00
Conventional natural gas -MCF per day
40,164
33,814
31,023
-average price ($ per MCF)
1.68
3.12
5.44
Total barrels of oil equivalent per day (BOE)
(4)
14,846
14,204
13,407
December 31,
2024
December 31,
2023
December 31,
2022
8 | Page
QUARTERLY HIGHLIGHTS
As at and for the periods ended
($ 000s except $ per share)
Q4
Q3
Q2
Q1
Financial
Revenue - oil and gas sales
69,699
69,204
72,465
68,589
Funds flow
30,100
30,066
31,484
27,018
Per share - basic
0.81
0.81
0.84
0.73
Per share - diluted
0.81
0.81
0.84
0.72
Cash flow from operations
28,587
31,531
33,180
21,654
Per share - basic and diluted
0.77
0.84
0.89
0.58
Net earnings (loss)
(2,213)
4,258
7,310
848
Per share - basic
(0.06)
0.11
0.20
0.02
Per share - diluted
(0.06)
0.11
0.20
0.02
Capital expenditures
22,438 24,095 21,619
32,924
Oil and gas property acquisition
- - - 24,234
Total assets
975,043
982,256
984,065
984,464
Bank debt
46,211
41,871
41,889
38,688
Net debt
167,210
168,278
172,622
181,400
Shareholders' equity
540,639
542,344
537,498
529,605
Operations
Light oil (barrels per day)
6,588
6,775
6,571
6,622
Average price ($ per bbl)
92.11
94.30
102.09
88.96
NGLs (barrels per day)
1,625
1,538
1,418
1,468
Average price ($ per bbl)
48.97
47.44
45.08
46.08
Conventional natural gas (MCF per day)
44,436
42,039
37,519
36,594
Average price ($ per MCF)
1.60
0.96
1.64
2.65
Total BOE per day
15,619
15,320
14,242
14,189
2024
9 | Page
STATISTICAL REVIEW
Summary of Gross Oil and Gas Reserves as of December 31, 2024
Reconciliation of Company Gross Reserves by Principle Product Type
as of December 31, 2024(1)
Light &
Medium
Crude Oil
Conventional
Natural Gas
Natural Gas
Liquids
Oil
equivalent(4)
Future
development
Capital
Reserves Category:
(Mbbl)
(MMCF)
(Mbbl)
(MBOE)
(000s)
PROVED
Developed Producing
16,218
88,641
3,394
34,386
-
Developed Non-Producing
2,144
7,254
280
3,633
5,801
Undeveloped
23,076
118,684
4,122
46,978
780,568
TOTAL PROVED
41,438
214,579
7,796
84,997
786,369
PROBABLE
10,286
53,211
1,919
21,073
5,082
TOTAL PROVED PLUS PROBABLE(1)(2)(3)
51,724
267,790
9,714
106,070
791,451
(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, 2024 escalated price deck.
(4) Oil equivalent amounts have been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of oil.
Total
Proved
(Mbbl)
Proved +
Probable
(Mbbl)
Total
Proved
(MMCF)
Proved +
Probable
(MMCF)
Total
Proved
(Mbbl)
Proved +
Probable
(Mbbl)
Total
Proved
(MBOE)
Proved +
Probable
(MBOE)
Opening Balance
December 31, 2023
42,205
53,155
184,761
231,737
7,142
8,969
80,141
100,747
Extensions & Improved Recovery(2)
1,719
2,164
25,077
31,625
685
863
6,584
8,298
Technical Revisions
(1,439) (2,798) 7,857 4,110 304 153 175 (1,955)
Acquisitions
1,237
1,594
12,458
16,120
249
322
3,563
4,603
Economic Factors
146 35 (873) (1,103) (32) (40) (32) (189)
Production
(2,430) (2,430) (14,700) (14,700) (554) (554) (5,434) (5,434)
Closing Balance,
December 31, 2024(3)
41,438
51,724
214,580
267,790
7,796
9,714
84,997
106,070
(3) Totals may not add due to rounding.
Light & Medium Crude
Oil
Conventional Natural
Gas(3)
Natural Gas
Liquids
Total
(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.
10 | Page
Summary of Net Present Values of Future Net Revenue
as of December 31, 2024
Finding, Development & Acquisition (FD&A) and
Finding & Development (F&D) Costs
($ 000s)
Net Present Value Before Income Taxes Discounted at (% per Year)
Reserves Category:
0%
5%
10%
15%
PROVED
Developed Producing
930,846
707,085
572,134
483,891
Developed Non-Producing
91,930
66,114
50,405
40,096
Undeveloped
995,773
617,634
403,117
273,456
TOTAL PROVED
2,018,549
1,390,833
1,025,656
797,443
PROBABLE
768,399
476,725
336,627
257,341
TOTAL PROVED + PROBABLE(1)(2)(3)(4)
2,786,948
1,867,558
1,362,283
1,054,784
(1) Evaluated by Sproule as at December 31, 2024. Net present value of future net revenue does not represent fair value of the
reserves.
(2) Net present values equals net present value before income taxes based on Sproule’s forecast prices and costs as of
December 31, 2024. There is no assurance that the forecast price and cost assumptions will be attained and variances could be
material.
(3) Includes abandonment and reclamation costs as defined in NI 51-101.
(4) Totals may not add due to rounding.
2024
2023
2022
3 Yr Avg(4)
2024
2023
2022
3 Yr Avg(4)
FD&A COSTS PER BOE (1)(2)(3)(5)
Including FDC
$17.33
$39.08
24.85
$
$25.31
$18.34
$34.16
$23.34
$23.55
Excluding FDC
$10.45
$27.09
$10.47
$14.67
$11.65
$23.24
$10.02
$13.72
F&D COSTS PER BOE (1)(2)(3)(5)
Including FDC
$18.90
$39.08
$24.85
$26.49
$20.99
$34.16
$23.34
$25.61
Excluding FDC
$14.89
$27.09
$10.47
$16.16
$16.42
$23.24
$10.02
$15.72
(3) The calculation of F&D and FD&A costs both includes or excludes, as labelled, the change in FDC required to bring proved undeveloped and
developed reserves into production. The F&D or FD&A number is calculated by dividing the identified capital expenditures by applicable reserve
additions including extensions, infills. Revisions, acquisitions and disposals, and economic factors, after or before changes in FDC costs (as labelled).
(4) Three year average is calculated using three year total capital costs and reserve additions on both a TP and TPP reserves on a weighted average
basis.
(5) "FD&A Cost", "F&D Cost", and "Recycled Ratio" do not have standardized meanings and therefore may not be comparable with the calculation of
similar measures for other entities. See "Information Regarding Disclosure on Oil and Gas Reserves and Operational information" in the Standout
2024 Reserves Report Highlighted by Increases Across all Reserves Categories news release.
Proved Reserves Net Additions
Proved + Probable Reserves Net Additions
(1) Barrels of Oil Equivalent may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 MCF: 1 bbl is based on an energy
equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
(2) The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated
future development costs generally will not reflect total finding and development costs related to reserve additions for that year.
11 | Page
Commodity Prices Used in the Above Calculations
of Reserves are as Follows
Production
Land Holdings
Year
Edmonton
Par Price
40° API
($Cdn per bbl)
Natural Gas
AECO-C Spot
($Cdn per
mmbtu)
NGL
Butanes
Edmonton
($Cdn per bbl)
NGL
Pentanes
Edmonton
($Cdn per bbl)
Operating Cost
Inflation Rate
(% per Year)
Exchange
Rate
($US/$Cdn)
FORECAST (1)(2)
2025
94.79
2.36
51.15
33.56
0.0
0.71
2026
97.04
3.33
49.99
32.78
0.7
0.73
2027
97.37
3.48
50.16
32.81
2.0
0.74
2028
99.80
3.69
51.41
33.63
2.0
0.74
2029
101.79
3.76
52.44
34.30
2.0
0.74
2030
103.93
3.83
53.49
34.99
2.0
0.74
2031
105.91
3.91
54.56
35.69
2.0
0.74
2032
108.03
3.99
55.65
36.40
2.0
0.74
2033
110.19
4.07
56.76
37.13
2.0
0.74
2034
112.39
4.15
57.90
37.87
2.0
0.74
(1) Crude oil, natural gas and liquid prices escalate at 2.0 percent thereafter.
(2) The forecast of product prices is an average of independent reserve evaluators Sproule, GLJ Petroleum and McDaniel
and Associates Consultants Ltd.
OIL & NGLS
(Bbl PER DAY)
CONVENTIONAL
NATURAL GAS
(MCF PER DAY)
TOTAL
(BOE PER DAY)
Alberta
8,086
40,016
14,755
Saskatchewan
62
26
66
British Columbia
4
123
25
Total
8,152
40,165
14,846
2024
Gross Acres
Net Acres
Gross Acres
Net Acres
Alberta
408,928 282,482 354,928 227,663
Saskatchewan
5,842 3,704 5,886 3,677
British Columbia
65,208 28,257 65,913 28,297
Total
479,978 314,443 426,727 259,636
2024
2023
12 | Page
Petroleum and Natural Gas Expenditures
Drilling History
($ 000s)
2024
2023
Land
1,190 1,222
Acquisitions
24,234
-
Exploration and development costs
99,886
125,256
Net petroleum and natural gas capital expenditures
125,310
126,478
The following table summarized petroleum and natural gas capital expenditures incurred by Bonterra on
acquisitions, land, and exploration and development costs for the years ended December 31:
The following tables summarize Bonterra's gross and net drilling activity and success:
Gross
Net
Gross
Net
Gross
Net
Crude oil
23 18.5 - - 23 18.5
Natural gas
1 1.0 - - 1 1.0
Total
24 19.5 - - 24 19.5
Success rate
100%
100% 100.0 100.0
100%
100%
Gross
Net
Gross
Net
Gross
Net
Crude oil
52 41.2 - - 52 41.2
Natural gas
- - 1 1.0 1 1.0
Total
52 41.2 1 1.0 53 42.2
Success rate
100%
100% 100.0 100.0
100%
100%
2024
Development
Exploratory
Total
2023
Development
Exploratory
Total
13 | Page
YEAR END 2024
Management’s Discussion and Analysis
&
Financial Statements
14 | Page
MANAGEMENT’S DISCUSSION AND ANALYSIS
This Management’s Discussion and Analysis (“MD&A”) of the financial position and results of operations of
Bonterra Energy Corp. (“Bonterra” or “the Company”), is for the three months and years ended December
31, 2024 and 2023. For a full understanding of the financial position and results of operations of the
Company, the MD&A should be read in conjunction with the documents filed on SEDAR+, including historical
financial statements, MD&A and the Annual Information Form (“AIF”) dated March 13, 2025 for the year
ended December 31, 2024. These documents are available at www.sedarplus.ca.
Bonterra’s management is responsible for the integrity of the information contained in this report and for the
consistency between the MD&A and financial statements. In the preparation of these financial statements,
estimates are necessary to make a determination of future values for certain assets and liabilities.
Management believes these estimates have been based on careful judgments and have been properly
presented. The financial statements have been prepared using policies and procedures established by
management and fairly reflect Bonterra’s financial position and results of operations. The Company's
financial statements have been prepared in accordance with International Financial Reporting Standards
(IFRS®) as issued by the International Accounting Standards Board (IASB®).
Bonterra’s Board of Directors and Audit Committee have reviewed and approved the financial statements
and MD&A. This MD&A is dated March 13, 2025.
Description of Business
Bonterra Energy Corp. is one of Canada’s longest-standing oil and gas exploration, development, and
production companies, with a focus on its core assets in the Cardium, Charlie Lake, and emerging Montney
formations within the western Canadian sedimentary basin. The Company is committed to sustainable
production growth, financial resilience, and advancing toward a shareholder returns-based model through
disciplined capital allocation and operational efficiency.
Bonterra plays a vital role as an economic contributor to rural and northern Alberta communities, fostering
positive stakeholder relationships and upholding high standards of environmental and corporate
responsibility. Bonterra’s common shares are traded on the Toronto Stock Exchange (“TSX”) under the
symbol BNE.
Frequently Recurring Terms
Bonterra uses the following frequently recurring terms in this MD&A:
“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;
“LNG” refers to liquefied natural gas; 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.
15 | Page
ANNUAL COMPARISONS
(1) On March 1, 2024, the Company acquired the Charlie Lake Assets for cash consideration of $23.6 million and $0.3 million in non-
core mineral rights, including closing adjustments. The Charlie Lake Assets have been accounted for as an asset acquisition, which
resulted in an increase of $24.2 million in PP&E and the assumption of $0.3 million in decommissioning liabilities.
As at and for the year ended
($000s except $ per share)
FINANCIAL
Revenue - realized oil and gas sales
279,957
319,517
384,197
Funds flow
118,668
147,305
185,583
Per share - basic
3.18
3.96
5.16
Per share - diluted
3.18
3.95
4.98
Cash flow from operations
114,952
140,183
183,553
Per share - basic
3.08
3.77
5.10
Per share - diluted
3.08
3.76
4.92
Net earnings
10,203
44,943
79,023
Per share - basic
0.27
1.21
2.20
Per share - diluted
0.27
1.20
2.12
Capital expenditures
101,076 126,478
79,769
Oil and gas property acquisition
(1)
24,234
- -
Total assets
975,043
967,870
919,682
Net debt
167,210
145,440
154,786
Shareholders' equity
540,639
528,258
479,839
OPERATIONS
Light oil
-bbl per day
6,639
7,209
7,095
-average price ($ per bbl)
94.35
97.58
113.93
NGLs
-bbl per day
1,513
1,359
1,141
-average price ($ per bbl)
46.97
48.80
66.00
Conventional natural gas -MCF per day
40,164
33,814
31,023
-average price ($ per MCF)
1.68
3.12
5.44
Total BOE per day
14,846
14,204
13,407
December 31,
2024
December 31,
2023
December 31,
2022
16 | Page
QUARTERLY COMPARISONS
As at and for the periods ended
($ 000s except $ per share)
Q4
Q3
Q2
Q1
Financial
Revenue - oil and gas sales
69,699
69,204
72,465
68,589
Funds flow
30,100
30,066
31,484
27,018
Per share - basic
0.81
0.81
0.84
0.73
Per share - diluted
0.81
0.81
0.84
0.72
Cash flow from operations
28,587
31,531
33,180
21,654
Per share - basic and diluted
0.77
0.84
0.89
0.58
Net earnings (loss)
(2,213)
4,258
7,310
848
Per share - basic and diluted
(0.06)
0.11
0.20
0.02
Capital expenditures
22,438
24,095
21,619
32,924
Oil and gas property acquisition
-
-
- 24,234
Total assets
975,043
982,256
984,065
984,464
Net debt
167,210
168,278
172,622
181,400
Shareholders' equity
540,639
542,344
537,498
529,605
Operations
Light oil (barrels per day)
6,588
6,775
6,571
6,622
NGLs (barrels per day)
1,625
1,538
1,418
1,468
Conventional natural gas (MCF per day)
44,436
42,039
37,519
36,594
Total BOE per day
15,619
15,320
14,242
14,189
2024
As at and for the periods ended
($ 000s except $ per share)
Q4
Q3
Q2
Q1
Financial
Revenue - oil and gas sales
81,739
84,909
75,606
77,263
Funds flow
40,442
42,722
34,799
29,342
Per share - basic
1.09
1.15
0.94
0.79
Per share - diluted
1.08
1.14
0.93
0.79
Cash flow from operations
44,596
37,715
33,854
24,018
Per share - basic
1.20
1.01
0.91
0.65
Per share - diluted
1.19
1.01
0.91
0.64
Net earnings
14,973
13,486
8,844
7,640
Per share - basic
0.40
0.36
0.24
0.21
Per share - diluted
0.40
0.36
0.24
0.20
Capital expenditures
14,009 36,130 16,116
60,223
Total assets
967,870
955,484
962,021
963,890
Net debt
145,440
172,489
173,299
188,629
Shareholders' equity
528,258
512,479
498,449
488,762
Operations
Light oil (barrels per day)
7,306
7,177
7,282
7,068
NGLs (barrels per day)
1,619
1,410
1,248
1,155
Conventional natural gas (MCF per day)
37,214
34,241
32,286
31,448
Total BOE per day
15,128
14,294
13,911
13,464
2023
17 | Page
Business Environment and Sensitivities
Bonterra’s financial results may be influenced by fluctuations in commodity prices, including price
differentials, as well as production volumes and foreign exchange rates. The following table depicts selective
market benchmark commodity prices, differentials, and foreign exchange rates in the last eight quarters to
assist in understanding how past volatility has impacted the Company’s financial and operating performance.
The increases or decreases in Bonterra’s realized average price for oil and natural gas for each of the eight
quarters is also outlined in detail in the following table.
(1) This differential accounts for the majority of the difference between WTI and Bonterra’s average realized price (before quality
adjustments and foreign exchange).
WTI prices averaged $70.27 USD per barrel in Q4 2024, reflecting a 10 percent decline compared to Q4
2023. This decrease was driven by supply and demand volatility influenced by various macroeconomic and
geopolitical factors, including global supply growth and OPEC+ signaling its intent to reintroduce supply to
the market starting in Q2 2025.
Beyond the WTI benchmark, the Company’s realized crude oil price is affected by the MSW Stream Index,
or Edmonton Par differential (the “Differential”). In Q4 2024, the Differential averaged ($2.37) USD per barrel,
tightening by $2.79 USD per barrel from Q4 2023. While the Differential has improved year over year, near-
term volatility is expected as the market assesses the potential impact of tariffs on all grades of Canadian
crude production.
AECO daily spot prices averaged $1.47 per mcf in Q4 2024, down 36 percent from Q4 2023. This decline
was primarily due to a significant supply-demand imbalance, leading to record storage levels and downward
pressure on prices.
The following chart shows the Company’s sensitivity to key commodity price variables. The sensitivity
calculations are performed independently and show the effect of changing one variable while holding all
other variables constant.
(1) This analysis uses current royalty rates, annualized estimated average production of 14,700 BOE per day and no changes in
working capital.
(2) Based on annualized basic weighted average shares outstanding of 37,324,880.
Q4-2024 Q3-2024 Q2-2024 Q1-2024 Q4-2023 Q3-2023 Q2-2023 Q1-2023
Crude oil
WTI (U.S.$/bbl)
70.27
75.09
80.57
76.96
78.32
82.26
73.78
76.13
WTI to MSW Stream Index
Differential (U.S.$/bbl)
(1)
(2.37)
(3.31)
(3.62)
(8.64)
(5.16)
(1.83)
(2.96)
(2.86)
Foreign exchange
U.S.$ to Cdn$
1.3991
1.3636
1.3694
1.3488
1.3619
1.3410
1.3431
1.3520
Bonterra average realized
oil price (Cdn$/bbl)
92.11
94.30
102.09
88.96
97.01
104.32
93.21
95.71
Natural gas
AECO (Cdn$/mcf)
1.47
0.68
1.17
2.48
2.29
2.58
2.44
3.20
Bonterra average realized
gas price (Cdn$/mcf)
1.60
0.96
1.64
2.65
2.73
3.06
3.01
3.78
Annualized sensitivity analysis on before tax cash flow, as estimated for 2025
(1)
Impact on cash flow
Change ($)
$000s
$ per share
(2)
Realized crude oil price ($/bbl)
1.00
2,104
0.06
Realized natural gas price ($/mcf)
0.10
1,480
0.04
U.S.$ to Canadian $ exchange rate
0.01
1,388
0.04
18 | Page
Business Overview, Strategy and Key Performance Drivers
In 2024, Bonterra continued its profitable development of high-quality, light oil-weighted assets, achieving
significant milestones in production growth and strategic acquisitions. Subsequent to December 31, 2024,
the Company completed a financial restructuring to strengthen and simplify its capital structure and support
future growth initiatives.
Debt Refinancing and Capital Management
On January 28, 2025, Bonterra closed a private placement offering of $135 million aggregate principal
amount of Senior Secured Second Lien Notes due 2030 (the "Notes"). The Notes were priced at $981.16
per $1,000 of principal amount of Notes, will accrue interest at the rate of 10.50% per annum and will have
a five-year term, maturing on January 28, 2030. Interest payments of $7.1 million will be made bi-annually
on January 28 and July 28, beginning July 28, 2025. Proceeds were used to fully repay the amount owing
under the second lien subordinated term debt, with the remainder of the net proceeds used to repay the
amount drawn under the Company's revolving first lien credit facility and to pay related transaction expenses.
On February 26, 2025, Bonterra redeemed its subordinated debentures, at a price of $1,072.50 per
$1,000.00 principal amount, including accrued interest and a redemption premium.
Strategic Acquisitions and Development
On March 1, 2024, Bonterra closed an acquisition to purchase primarily undeveloped petroleum and natural
gas assets in northern Alberta, for cash consideration of $23.6 million and $0.3 million in non-core mineral
rights, after closing adjustments (the “Charlie Lake Asset Acquisition”). The Charlie Lake Asset Acquisition
was funded by the bank facility and resulted in a $24.2 million increase in property, plant and equipment,
and the assumption of $0.3 million in decommissioning liabilities. The Charlie Lake asset is located northwest
of Grand Prairie, Alberta (Bonanza), on a contiguous 118 sections of land with two extensive land blocks of
91 and 100 percent working interest. The Company drilled, completed, tied in and brought on production four
gross Charlie Lake wells in 2024 and is pleased with results to date. Initial production from the two most
recent wells exceeded gathering infrastructure capacity resulting in area wide production restrictions in Q4
2024. The Company has since been able to resume unrestricted operations as of January of 2025. The two
most recent wells achieved 30 day peak rates at a combined 1,558 BOE per day, including approximately
390 barrels per day of light crude oil. Current total production from the Charlie Lake asset is approximately
2,100 BOE per day, including approximately 685 barrels per day of light crude oil. The Charlie Lake Asset
Acquisition provides a portfolio of high-quality future drilling locations and reserves, establishing a new core
operating area for the Company.
Production Growth and Operational Highlights
Bonterra averaged 14,846 BOE per day of production in 2024, a five percent increase from 14,204 BOE per
day in 2023, driven by new wells and a well reactivation program. Production in the fourth quarter of 2024
reached a record 15,619 BOE per day. Bonterra is pleased to reiterate its previously announced 2025 annual
guidance with average production between 14,600 and 14,800 BOE per day based on a fully funded 2025
capital expenditure budget between $65 million to $75 million.
The Company’s first Montney well (the “4-3 well”) has been flowing unrestricted since November of 2024
and is currently producing approximately 575 BOE per day, including approximately 125 barrels per day of
light crude oil, 2.2 mmcf per day of conventional natural gas and 85 barrels per day of natural gas liquids. To
date, the 4-3 well has cumulatively produced approximately 58,350 barrels of light crude oil, 575 mmcf of
conventional natural gas and 19,200 barrels of natural gas liquids over a 13 month period, of which the
majority of the producing time in the first ten months was restricted.
The Company is very encouraged with the early results of its second Montney well (the “102/4-28 well”),
flowing unrestricted at current rates of approximately 915 BOE per day, including approximately 300 barrels
per day of light crude oil, 3.0 mmcf per day of conventional natural gas and 105 barrels per day of natural
gas liquids. The 102/4-28 well was completed with a different fracture stimulation design than the 4-3 well
and was able to avoid lengthy early time production restrictions that the 4-3 well experienced. To date, over
19 | Page
the course of approximately four months, the 102/4-28 well has cumulatively produced 35,800 barrels of light
crude oil, 200 mmcf of conventional natural gas and 7,000 barrels of natural gas liquids.
Bonterra's Montney asset is located directly north of Grand Prairie, Alberta (Valhalla), on a contiguous 52
sections of land with 100 percent working interest.
Capital Expenditures and Environmental Stewardship
The Company invested $101.1 million of capital expenditures in 2024. Of the capital invested, $69.1 million
was directed to the drilling of 20 gross (18.9 net) operated wells and completing, equipping, tying-in and
placing on production 24 gross (22.7 net) operated wells, of which four gross (3.6 net) were drilled in Q4
2023. An additional $32.0 million was directed primarily to related infrastructure, recompletions and drilling,
completing, equipping and tying-in a water disposal well to reduce water handling costs in the Montney area.
Bonterra will continue to prioritize responsible environmental initiatives, including a targeted abandonment
and reclamation program. During 2024, the Company abandoned 28.6 net wells, 10.4 net facilities, and 31.6
net pipelines (covering a total length of 40.4 kilometers of pipeline), decommissioned 215.8 net well sites in
preparation for future reclamation, and completed the initial reclamation on 16.0 net sites. The Company
invested $7.2 million in decommissioning liabilities for 2024, exceeding its mandatory spend requirements
under the Alberta Energy Regulator’s Liability Management Program.
Risk Management and Commodity Pricing
To protect future cash flows, Bonterra has secured physical delivery sales and risk management contracts
for approximately 35% and 40% (net of royalties payable) of its expected crude oil production and natural
gas production, respectively, through the next nine months of 2025. The Company has locked in WTI prices
between $60.00 USD and $86.35 USD per barrel for 1,995 barrels per day, and natural gas prices between
$1.75 and $3.30 per GJ for 17,456 GJ per day.
Key Performance Drivers
The Company’s successful operations are dependent upon several factors including, but not limited to
commodity prices, efficient management of capital spending, the ability to maintain desired production levels,
control over infrastructure, efficiency in developing and operating properties, and the ability to control costs.
Its key performance measures include average daily production volumes, realized prices, and production
costs per unit. Disclosure of these key performance measures can be found within this MD&A and/or previous
interim or annual MD&A disclosures.
Production
The Company's production in 2024 averaged 14,846 BOE per day, reflecting a five percent increase
compared to the 2023 average of 14,204 BOE per day, or an additional 642 BOE per day. This growth was
primarily driven by the success of Bonterra’s 2024 capital and well reactivation program, which contributed
significantly to the higher production levels. However, the increase was partially offset by approximately 375
BOE per day of shut-in volumes, largely due to planned major gas plant turnarounds, which are required
every five years, and the new Charlie Lake wells surpassing expectations, which led to Q4 2024 capacity
constraints in the current gathering infrastructure. The Company has since resumed unrestricted operations
in the area as of January 2025.
December 31,
2024
September 30,
2024
December 31,
2023
December 31,
2024
December 31,
2023
Crude oil (barrels per day)
6,588
6,775
7,306
6,639
7,209
NGLs (barrels per day)
1,625
1,538
1,619
1,513
1,359
Conventional natural gas (MCF per day)
44,436
42,039
37,214
40,164
33,814
Average BOE per day
15,619
15,320
15,218
14,846
14,204
Three months ended
Year ended
20 | Page
Cash Netback
In 2024, field and cash netbacks decreased on a BOE basis compared to 2023, primarily due to lower
realized natural gas prices. This was partially offset by reduced royalties and current income tax costs.
Oil and Gas Sales
Revenue from oil and gas sales in 2024 decreased by $39.6 million, or 12 percent, as compared to 2023.
This decrease was primarily driven by a 16 percent reduction in Bonterra’s average realized commodity
prices caused primarily by a 46 percent decrease in realized gas prices, which was partially offset by a five
percent increase in production over the same period.
Bonterra’s product split on a revenue basis was weighted approximately 91 percent to crude oil and NGLs
during 2024.
$ per BOE
December 31,
2024
September 30,
2024
December 31,
2023
December 31,
2024
December 31,
2023
Production volumes (BOE)
1,436,969
1,409,407
1,391,754
5,433,622
5,184,455
Gross production revenue
48.50 49.10 58.73
51.52
61.63
Realized gain on risk
management contracts
1.13
0.85
0.02
0.66
0.35
Royalties
(6.62)
(7.66)
(9.53)
(7.30)
(8.95)
Production costs
(16.07)
(16.04)
(13.37)
(16.54)
(16.02)
Field netback
26.94
26.25
35.85
28.34
37.01
General and administrative
(3.62)
(1.72)
(3.72)
(2.65)
(2.79)
Disposal of investments
- - -
0.27
-
Interest and other
(2.91)
(3.06)
(3.09)
(3.17)
(3.65)
Current income tax
0.54
(0.14)
0.02
(0.95)
(2.15)
Cash netback
20.95 21.33 29.06 21.84
28.42
Three months ended
Year ended
December 31,
2024
September 30,
2024
December 31,
2023
December 31,
2024
December 31,
2023
Revenue - oil and gas sales ($ 000s)
Light oil
55,826
58,774
65,209
229,249
256,745
NGL
7,323
6,714
7,168
26,011
24,212
Conventional natural gas
6,550
3,716
9,362
24,697
38,560
69,699
69,204
81,739
279,957
319,517
Average realized prices:
Light oil ($ per barrel)
92.11
94.30
97.01
94.35
97.58
NGL ($ per barrel)
48.97
47.44
48.12
46.97
48.80
Conventional natural gas ($ per MCF)
1.60
0.96
2.73
1.68
3.12
Average ($ per BOE)
48.50
49.10
58.73
51.52
61.63
Average BOE per day
15,619
15,320
15,128
14,846
14,204
Three months ended
Year ended
21 | Page
Royalties
Royalties paid by the Company consist of both Crown royalties to the Provinces of Alberta, Saskatchewan
and British Columbia and other royalties. Total royalties in 2024 decreased by $1.65 per BOE as compared
to the prior year primarily due to a decrease in commodity prices.
Production Costs
Production costs for 2024 increased on a BOE basis as compared to 2023 primarily due to start up activities
and early stage third party infrastructure arrangements in the Charlie Lake and Montney plays and a more
active year over year well reactivation program. This was partially offset by a 52 percent decrease in power
rates in 2024 compared to 2023.
Other Income
Deferred consideration relates to a deferred gain on the sale of a two percent overriding royalty interest,
which is recognized into revenue using the same unit-of-production method as the encumbered property,
plant, and equipment assets.
During the first quarter of 2024, Bonterra disposed of all of its investments in marketable securities. The
dispositions resulted in a gain net of tax of $271,000 and were recorded as an equity transfer between
accumulated other comprehensive income and retained earnings.
The Company receives administrative income for various oil and gas administrative services provided and
production equipment rentals to other companies.
($ 000s)
December 31,
2024
September 30,
2024
December 31,
2023
December 31,
2024
December 31,
2023
Crown royalties
6,727
7,631
9,448
27,633
32,953
Freehold, gross overriding and other royalties
2,784
3,163
3,812
12,009
13,451
Total royalties
9,511
10,794
13,260
39,642
46,404
Crown royalties - percentage of revenue
9.7
11.0
11.6
9.9
10.3
Freehold, gross overriding and other royalties -
percentage of revenue
4.0
4.6
4.7
4.3
4.2
Royalties - percentage of revenue
13.7
15.6
16.3
14.2
14.5
Royalties $ per BOE
6.62
7.66
9.53
7.30
8.95
Three months ended
Year ended
($ 000s except $ per BOE)
December 31,
2024
September 30,
2024
December 31,
2023
December 31,
2024
December 31,
2023
Production costs
23,089
22,611
18,603
89,881
83,064
$ per BOE
16.07
16.04
13.37
16.54
16.02
Three months ended
Year ended
($ 000s)
December 31,
2024
September 30,
2024
December 31,
2023
December 31,
2024
December 31,
2023
Investment income
46 60
120
326
440
Administrative income
75
49
120
252
321
Gain on sale of property
25
-
- 178 17
Government grant in-kind
-
- - -
782
Deferred consideration
276 223 274 958
1,009
Realized gain on risk management
contracts
1,626 1,203 28 3,569
1,801
Unrealized gain (loss) on risk
management contracts
(2,707) 2,101 4,617 (1,525)
1,559
(659)
3,636
5,159 3,758
5,929
Three months ended
Year ended
22 | Page
To minimize commodity price risk on crude oil and natural gas sales, Bonterra has entered into financial
derivatives. The financial derivatives outstanding are primarily for the period from January 1, 2025 to
September 30, 2025 and are for a total of 544,750 barrels of light crude oil (approximately 1,995 barrels of
oil per day) at fixed WTI prices ranging from $60.00 USD to $86.35 USD per barrel and 9,973 GJ per day of
natural gas at fixed prices between $1.75 and $3.30. These contracts are not considered normal sales
contracts and are recorded at fair value.
General and Administrative (“G&A”) Expense
Employee compensation expense in 2024 is comparable to the same period in 2023. Quarter-over-quarter
increased due to a bonus accrual.
Office and administrative expense in Q4 of 2024 increased as compared Q3 of 2024 primarily due to the
second lien subordinated term loan annual fee in the fourth quarter of 2024.
Finance Costs
Interest on bank debt was higher in 2024 as compared 2023 due to an increase in bank debt from the Charlie
Lake Asset Acquisition that occurred towards the end of the first quarter, which was partially offset by
decreases in interest rates.
Interest on the second lien Subordinated Term Debt was lower due to the $4.75 million amortization
payments per quarter and a decrease in the Canadian Prime rate. On January 28, 2025, the Subordinated
Term Debt was repaid.
Subordinated Debentures are unsecured and were determined to be a compound instrument with a debt and
equity component. The fair value of the $59 million debt component was reduced by the residual value from
the issuance of 3,304,000 warrants and issue costs. The debentures have a fixed interest rate of nine
percent, payable semi-annually. Based on the calculated fair value of the subordinated debentures as at
December 31, 2024, the effective interest rate was determined to be 15.6 percent using the effective interest
rate method. The value of the subordinated debentures will accrete up to the principal balance at maturity.
On February 26, 2025, the Subordinated Debentures were repaid. For more information on Subordinated
Debentures, refer to Note 9 and Note 19 of the December 31, 2024, audited annual financial statements.
($ 000s except $ per BOE)
December 31,
2024
September 30,
2024
December 31,
2023
December 31,
2024
December 31,
2023
Employee compensation
3,873
1,795
3,937
9,111
9,212
Office and administrative
1,334
623
1,234
5,262
5,245
Total G&A
5,207
2,418
5,171
14,373
14,457
$ per BOE
3.62
1.72
3.72
2.65
2.79
Three months ended
Year ended
($ 000s except $ per BOE)
December 31,
2024
September 30,
2024
December 31,
2023
December 31,
2024
December 31,
2023
Interest on bank debt
1,153
1,026
641
3,970
3,359
Subordinated debentures
1,327
1,328 1,327
5,310
5,310
Subordinated term debt
1,834 2,069 2,596
8,541
11,046
Interest expense
4,314
4,423
4,564
17,821
19,715
$ per BOE
3.00
3.14
3.28
3.28
3.80
Accretion of decommissioning liabilities
953
940
943
3,692
3,770
Accretion on subordinated debentures
909 821 790
3,287
2,816
Accretion on subordinated term debt
392 424 496
1,732
2,136
Total finance costs
6,568
6,608
6,793
26,532
28,437
Three months ended
Year ended
23 | Page
A one percent increase (decrease) in the Canadian prime rate would decrease (increase) both annual net
earnings and comprehensive income by approximately $685,000. For more information on bank debt and
subordinated term debt, see the Liquidity and Capital Resources section herein.
Share-Option Compensation
Share-option compensation is a statistically calculated value representing the estimated expense of issuing
employee stock options. The Company records a compensation expense over the vesting period based on
the fair value of options granted to directors, officers, and employees.
Based on the outstanding options as of December 31, 2024, the Company has an unamortized expense of
$1.2 million, of which; $1.0 million in 2025 and $0.2 million thereafter. For more information about options
issued and outstanding, refer to Note 13 of the December 31, 2024, audited annual financial statements.
Depletion and Depreciation, Exploration and Evaluation (“E&E”) and Impairment
The provision for depletion and depreciation (“D&D”) increased due to an increase in production from the
same period in 2023. There were no indicators of impairment identified for each of the periods ended.
Taxes
The Company recorded a total income tax expense of $3.7 million in 2024 (2023 – $14.4 million). The
decrease in income tax expense as compared to 2023 is due to reduced earnings before income taxes.
Included in the 2024 current income tax provision of $5.2 million, is $1.8 million payable to the province of
Alberta and $3.4 million to the Federal government. For additional information regarding income taxes, see
Note 12 of the December 31, 2024, audited annual financial statements.
Net Earnings
Net earnings for 2024 decreased by $34.7 million as compared to 2023. The decrease in net earnings was
primarily attributed to lower realized natural gas prices and an increase in production costs and depletion
due to increased production volumes. This was partially offset by a decrease in royalties and the tax
provision.
Net earnings for Q4 2024 decreased $17.2 million compared to Q4 2023. The decrease in net earnings
was primarily due to lower commodity prices and an increase in production costs as the Company reduced
its well reactivation program in Q4 2023.
($ 000s)
December 31,
2024
September 30,
2024
December 31,
2023
December 31,
2024
December 31,
2023
Share-option compensation
508
588
946
2,293
3,228
Three months ended
Year ended
($ 000s)
December 31,
2024
September 30,
2024
December 31,
2023
December 31,
2024
December 31,
2023
Depletion and depreciation
26,826
24,124
24,071
97,137
90,479
Three months ended
Year ended
($ 000s except $ per share)
December 31,
2024
September 30,
2024
December 31,
2023
December 31,
2024
December 31,
2023
Net earnings (loss)
(2,213)
4,258
14,973
10,203
44,943
$ net earnings per share - basic
(0.06)
0.11
0.40
0.27
1.21
$ net earnings per share - diluted
(0.06)
0.11
0.40
0.27
1.20
Three months ended
Year ended
24 | Page
Other Comprehensive Income
Other comprehensive income for 2024 consists of an unrealized loss before tax on investments of $186,000
relating to a decrease in the investments’ fair value (December 31, 2023 – $394,000 gain). Other
comprehensive income also consisted of a realized gain of $271,000 net of tax from the divestment of all the
investments held by the Company. The realized gain resulted in transferring the remaining accumulated
other comprehensive income to retained earnings.
Funds Flow and Cash Flow From Operations
In 2024, the Company experienced a $28.6 million decrease in funds flow compared to 2023, primarily driven
by lower realized natural gas prices and higher production costs. These challenges were partially offset
by reduced royalties and current income taxes, which helped mitigate some of the financial impact.
Similarly, cash flow from operating activities decreased by $25.2 million, which was $2.6 million less than
the decline in funds flow. This smaller reduction was due to an increase in non-cash working capital, which
cushioned the impact, alongside a decrease in decommissioning expenditures settled.
Liquidity and Capital Resources
Net Debt to EBITDA
Bonterra continues to focus on reducing overall debt while managing its cash flow and capital expenditures.
The Company’s net debt to twelve-month trailing EBITDA ratio as of December 31, 2024 was 1.2 (versus
0.8 at December 31, 2023).
The increase in Bonterra’s net debt to EBITDA ratio is primarily due to an increase in net debt from the
Charlie Lake Asset Acquisition and a decrease in EBITDA from lower commodity prices, in particular natural
gas prices. The net debt to EBITDA ratio is anticipated to improve in subsequent quarters due to the
Company’s focus on debt reduction from a reduced capital program paired with increased production and
future cash flow protection from having at least 30 percent (net of royalties payable) of Bonterra’s forecasted
oil and natural gas production hedged over the next nine months.
For more information about net debt to EBITDA, please see Note 17 of the December 31, 2024 audited
annual financial statements.
($ 000s except $ per share)
December 31,
2024
September 30,
2024
December 31,
2023
December 31,
2024
December 31,
2023
Funds flow
30,100
30,066
40,442
118,668
147,305
$ per share - basic
0.81
0.81
1.09
3.18
3.96
$ per share - diluted
0.81
0.81
1.08
3.18
3.95
Cash flow from operations
28,587
31,531
44,596
114,952
140,183
$ per share - basic
0.77
0.84
1.20
3.08
3.77
$ per share - diluted
0.77
0.84
1.19
3.08
3.76
Three months ended
Year ended
25 | Page
Working Capital Deficiency and Net Debt
Net debt is a combination of bank debt, subordinated debentures, subordinated term debt and working
capital. The Company’s Bank Facility has a maturity date of April 30, 2026, and is recorded as a long-term
liability at December 31, 2024 and December 31, 2023.
The Company’s subordinated debentures are classified as non-current liabilities as of December 31, 2024.
This classification is supported by the sufficient availability under the Company’s Bank Facility, which
provides the ability to refinance or defer repayment beyond the next financial year, ensuring that the
debentures do not require settlement within that period. Included in working capital deficiency is $19.0 million
of principal payments due in the next 12 months on the subordinated term debt loan. Bonterra actively
monitors its credit availability and working capital to ensure that it has sufficient available funds to meet its
financial requirements as they come due. Any of these events present risks that could affect Bonterra’s ability
to fund ongoing operations. If required, Bonterra will also consider short-term or long-term financing
alternatives to meet its future liabilities. The subordinated debentures and the subordinated term debt loans
were both repaid in the first quarter of 2025.
Net debt at December 31, 2024 increased by $21.8 million as compared to December 31, 2023, primarily
due to the $23.6 million cash consideration for the Charlie Lake Asset Acquisition and a decrease in
commodity prices. The Company intends to continue its focus on net debt reduction.
Working capital is calculated as current assets less current liabilities.
Financial Risk Management
Bonterra faces market risk related to the oil and gas it produces. This risk is influenced by external factors
such as global supply and demand. External factors beyond the Company’s control may affect the
marketability of oil and gas produced. Oil prices are affected by worldwide supply and demand fundamentals
and access to market, while natural gas prices are largely affected by North American supply and demand
fundamentals.
To manage commodity risk, the Company executed physical delivery sales contracts which are considered
normal sales contracts and are not recorded at fair value in the financial statements, and also executed risk
management contracts which are not considered normal sales contracts and are recorded at fair value. The
Company has contracts in place on approximately 30 percent of its estimated oil and natural gas production
(net of royalties payable) for the next nine months.
The Company relies on its cash flow, access to equity markets and bank financing to support its operations
and capital program. Bonterra uses these futures contracts to hedge its exposure to the potential adverse
impact of commodity price volatility and provide a measure of stability to the Company’s capital development
program. For more information on physical delivery and risk management contracts in place, see Note 17 of
the December 31, 2024 annual audited financial statements.
($ 000s)
December 31,
2024
December 31,
2023
Working capital deficiency
29,377
25,015
Bank debt
46,211 14,822
Subordinated debentures
55,872 52,585
Subordinated term debt (long-term portion)
35,750 53,018
Net debt
167,210
145,440
26 | Page
Capital Expenditures and Acquisition
During 2024, the Company incurred capital expenditures of $101.1 million (December 31, 2023 - $126.5
million). Of the total capital invested, $69.1 million was directed to the drilling of 20 gross (18.9 net) operated
wells and the completion, equip and tie-in of 24 gross (22.7 net) operated wells, of which four gross (3.6 net)
of those wells were drilled in Q4 of 2023. An additional $32.0 million was spent primarily on related land and
lease, infrastructure, recompletions and drilling a water disposal well.
On March 1, 2024, Bonterra closed an acquisition to purchase largely undeveloped petroleum and natural
gas assets in northern Alberta, for cash consideration of $23.6 million and $0.3 million in non-core land and
leases, after closing adjustments. The Charlie Lake Asset Acquisition has been accounted for as an asset
acquisition, which resulted in a $24.2 million increase in PP&E and the assumption of $0.3 million in
decommissioning liabilities. Of the 19 operated wells drilled, four (3.6 net) were in the Charlie Lake area for
an average gross cost of $2.4 million per well.
Drilling Statistics
(1)
“Gross” wells are the number of wells in which Bonterra has a working interest.
(2) “Net” wells are the aggregate number of wells obtained by multiplying each gross well by Bonterra’s percentage of working interest.
Decommissioning Liabilities
The Company spent $7.2 million on decommissioning activities during the year ended December 31, 2024
(December 31, 2023 - $9.1 million). For 2025, the Company plans to invest approximately $8.0 in
decommissioning liabilities, exceeding its $5.2 million mandatory spend requirements under the Alberta
Energy Regulator’s Liability Management Program.
Bank Debt and Subordinated Term Debt
Bank debt represents the outstanding amounts drawn on the Company’s Bank Facility. As at December 31,
2024, the Company has a total Bank Facility of $110.0 million, comprised of a $85.0 million syndicated
revolving credit facility and a $25.0 million non-syndicated revolving facility. The amount drawn under the
total Bank Facility at December 31, 2024 was $46.2 million (December 31, 2023 - $14.8 million).
($ 000s)
December 31,
2024
December 31,
2023
Exploration and Evaluation
Land and lease
1,190
1,221
Property, Plant and Equipment
Operated drilling, completing and equipping costs
69,062
91,578
Infrastructure, recompletions and other
29,118
26,131
Non-operated capital
1,706
7,548
99,886 125,257
Total capital expenditures
101,076
126,478
Gross
(1)
Net
(2) Gross
(1)
Net
(2) Gross
(1)
Net
(2) Gross
(1)
Net
(2) Gross
(1)
Net
(2)
Cardium oil horizontal-operated
- - 2 1.9 2
1.8
15
14.3
40
38.2
Cardium oil horizontal-non-operated
- - 4 0.6 5 1.0
4 0.6 11 2.0
Charlie Lake oil horizontal-operated
- - 2 1.8
- - 4 3.6
-
-
Montney gas horizontal-operated
1
1.0
- - 1 1.0
1 1.0 1 1.0
Total
1 1.0
8
4.3
8
3.8
24
19.5
52
41.2
Success rate
100%
100%
100%
100%
100%
Three months ended
Year ended
December 31,
2024
September 30,
2024
December 31,
2023
December 31,
2024
December 31,
2023
27 | Page
The amounts borrowed under the total Bank Facility bear interest at a floating rate based on the applicable
Canadian prime rate or Banker’s Acceptance rate, plus between 2.00 percent and 7.00 percent, depending
on the type of borrowing and the Company’s consolidated debt to EBITDA ratio. As at December 31, 2024,
the terms of the total revolving Bank Facility provided that the loan facility was revolving to April 30, 2025,
with a maturity date of April 30, 2026, with no set terms of repayment on the credit facility.
The amount available for borrowing under the Bank Facility is reduced by outstanding letters of credit. Letters
of credit totaling $2.0 million were issued as at December 31, 2024 (December 31, 2023 - $2.1 million).
Security for the Bank Facility consists of various floating demand debentures totaling $750 million (December
31, 2023 - $750 million) over all of the Company’s assets and a general security agreement with first ranking
over all personal and real property.
Subordinated Term Debt represents a four-year second lien, non-revolving subordinated term debt facility.
The amounts borrowed under the Subordinated Term Debt bear interest at a fixed rate of 11.70 percent to
be applied to 25 percent of the term facility principle and a floating interest rate of Canadian Prime Rate plus
6.25 percent on the remaining 75 percent of the principal amount. The Company is required to make
mandatory principal repayments equal to $4.75 million, payable on the last banking day of February, May,
August and November of each calendar year, commencing on February 28, 2023. The term debt has a
maturity date of November 30, 2026, on which the remaining outstanding principal balance is to be paid.
The amount drawn under the Subordinated Term Debt at December 31, 2024 was $57.0 million (December
31, 2023 - $76.0 million). Based on the calculated fair value of the debt as at December 31, 2024, the
effective interest rate was determined to be 15.1 percent, by discounting future payments of interest and
principal with the residual value allocated to issue costs. The value of the debt will accrete up to the principal
balance at maturity.
Security for the Subordinated Term Debt consists of various floating demand debentures totaling $150 million
(December 31, 2023 - $150 million) over all of the Company’s assets and a general security agreement with
second ranking over all personal and real property.
On January 28, 2025, the Subordinated Term Debt was repaid. For more information on the subordinated
debt restructuring, please see Note 19, of the December 31, 2024 audited annual financial statements.
Financial Covenants
The Company is subject to certain financial covenants under its Bank Facility and Subordinated Term Debt
facility as follows:
Consolidated debt to trailing twelve months EBITDA ratio shall not exceed 2.50:1.00; and
Asset coverage ratio of not less that 1.50:1.
Asset coverage ratio is defined as the proved developed producing reserves of the Company (before income
tax; discounted at 10 percent), as evaluated by an independent third-party engineering report as at
December 31, 2023 and evaluated on strip commodity pricing, divided by the consolidated debt of the
Company. The ratio is calculated and revaluated for strip pricing on June 30 and December 31 period ends.
As at December 31, 2024, Bonterra was in compliance with all financial covenants on its first and second
lien facilities. For more information about Bank Debt and Subordinated Term Debt, please see Note 8 and
10, respectively, of the December 31, 2024 audited annual financial statements.
28 | Page
Shareholders’ Equity
The Company is authorized to issue an unlimited number of common shares without nominal or par value.
The Company is also authorized to issue an unlimited number of Class “A” redeemable Preferred Shares
and an unlimited number of Class “B” Preferred Shares. There are currently no outstanding Class “A”
redeemable Preferred Shares or Class “B” Preferred Shares.
A total of 2,753,000 Warrants are outstanding as at December 31, 2024, entitling the holder to purchase one
Common Share of Bonterra for each Warrant at a price of $7.75, until October 20, 2025.
The Company provides a stock option plan for its directors, officers and employees. Under the plan, the
Company may grant options for up to 3,732,488 (December 31, 2023 – 3,725,325) common shares. The
exercise price of each option granted will not be lower than the market price of the common shares on the
date of grant and the option’s maximum term is five years.
For additional information regarding warrants and options outstanding, see Note 13 of the December 31,
2024, audited annual financial statements.
Quarterly Financial Information
The fluctuations in the Company’s revenue and net earnings from quarter-to-quarter are caused by variations
in production volumes, realized commodity pricing and the related impact on royalties, production, G&A and
finance costs.
Issued and fully paid - common shares
Number
Amount
($ 000s)
Number
Amount
($ 000s)
Balance, beginning of year
37,253,252
783,185
36,912,892
781,679
Issued pursuant to the Company's share option plan
71,628
50
340,360 596
Transfer from contributed surplus to share capital
131
910
Balance, end of year
37,324,880
783,366
37,253,252
783,185
December 31, 2024
December 31, 2023
For the periods ended
($ 000s except $ per share)
Q4
Q3
Q2
Q1
Revenue - oil and gas sales
69,699
69,204
72,465
68,589
Cash flow from operations
28,587
31,531
33,180
21,654
Net earnings (loss)
(2,213)
4,258
7,310
848
Per share - basic
(0.06)
0.11
0.20
0.02
Per share - diluted
(0.06)
0.11
0.20
0.02
2024
For the periods ended
($ 000s except $ per share)
Q4
Q3
Q2
Q1
Revenue - oil and gas sales
81,739
84,909
75,606
77,263
Cash flow from operations
44,596
37,715
33,854
24,018
Net earnings
14,973
13,486
8,844
7,640
Per share - basic
0.40
0.36
0.24
0.21
Per share - diluted
0.40
0.36
0.24
0.20
2023
29 | Page
Contractual Obligations and Commitments
At December 31, 2024, the Company has the following contractual obligations and commitments:
(1) Principal amount.
Off-Balance Sheet Financing
Bonterra does not have any guarantees or off-balance sheet arrangements that have been excluded from
the annual statement of financial position or balance sheet other than commitments disclosed in Note 17 of
the December 31, 2024 audited annual financial statements.
Critical Accounting Estimates
There have been no changes to the Company’s critical accounting policies and estimates as of the period
ended in the financial statements.
Assessment of Business Risk
Bonterra’s exploration and production activities are concentrated in the Western Canadian Sedimentary
Basin, where activity is highly competitive and includes a variety of different sized companies. Bonterra is
subject to a number of risks that are also common to other organizations involved in the oil and gas industry.
Such risks include finding and developing oil and gas reserves at economic costs; estimating amounts of
recoverable reserves; production of oil and gas in commercial quantities; marketability of oil and gas
produced; fluctuations in commodity prices; stock market volatility; debt servicing which may limit the market
price of shares; financial and liquidity risks; environmental and safety risks; failure to realize benefits of
acquisitions and dispositions; reliance on third party gathering, processing and pipeline systems; changes to
applicable royalty regimes and environmental legislation and regulations; cyber security risks; and reliance
on key personnel.
The Company mitigates its risk related to producing hydrocarbons through the utilization of hedging a portion
of product sales, current technology and information systems. In addition, Bonterra strives to operate the
majority of its properties, thereby maintaining operational control where possible.
Additional information regarding risk factors including, but not limited to, business risks is available in the
Company’s Annual Information Form for the year ended December 31, 2024, which can be accessed on its
website www.bonterraenergy.com or on SEDAR+ at www.sedarplus.ca.
Environmental Risk
General Risks
Oil and gas exploration and production can involve environmental risks such as litigation, physical and
regulatory risks. Physical risks include the pollution of the environment, climate change and destruction of
natural habitats, as well as safety risks such as personal injury or damage to production facilities and
($ 000s)
Less than
1 year
Over 1 year
to 3 years
Over 3 years
to 5 years
Over 5 years
to 7 years
Total
Accounts payable and
accrued liabilities
36,371
-
-
-
36,371
Bank debt
-
46,211
-
-
46,211
Subordinated debentures
(1)
59,000
-
-
-
59,000
Subordinated term debt
(1)
19,000
38,000
-
-
57,000
Future interest
9,921
3,231
-
-
13,152
Firm service commitments
1,824
2,866
1,601
149
6,440
Office lease commitments
518
475
-
-
993
Total
126,634
90,783
1,601
149
219,167
30 | Page
equipment. The Company conducts its operations while ensuring it protects the environment, various
stakeholders, and the general public.
Bonterra maintains current insurance coverage for comprehensive and general liability as well as limited
pollution liability. The amount and terms of this insurance are reviewed on an ongoing basis and adjusted as
necessary to reflect current corporate requirements, availability, as well as industry standards and
government regulations. Without such insurance, and if the Company becomes subject to environmental
liabilities, the payment of such liabilities could reduce or eliminate its available funds or could exceed the
funds the Company has available and result in financial distress.
Climate Change Risks
Bonterra’s exploration and production facilities and other operations and activities emit greenhouse gasses
("GHG") which require the Company to comply with Federal and/or Provincial GHG emissions legislation.
Climate change policy is evolving at regional, national and international levels, and political and economic
events may significantly affect the scope and timing of climate change measures that are ultimately put in
place to prevent climate change or mitigate Bonterra’s effects.
The direct or indirect costs of compliance with GHG-related regulations may have a material adverse effect
on the Company’s business, financial condition, results of operations and prospects. Some of its significant
facilities may ultimately be subject to future regional, Provincial and/or Federal climate change regulations
to manage GHG emissions. In addition, climate change has been linked to long-term shifts in climate patterns
and extreme weather conditions, both of which pose the risk of causing operational difficulties.
Additional information regarding risk factors including, but not limited to, environmental risks is available in
the Company’s Annual Information Form for the year ended December 31, 2024, which can be accessed on
its website at www.bonterraenergy.com or on SEDAR+ at www.sedarplus.ca.
Forward-Looking Information
Certain statements contained in this MD&A 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 MD&A includes, but is not limited to: estimated production; cash flow
sensitivity to commodity price variables; earnings sensitivity to interest rates; abandonment and reclamation
activities and targets; expected cash provided by continuing operations; return of capital strategy; 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; maintenance of existing customer, supplier and
partner relationships; supply channels; accounting policies; 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; the impact on the Canadian energy industry of U.S. tariffs, changes to international trade
agreements or the potential imposition of tariffs or other protectionist economic policies by the Canadian
federal or provincial governments; applicable environmental, taxation and other laws and regulations as well
as how such laws and regulations may limit growth or operations within the oil and gas industry; the impact
of climate-related financial disclosures on financial results; the ability of the Company to raise capital,
maintain its syndicated bank facility and refinance indebtedness upon maturity; 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; credit risks;
31 | Page
climate change risks; cyber security; opportunities available to or pursued by us; and other factors, many of
which are beyond our control. The foregoing factors are not exhaustive.
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 therefrom. 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.
Disclosure Controls and Procedures
Disclosure controls and procedures (“DC&P”), as defined in National Instrument 52-109 Certification of
Disclosure in Issuers’ Annual and Interim Filings, are designed to provide reasonable assurance that
information required to be disclosed in the Company’s annual filings, interim fillings or other reports filed, or
submitted by the Company under securities legislation is recorded, processed, summarized and reported
within the time periods specified under securities legislation and include controls and procedures designed
to ensure that information required to be disclosed is accumulated and communicated to management,
including the Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions
regarding required disclosure. The Chief Executive Officer and Chief Financial Officer of Bonterra evaluated
the effectiveness of the design and operation of the Company’s DC&P. Based on that evaluation, the Chief
Executive Officer and the Chief Financial Officer concluded that Bonterra’s DC&P were effective at
December 31, 2024.
Internal Controls Over Financial Reporting
Internal control over financial reporting (“ICFR”), as defined in National Instrument 52-109, includes those
policies and procedures that:
1. Pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect transactions
and dispositions of Bonterra;
2. Are designed to provide reasonable assurance that transactions are recorded as necessary to permit
preparation of financial statements in accordance with generally accepted accounting principles and
that receipts and expenditures of Bonterra are being made in accordance with authorizations of
management and Directors of Bonterra; and
3. Are designed to provide reasonable assurance regarding prevention or timely detection of authorized
acquisition, use, or disposition of the Company’s assets that could have a material effect on the financial
statements.
The CEO and CFO have designed, or caused to be designed under their supervision, ICFR as defined in
National Instrument 52-109 of the Canadian Securities Administrators, in order to provide reasonable
assurance regarding the reliability of financial reporting and the preparation of financial statements for
external purposes in accordance with IFRS. The control framework the Company used to design its ICFR
was in accordance with the Committee of Sponsoring Organizations of the Treadway Commission (COSO
2013).
The Company’s CEO and CFO have evaluated, or caused to be evaluated under their supervision, the
effectiveness of the Company’s internal controls over financial reporting at the financial period end of the
Company and concluded that such internal controls over financial reporting are effective as of December 31,
2024.
It should be noted that while Bonterra’s CEO and CFO believe that the Company’s internal controls and
procedures provide a reasonable level of assurance and are effective, they do not expect that these
controls will prevent all errors and fraud.
Use of Non-IFRS Financial Measures
This MD&A contains financial measures and uses the terms “capital expenditures”, “funds flow”, “net debt”,
“EBITDA”, “net debt to EBITDA”, “field netback” and “cash netback” which are not prescribed by IFRS as
issued by the International Accounting Standards Board (“IFRS Accounting Standards”). These specified
financial measures include non-IFRS financial measures and non-IFRS ratios and are not defined by IFRS
32 | Page
Accounting Standards, and therefore are referred to as non-IFRS and other financial measures. These non-
IFRS and other financial measures are included because management uses the information to analyze
business performance, cash flow generated from the business, leverage and liquidity, resulting from the
Corporation’s principal business activities and it may be useful to investors on the same basis. None of these
measures are used to enhance the Corporation’s reported financial performance or position. The non-IFRS
and other measures do not have a standardized meaning prescribed by IFRS Accounting Standards and
therefore are unlikely to be comparable to similar measures presented by other issuers. They are common
in the reports of other companies but may differ by definition and application in Bonterra’s financial
information.
Please see below for a brief overview of non-IFRS measures and the relevant descriptions and
reconciliations.
Funds Flow
Funds flow is a non-IFRS financial measure, calculated as cash flow from operating activities including
proceeds from sale of investments and investment income received excluding effects of changes in non-
cash working capital items and decommissioning expenditures settled. Management uses funds flow to
determine the cash generated during a period.
The following is a reconciliation of funds flow to the most directly comparable IFRS measure, cash flow
from operating activities:
Net Debt
Net debt is a non-IFRS financial measure, calculated as long-term subordinated term debt, subordinated
debentures and bank debt plus working capital deficiency (current liabilities less current assets). This metric
is used by management to analyze the level of debt in the Corporation including the impact of working capital,
which varies with the timing of settlement of these balances.
The following is a reconciliation of net debt to the most directly comparable IFRS measures:
($ 000s except $ per share)
December 31,
2024
September 30,
2024
December 31,
2023
December 31,
2024
December 31,
2023
Cash flow from operations
28,587
31,531
44,596
114,952
140,183
Adjusted for
Changes in non-cash working capital
(2,106)
(2,581)
(8,143)
(5,297)
(1,609)
Interest expense
(4,314)
(4,423)
(4,564)
(17,821)
(19,715)
Interest paid
5,642
3,095
5,891
17,821
19,715
Decommissioning expenditures
2,245
2,384
2,542
7,239
8,291
Investment income received
46
60
120
326
440
Proceeds on sale of investments
- - -
1,448
-
Funds Flow
30,100
30,066
40,442
118,668
147,305
$ per share - basic
0.81
0.81
1.09
3.18
3.96
Three months ended
Year ended
As at
As at
($ 000s)
December 31,
2024
December 31,
2023
Bank debt
46,211 14,822
Subordinated debentures
55,872 52,585
Subordinated term debt (long-term)
35,750 53,018
Current liabilities
(1)
61,389 62,175
Current Assets
(32,012) (37,160)
Net Debt
167,210
145,440
33 | Page
(1) Included in current liabilities is $19.0 million (December 31, 2023 - $19.0 million) of Subordinated Term Debt due in the next twelve
months.
EBITDA
EBITDA is a non-IFRS financial measure. EBITDA is a measure showing net earnings excluding deferred
consideration, finance costs, provision for current and deferred taxes, depletion and depreciation, share-
option compensation, gain or loss on sale of assets, impairment or impairment reversal and unrealized gain
or loss on risk management contracts. Management uses these measures to measure the Corporation’s
profitability generated by operations.
The following is a reconciliation of EBITDA to the most directly comparable IFRS measure, net earnings
(loss):
Net Debt to EBITDA
Net debt to EBITDA is a non-IFRS ratio. Net debt to EBITDA is calculated as net debt divided by EBITDA for
the trailing twelve months. This measure provides management with an indication of the Corporation’s
leverage and ability to repay debt.
Capital Expenditures
Capital expenditures are a non-IFRS financial measure. They are calculated as the sum of exploration and
evaluation costs and property, plant, and equipment costs per the statement of cash flow. Management uses
this metric to assess the total cash capital expenditures incurred during the period.
Field Netback and Cash Netback
Field netback is defined as revenue and realized risk management contract gain (loss) minus royalties and
operating expenses divided by total BOEs for the period. Cash netback is defined as field netback less
interest expense, general and administrative expense and current income tax expense divided by total BOEs
for the period.
($ 000s)
December 31,
2024
December 31,
2023
Net earnings
10,203
44,943
Adjustments to net earnings:
Unrealized gain on risk management contracts
1,525 (1,559)
Deferred consideration
(958) (1,009)
Finance costs
26,532 28,437
Share-option compensation
2,293 3,228
Depletion and depreciation
97,137 90,479
Impairment (reversal of impairment)
- -
Current income tax expense
5,167 11,134
Deferred income tax expense
(1,513)
3,300
EBITDA
140,386
178,953
Net debt to EBITDA ratio
1.2
0.8
Twelve months ended
34 | Page
Management’s Responsibility for Financial Statements
The information provided in this report, including the financial statements, is the responsibility of
management. The timely preparation of the financial statements requires that management make estimates
and use judgment regarding the reported amounts of assets and liabilities and disclosures of contingent
assets and liabilities as at the date of the financial statements and the reported amounts of revenues and
expenses during the period. Such estimates primarily relate to unsettled transactions and events as at the
date of the financial statements. Accordingly, actual results may differ from estimated amounts as future
confirming events occur. Management believes such estimates have been based on careful judgments and
have been properly reflected in the accompanying financial statements.
Management maintains a system of internal controls to provide reasonable assurance that the Company’s
assets are safeguarded and to facilitate the preparation of relevant and timely information.
Deloitte LLP has been appointed by the Shareholders to serve as the Company’s external auditors. They
have examined the financial statements and provided their auditor’s report. The audit committee has
reviewed these financial statements with management and the auditors, and has reported to the Board of
Directors. The Board of Directors has approved the financial statements as presented in this annual report.
“Signed Patrick G. Oliver”
“Signed Scott A. Johnston”
Patrick G. Oliver
Scott A. Johnston
Chief Executive Officer
Chief Financial Officer
March 13, 2025
March 13, 2025
35 | Page
INDEPENDENT AUDITOR’S REPORT
To the Shareholders of Bonterra Energy Corp.
Opinion
We have audited the financial statements of Bonterra Energy Corp. (the “Company”), which comprise the
statements of financial position as at December 31, 2024 and 2023, and the statements comprehensive
income, cash flow and changes in equity for the years then ended, and notes to the financial statements,
including a summary of significant accounting policies (collectively referred to as the “financial statements”).
In our opinion, the accompanying financial statements present fairly, in all material respects, the financial
position of the Company as at December 31, 2024 and 2023, and its financial performance and its cash
flows for the years then ended in accordance with International Financial Reporting Standards (“IFRS”).
Basis for Opinion
We conducted our audit in accordance with Canadian generally accepted auditing standards (“Canadian
GAAS”). Our responsibilities under those standards are further described in the Auditor’s Responsibilities for
the Audit of the Financial Statements section of our report. We are independent of the Company in
accordance with the ethical requirements that are relevant to our audit of the financial statements in Canada,
and we have fulfilled our other ethical responsibilities in accordance with these requirements. We believe
that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our opinion.
Key Audit Matters
Key audit matters are those matters that, in our professional judgment, were of most significance in our audit
of the financial statements for the year ended December 31, 2024. These matters were addressed in the
context of our audit of the financial statements as a whole, and in forming our opinion thereon, and we do
not provide a separate opinion on these matters.
Property, Plant and Equipment - Oil and gas properties - Refer to Notes 4 and 6 to the
financial statements
Key Audit Matter Description
The Company’s property, plant and equipment includes oil and gas properties. Oil and gas properties are
measured by depleting the assets on a unit-of-production basis (“depletion”) and are evaluated for
impairment and impairment reversal using the future net cash flows of the underlying proved plus probable
crude oil and natural gas reserves. The Company engages an independent reserve evaluator to estimate
crude oil and natural gas reserves using estimates, assumptions and engineering data. The development of
the Company’s reserves and the related future net cash flows used to evaluate any impairment or impairment
reversal requires management to make significant estimates and assumptions related to crude oil and natural
gas prices, discount rates, reserves, and future costs.
Given the significant judgments made by management related to future crude oil and natural gas prices,
discount rates, reserves, and future operating and development costs, these estimates and assumptions are
subject to a high degree of estimation uncertainty. Auditing these estimates and assumptions required
auditor judgement in applying audit procedures and in evaluating the results of those procedures. This
resulted in an increased extent of audit effort.
How the Key Audit Matter Was Addressed in the Audit
Our audit procedures related to future crude oil and natural gas prices, discount rates, reserves, and future
operating and development costs used to measure oil and gas properties included the following, among
others:
•
Evaluated future crude oil and natural gas prices by independently developing a reasonable range
of forecasts based on reputable third-party forecasts and market data and comparing those to the
future crude oil and natural gas prices selected by management.
•
Evaluated the reasonableness of the discount rates by testing the source information underlying the
determination of the discount rates and developing a range of independent estimates and comparing
those to the discount rates selected by management.
•
Evaluated the Company’s independent reserve evaluator by examining reports and assessed their
36 | Page
scope of work and findings; and assessing the competence, capability and objectivity by evaluating
their relevant professional qualifications and experience.
•
Evaluated the reasonableness of reserves by testing the source financial information underlying the
reserves and comparing the reserve volumes to historical production volumes.
•
Evaluated the reasonableness of future operating and development costs by testing the source
financial information underlying the estimate, comparing future operating and development costs to
historical results, and evaluating whether they are consistent with evidence obtained in other areas
of the audit.
•
Performed a retrospective review to evaluate management’s ability to accurately forecast and to
assess for indications of estimation bias over time.
Other Information
Management is responsible for the other information. The other information comprises:
●
Management’s Discussion and Analysis
●
The information, other than the financial statements and our auditor’s report thereon, in the Annual
Report.
Our opinion on the financial statements does not cover the other information and we do not and will not
express any form of assurance conclusion thereon. In connection with our audit of the financial statements,
our responsibility is to read the other information identified above and, in doing so, consider whether the
other information is materially inconsistent with the financial statements or our knowledge obtained in the
audit, or otherwise appears to be materially misstated.
We obtained Management’s Discussion and Analysis prior to the date of this auditor’s report. If, based on
the work we have performed on this other information, we conclude that there is a material misstatement of
this other information, we are required to report that fact in this auditor’s report. We have nothing to report in
this regard.
The Annual Report is expected to be made available to us after the date of the auditor’s report. If, based on
the work we will perform on this other information, we conclude that there is a material misstatement of this
other information, we are required to report that fact to those charged with governance.
Responsibilities of Management and Those Charged with Governance for the Financial
Statements
Management is responsible for the preparation and fair presentation of the financial statements in
accordance with IFRS, and for such internal control as management determines is necessary to enable the
preparation of financial statements that are free from material misstatement, whether due to fraud or error.
In preparing the financial statements, management is responsible for assessing the Company’s ability to
continue as a going concern, disclosing, as applicable, matters related to going concern and using the going
concern basis of accounting unless management either intends to liquidate the Company or to cease
operations, or has no realistic alternative but to do so.
Those charged with governance are responsible for overseeing the Company’s financial reporting process.
Auditor’s Responsibilities for the Audit of the Financial Statements
Our objectives are to obtain reasonable assurance about whether the financial statements as a whole are
free from material misstatement, whether due to fraud or error, and to issue an auditor’s report that includes
our opinion. Reasonable assurance is a high level of assurance, but is not a guarantee that an audit
conducted in accordance with Canadian GAAS will always detect a material misstatement when it exists.
Misstatements can arise from fraud or error and are considered material if, individually or in the aggregate,
they could reasonably be expected to influence the economic decisions of users taken on the basis of these
financial statements.
As part of an audit in accordance with Canadian GAAS, we exercise professional judgment and maintain
professional skepticism throughout the audit. We also:
37 | Page
●
Identify and assess the risks of material misstatement of the financial statements, whether due to fraud
or error, design and perform audit procedures responsive to those risks, and obtain audit evidence that
is sufficient and appropriate to provide a basis for our opinion. The risk of not detecting a material
misstatement resulting from fraud is higher than for one resulting from error, as fraud may involve
collusion, forgery, intentional omissions, misrepresentations, or the override of internal control.
●
Obtain an understanding of internal control relevant to the audit in order to design audit procedures that
are appropriate in the circumstances, but not for the purpose of expressing an opinion on the
effectiveness of the Company’s internal control.
●
Evaluate the appropriateness of accounting policies used and the reasonableness of accounting
estimates and related disclosures made by management.
●
Conclude on the appropriateness of management’s use of the going concern basis of accounting and,
based on the audit evidence obtained, whether a material uncertainty exists related to events or
conditions that may cast significant doubt on the Company’s ability to continue as a going concern. If we
conclude that a material uncertainty exists, we are required to draw attention in our auditor’s report to
the related disclosures in the financial statements or, if such disclosures are inadequate, to modify our
opinion. Our conclusions are based on the audit evidence obtained up to the date of our auditor’s report.
However, future events or conditions may cause the Company to cease to continue as a going concern.
●
Evaluate the overall presentation, structure and content of the financial statements, including the
disclosures, and whether the financial statements represent the underlying transactions and events in a
manner that achieves fair presentation.
We communicate with those charged with governance regarding, among other matters, the planned scope
and timing of the audit and significant audit findings, including any significant deficiencies in internal control
that we identify during our audit.
We also provide those charged with governance with a statement that we have complied with relevant ethical
requirements regarding independence, and to communicate with them all relationships and other matters
that may reasonably be thought to bear on our independence, and where applicable, related safeguards.
From the matters communicated with those charged with governance, we determine those matters that were
of most significance in the audit of the financial statements of the current period and are therefore the key
audit matters. We describe these matters in our auditor's report unless law or regulation precludes public
disclosure about the matter or when, in extremely rare circumstances, we determine that a matter should not
be communicated in our report because the adverse consequences of doing so would reasonably be
expected to outweigh the public interest benefits of such communication.
The engagement partner on the audit resulting in this independent auditor’s report is Christopher Gill.
“Signed Deloitte LLP”
Chartered Professional Accountants
Calgary, Alberta
March 13, 2025
38 | Page
STATEMENT OF FINANCIAL POSITION
See accompanying notes to these financial statements.
On behalf of the Board:
“Signed Patrick G. Oliver”
“Signed Stacey E. McDonald”
Patrick G. Oliver
Stacey E. McDonald
Director
Director
As at
($ 000s)
Note
Assets
Current
Accounts receivable
25,778
25,364
Crude oil inventory
885
893
Prepaid expenses
4,517
6,912
Risk management contracts
17
832
2,357
Investments
-
1,634
32,012
37,160
Exploration and evaluation assets
5
6,787
5,785
Property, plant and equipment
6
936,244
924,925
975,043
967,870
Liabilities
Current
Accounts payable and accrued liabilities
7
36,371
37,226
Subordinated term debt
10
19,000
19,000
Decommissioning liabilities
11
5,161
5,040
Deferred consideration
857
909
61,389
62,175
Bank debt
8
46,211
14,822
Subordinated debentures
9, 19
55,872
52,585
Subordinated term debt
10, 19
35,750
53,018
Deferred consideration
7,265
8,170
Decommissioning liabilities
11
98,677
118,068
Deferred tax liability
12
129,240
130,774
434,404
439,612
Shareholders' equity
Share capital
13
783,366
783,185
Contributed surplus
36,185
34,023
Warrants
13
6,053
6,053
Accumulated other comprehensive income
-
436
Deficit
(284,965)
(295,439)
540,639
528,258
975,043
967,870
Subsequent events
17, 19
Commitments and contingencies
18
December 31,
2024
December 31,
2023
39 | Page
STATEMENT OF COMPREHENSIVE INCOME
See accompanying notes to these financial statements.
For the years ended December 31
($ 000s, except $ per share)
Note
2024
2023
Revenue
Oil and gas sales, net of royalties
14
240,315
273,113
Other income
756
1,560
Deferred consideration
958
1,009
Gain on risk management contracts
17
2,044
3,360
244,073
279,042
Expenses
Production
89,881
83,064
Office and administration
5,262
5,245
Employee compensation
9,111
9,212
Finance costs
16
26,532
28,437
Share-option compensation
2,293
3,228
Depletion and depreciation
6
97,137
90,479
230,216
219,665
Earnings before income taxes
13,857
59,377
Taxes
Current income tax expense
12
5,167
11,134
Deferred income tax expense (recovery)
12
(1,513)
3,300
3,654
14,434
Net earnings for the year
10,203
44,943
Other comprehensive loss
Unrealized loss on investments
(186)
(394)
Deferred taxes on unrealized loss on investments
21
46
Realized gains on available for sale investments
transferred to net earnings
(306)
-
Deferred taxes on realized gains on available for sale
investments transferred to net earnings
35
-
Other comprehensive loss for the year
(436)
(348)
Total comprehensive income for the year
9,767
44,595
Net earnings per share - basic
13
0.27
1.21
Net earnings per share - diluted
13
0.27
1.20
Comprehensive income per share - basic
13
0.26
1.20
Comprehensive income per share - diluted
13
0.26
1.19
40 | Page
STATEMENT OF CASH FLOW
See accompanying notes to these financial statements.
For the years ended December 31
($ 000s)
Note
2024
2023
Operating activities
Net earnings
10,203
44,943
Items not affecting cash
Deferred income tax recovery
(1,513)
3,300
Share-option compensation
2,293
3,228
Investment income
(326)
(440)
Finance costs
26,532
28,437
Unrealized (gain) loss on risk management contracts
17
1,525
(1,559)
Deferred consideration
(958)
(1,009)
Depletion and depreciation
6
97,137
90,479
Gain on sale of property
(178)
(17)
Government grant in-kind
-
(782)
Decommissioning expenditures
(7,239)
(8,291)
Interest paid
16
(17,821)
(19,715)
Changes in non-cash working capital accounts
16
5,297
1,609
Cash provided by operating activities
114,952
140,183
Financing activities
Increase (decrease) of bank debt
8
31,389
(2,779)
Subordinated term debt
10
(19,000)
(20,193)
Stock option proceeds
50
596
Cash provided by (used in) financing activities
12,439
(22,376)
Investing activities
Investment income received
326
440
Exploration and evaluation expenditures
(1,190)
(1,222)
Property, plant and equipment expenditures
6
(99,886)
(125,256)
Oil and gas property acquisition
6
(23,586)
-
Proceeds on sale of property
105
28
Proceeds on sale of investments
1,448
-
Changes in non-cash working capital accounts
16
(4,608)
8,203
Cash used in investing activities
(127,391)
(117,807)
Net change in cash in the year
-
-
Cash, beginning of year
-
-
Cash, end of year
-
-
The following are included in cash flow from operating activities:
Income taxes paid
7,007
9,625
41 | Page
STATEMENT OF CHANGES IN EQUITY
(1) All amounts reported in Contributed Surplus relate to share-option compensation.
(2) Accumulated other comprehensive income is comprised of unrealized gains and losses on investments fair value through other
comprehensive income.
See accompanying notes to these financial statements.
For the years ended
($ 000's, except number of shares outstanding)
Numbers of
common
shares
outstanding
(Note 13)
Share
capital
(Note 13)
Contributed
surplus (1)
Warrants
Accumulated
other
comprehensive
income (loss)(2)
Deficit
Total
shareholders'
equity
January 1, 2023
36,912,892
781,679
31,705
6,053
784
(340,382)
479,839
Share-option compensation
3,228
3,228
Exercise of options
340,360
596
596
Transfer to share capital on
exercise of options
910
(910)
-
Comprehensive income (loss)
(348)
44,943
44,595
December 31, 2023
37,253,252
783,185
34,023
6,053
436
(295,439)
528,258
Share-option compensation
2,293
2,293
Exercise of options
71,628
50
50
Transfer to share capital on
exercise of options
131
(131)
-
Comprehensive income (loss)
(165)
10,203
10,038
Transfer on realized gain on
investments, net of tax
(271)
271
-
December 31, 2024
37,324,880
783,366 36,185 6,053
-
(284,965)
540,639
42 | Page
NOTES TO THE FINANCIAL STATEMENTS
As at and for the years ended December 31, 2024 and December 31, 2023.
1. NATURE OF BUSINESS AND SEGMENT INFORMATION
Bonterra Energy Corp. (“Bonterra” or the “Company”) is a public company listed on the Toronto Stock
Exchange (the “TSX”) and incorporated under the Business Corporations Act (Alberta). The address of the
Company’s registered office is Suite 901, 1015-4th Street SW, Calgary, Alberta, Canada, T2R 1J4. The
common shares of the Company (the “Common Shares”) are listed for trading on the TSX under the symbol
“BNE”.
Bonterra operates in one industry and has only one reportable segment which is the development and
production of oil and natural gas in the Western Canadian Sedimentary Basin.
2. BASIS OF PREPARATION AND FUTURE OPERATIONS
a)
Statement of Compliance
These financial statements have been prepared by management in accordance with International Financial
Reporting Standards (IFRS®) as issued by the International Accounting Standards Board (IASB®).
The financial statements were authorized for issue by the Company’s Board of Directors on March 13, 2025.
b)
Basis of Measurement
These financial statements have been prepared on a historical cost basis, except for certain financial
instruments and share-based payment transactions which are measured at fair value.
c)
Functional and Presentation Currency
The Company’s functional and presentation currency is the Canadian dollar.
Foreign currency denominated monetary assets and liabilities are translated into Canadian dollars at the
rates prevailing on the reporting date. Non-monetary assets and liabilities are translated into Canadian
dollars at the rates prevailing on the transaction dates. Exchange gains and losses are recorded as income
or expense in the period in which they occur.
d)
Material Accounting Estimates and Judgments
The timely preparation of financial statements requires management to make estimates and assumptions
that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as
at the date of the statement of financial position as well as the reported amounts of revenues, expenses and
cash flows during the periods presented. Such estimates relate primarily to unsettled transactions and events
as of the date of the financial statements. Actual results could differ materially from estimated amounts. See
Note 4 for more information.
e)
Adopted Accounting Pronouncements
Amendments to IAS 1 - Classification of liabilities as current or non-current
On January 1, 2024 the Company adopted the scope amendments to IAS 1 – “Presentation of Financial
Statements” to clarify that liabilities are classified as either current or non-current, depending on the existence
of the substantive right at the end of the reporting period for an entity to defer settlement of the liability for at
least twelve months after the reporting period. There was no material impact to Bonterra’s financial
statements from its adoption.
43 | Page
Amendments to IFRS 16 – Leases – Lease Liability in a Sale and Leaseback
On January 1, 2024 the Company adopted amendments to IFRS 16 – Leases “Lease Liability in a Sale and
Leaseback” transactions, that specify the requirement that a seller-lessee uses in its subsequent
measurement of the lease liability in a sale and leaseback transaction to ensure the seller-lessee does not
recognize any amount of the gain or loss that relates to the right of use it retains. There was no material
impact to Bonterra’s financial statements from its adoption.
f)
Future Accounting Pronouncements
IFRS 18 – Presentation and Disclosure in Financial Statements
On April 9, 2024 the IASB issued IFRS 18, “Presentation and Disclosure in Financial Statements” (“IFRS
18”), which will replace International Accounting Standard 1, “Presentation of Financial Statements”. IFRS
18 will establish a revised structure for the Consolidated Statements of Comprehensive Income (Loss) and
improve comparability across entities and reporting periods. IFRS 18 is effective for annual periods beginning
on or after January 1, 2027, with early adoption permitted. The standard is to be applied retrospectively, with
certain transition provisions. The Company is currently evaluating the impact of adopting IFRS 18 on its
financial statements.
3. MATERIAL ACCOUNTING POLICIES
a) Revenue Recognition
Revenue associated with the sale of crude oil, natural gas and natural gas liquids is measured based on the
consideration specified in contracts with customers. Revenue from contracts with customers is recognized
when or as Bonterra satisfies a performance obligation by transferring a promised good or service to a
customer. A good or service is transferred when the customer obtains control of that good or service. The
transfer of control of oil, natural gas, and natural gas liquids usually coincides with title passing to the
customer and the customer taking physical possession. The Company principally satisfies its performance
obligations at a point in time and the amounts of revenue recognized relating to performance obligations
satisfied over time are not significant. Collection of revenue associated with the sale of crude oil, natural gas
and natural gas liquids occurs on or about the 25th of the month following production. Items such as royalties
for Crown, freehold, gross overriding (GORR) and Saskatchewan surcharge are netted against revenue.
These items are netted to reflect the deduction for other parties’ proportionate share of the revenue.
Administration fee income is recorded when services are provided.
b) Joint Arrangements
Certain exploration, development and production activities are conducted jointly with others. These financial
statements reflect only the Company’s interests in such activities. A jointly controlled operation involves the
use of assets and other resources of the Company and those of other joint venture participants through
contractual arrangements rather than through the establishment of a corporation, partnership or other entity.
The Company has no interests in jointly controlled entities. The Company recognizes in its financial
statements its interest in assets that it owns, the liabilities and expenses that it incurs, and its share of income
earned by the joint arrangement.
c) Inventories
Inventories consist of crude oil. Crude oil stored in the Company’s tanks is valued on a first-in, first-out basis
at the lower of cost or net realizable value. The inventory cost for crude oil is determined based on the
combined average per barrel operating costs, and depletion and depreciation for the period, while net
realizable value is determined based on estimated sales price less transportation costs.
d) Investments
Investments consist of equity securities. The Company’s investments are measured as fair value through
other comprehensive income (“FVTOCI”), with gains or losses arising from changes in fair value recognized
in other comprehensive income and accumulated in the fair value instrument. The cumulative gain or loss
will not be reclassified to profit or loss on disposal of the investments. Fair value is determined by multiplying
the period end trading price of the investments by the number of common shares held as at period end.
44 | Page
e) Exploration and Evaluation Assets
General exploration and evaluation (“E&E”) expenditures incurred prior to acquiring the legal right to explore
are charged to expense as incurred.
E&E expenditures represent undeveloped land costs, licenses and exploration well costs.
Undeveloped land costs, licenses and exploration well costs are initially capitalized and, if subsequently
determined to have not found sufficient reserves to justify commercial production, are charged to expense.
E&E assets continue to be capitalized as long as sufficient progress is being made to assess the reserves
and economic viability of the asset. Once technical feasibility and commercial viability has been established,
E&E assets are transferred to property, plant and equipment (“PP&E”). E&E assets are assessed for
impairment annually, upon transfer to PP&E assets or whenever indications of impairment exist to ensure
they are not at amounts above their recoverable amounts.
f)
Property, Plant and Equipment
PP&E assets include transferred-in E&E costs, development drilling and other subsurface expenditures.
PP&E assets are carried at cost less depletion and depreciation of all development expenditures and include
all other expenditures associated with PP&E assets.
Oil and Gas Properties
The initial cost of an asset is comprised of its purchase price or construction cost, including expenditures
such as drilling costs; the present value of the initial and changes in the estimate of any decommissioning
obligation associated with the asset; and finance charges on qualifying assets that are directly attributable
to bringing the asset into operation and to its present location.
Production Facilities
Production facilities are comprised of costs related to petroleum and natural gas plant and production
equipment.
Leases
Leases or contractual obligations are capitalized as right of use assets (“ROUs”) with a corresponding right
of use lease obligation using the present value of future lease payments on the statement of financial
position. The discount rate used to determine the ROU is the stated rate in the lease contract. If no discount
rate is provided, the Company’s incremental borrowing rate is used. Certain lease payments will continue to
be expensed in the statement of comprehensive income. These leases are contractual obligations that
contain any of the following: are equal to or less than twelve months; are for oil and gas extraction; are
variable payments; the Company does not control the asset; or no asset is identified in the lease.
Depletion and Depreciation
Depletion and depreciation is recognized in the statement of comprehensive income (loss).
PP&E properties, excluding surface costs are depleted using the unit-of-production method over their proved
plus probable developed reserve life, when commercial production in an area has commenced. Proved plus
probable developed reserves are determined annually by qualified independent reserve engineers. Changes
in factors such as estimates of proved plus probable developed reserves that affect unit-of-production
calculations are accounted for on a prospective basis. Surface costs such as production facilities and
furniture, fixtures and other equipment are depreciated over their estimated useful lives.
Production facilities, furniture, fixtures and other equipment are depreciated over the individual assets
estimated economic lives, less estimated salvage value of the assets at the end of their useful lives.
These assets are depreciated as follows:
Production facilities
Declining balance method at 10 percent per year
Furniture, fixtures and other equipment
Declining balance method at 10 to 20 percent per year
Right of use assets
Straight line method over the term of the associated lease
45 | Page
g) Impairment of Assets
Impairment of Financial Assets
A financial asset is considered to be impaired if objective evidence indicates that one or more events have
had a negative effect on the estimated future cash flow of that asset. An impairment loss in respect of a
financial asset measured at amortized cost is calculated as the difference between its carrying amount and
the present value of the estimated future cash flow discounted at the original effective interest rate. Significant
financial assets are tested for impairment on an individual basis. The remaining financial assets are assessed
collectively in groups that share similar credit risk characteristics.
All impairment losses are recognized in net earnings. An impairment loss is reversed if there is an indicator
that the impairment reversal can be related objectively to an event occurring after the impairment loss was
recognized. Any subsequent recovery of an impairment loss in respect of an investment in an equity
instrument classified as FVTOCI is reversed through other comprehensive income instead of net earnings.
For financial assets measured at amortized cost, the reversal is recognized in net earnings.
Impairment of Non-Financial Assets
The carrying amounts of the Company's non-financial assets are reviewed at the end of each reporting period
to determine whether there is any indication of impairment. If such indication exists, then the assets’ carrying
amounts are assessed for impairment.
For the purpose of impairment testing, assets (which include E&E, PP&E and goodwill) are grouped together
into the smallest group of assets that generate cash flows from continuing use which are largely independent
of the cash flow of other assets or groups of assets (the cash-generating unit or “CGU”). Goodwill is allocated
to the CGU expected to benefit from the synergies of the combination. The recoverable amount of an asset
or a CGU is the greater of its value-in-use (“VIU”) and its fair value less costs to sell (“FVLCS”). The Company
has a core CGU composed of its Alberta properties and secondary CGUs for its British Columbia (BC) and
Saskatchewan properties.
An impairment loss is recognized if the carrying amount of an asset or its CGU exceeds its recoverable
amount. Impairment losses are recognized in the statement of comprehensive income (loss). Impairment
losses recognized in respect of a CGU are allocated first to reduce the carrying amount of any goodwill
allocated to the CGU and then to reduce the carrying amount of the other assets of the CGU on a pro-rata
basis.
In respect of assets other than goodwill, impairment losses recognized in prior periods are assessed at each
reporting date for any indications that the impairment loss has reversed. If the amount of the impairment loss
reverses in a subsequent period and the reversal can be objectively related to an event occurring after the
impairment was recognized, the impairment loss is reversed only to the extent that the asset's carrying
amount does not exceed the carrying amount that would have been determined, net of depletion and
depreciation, if no impairment loss had been recognized and recorded in the statement of comprehensive
income (loss). An impairment loss in respect of goodwill cannot be reversed.
h) Deferred Consideration
Deferred consideration is generated when a sale of a royalty interest linked to production at a specific
property occurs. Consideration is given to the specific terms of each arrangement to determine whether a
disposal of an interest in the reserves of the respective property has occurred and whether the counterparty
is entitled to the associated risks and rewards attributable to the property over its estimated life. These
include the contractual terms and implicit obligations related to production, such as the holder of the royalty
having the option of either being paid in cash or in kind and the associated commitments, if any, to develop
future expansions or projects at the property.
Proceeds for sale of a royalty interest on petroleum properties are then attributed to two components: a
payment for partial disposal of an interest in PP&E; and an upfront payment received for future extraction
services that will generate future royalties. Discounted future cash flows of future development and operating
costs multiplied by the royalty rate are used to derive the upfront payment received for future extraction
services, which is accounted for as deferred consideration and recognized as revenue over the reserve life
46 | Page
of the encumbered properties (as this represents the efforts incurred towards the extraction performance
obligation). Upon commencement of the royalty interest the deferred consideration is depleted (recognized
into revenue) using the same unit-of-production method as the depletion of the encumbered PP&E asset’s
carrying value.
i)
Decommissioning Liabilities
The fair value of the statutory, contractual, constructive or legal liabilities associated with the retirement and
reclamation of oil and gas properties is recorded when incurred, with a corresponding increase to the carrying
amount of the related PP&E. The amount recognized is the estimated cost of decommissioning, discounted
to its present value using the Company’s risk-free rate. Changes in the estimated timing of decommissioning
or decommissioning cost estimates and changes to the risk-free rates are dealt with prospectively by
recording an adjustment to the decommissioning liabilities, and a corresponding adjustment to PP&E. The
unwinding of the discount on the decommissioning provision is charged to net earnings as a finance cost.
The Company recognizes a decommissioning liability in the period in which it is incurred when a reasonable
estimate of the liability can be made. On a periodic basis, management will review these estimates and
changes and if there are any, they will be applied prospectively. The fair value of the estimated provision is
recorded as a long-term liability, with a corresponding increase in the carrying amount of the related asset.
The capitalized amount is depleted on a unit-of-production basis over the life of the proved plus probable
developed reserves. The liability amount is increased each reporting period due to the passage of time and
this amount is charged to earnings in the period. Actual costs incurred upon settlement of the obligations are
charged against the provision to the extent of the liability recorded and any remaining balance of actual costs
is recorded in the statement of comprehensive income (loss).
j)
Income Taxes
Tax expense comprises current and deferred taxes. Tax is recognized in the statement of comprehensive
income (loss) or directly in equity.
Current tax expense is based on the results for the period as adjusted for items that are not taxable or not
deductible. Current tax is calculated using tax rates and laws that are substantively enacted at the end of the
reporting period. Management periodically evaluates positions taken in tax returns with respect to situations
in which applicable tax regulation is subject to interpretation. Provisions are established where appropriate
on the basis of amounts expected to be paid to the tax authorities.
Deferred tax is recognized using the liability method, providing for unused tax losses, unused tax credits and
temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes
and the amounts used for taxation purposes. Deferred tax is not recognized for the following temporary
differences: the initial recognition of assets and liabilities in a transaction that is not a business combination
and that affects neither accounting nor taxable profit, and differences relating to investments in subsidiaries
to the extent that they are unlikely to be reversed in the foreseeable future. Deferred tax is measured at the
tax rates that are expected to be applied to the temporary differences when they reverse, based on the laws
that have been enacted or substantively enacted by the reporting date.
A deferred tax asset is recognized to the extent that it is probable that future taxable profits will be available
against which unused tax losses, unused tax credits and temporary differences can be utilized. Deferred tax
assets are reviewed at each period end and are reduced to the extent that it is no longer probable that the
related tax benefit will be realized.
The amount and timing of reversals of temporary differences will also depend on the Company’s future
operating results, and acquisitions and dispositions of assets and liabilities. A significant change in any of
the preceding assumptions could materially affect the Company’s estimate of the deferred income tax asset
or liability.
k) Share-option Compensation
The Company accounts for share-option compensation using the fair-value method of accounting for stock
options granted to directors, officers, employees and other service providers using the Black-Scholes option
pricing model. Share-option payments are recognized through the statement of comprehensive income (loss)
over the vesting period with a corresponding amount reflected in contributed surplus in equity. For awards
47 | Page
issued in tranches that vest at different times, the fair value of each tranche is recognized over its respective
vesting period.
At the grant date and at the end of each reporting period, the Company assesses and re-assesses for
subsequent periods its estimates of the number of awards that are expected to vest and recognizes the
impact of the revisions in the statement of comprehensive income (loss). Upon exercise of share-based
options, the proceeds received net of any transaction costs and the fair value of the exercised share-based
options is credited to share capital.
Employees may elect to have the Company settle any or all options vested and exercisable using a cashless
equity settlement. In connection with any such exercise, an employee shall be entitled to receive, without
any cash payment (other than the taxes required to be paid in connection with the exercise), whole shares
of the Company. The number of shares under option multiplied by the difference of the fair value at the time
of exercise less the option exercise price, divided by the fair value at the time of exercise, determines the
number of whole shares issued.
l)
Financial Instruments
The Company classifies its financial instruments into one of the following categories: financial assets at
amortized cost, financial liabilities at amortized costs; and fair value through profit or loss. All financial
instruments are measured at fair value on initial recognition. Measurement in subsequent periods is
dependent on the classification of the respective financial instrument.
Fair value through profit or loss financial instruments are subsequently measured at fair value with changes
in fair value recognized in net earnings. All other categories of financial instruments are measured at
amortized cost using the effective interest rate method.
Cash, account receivables and certain other long-term assets are classified as financial assets at amortized
cost since it is the Company’s intention to hold these assets to maturity and the related cash flows are mainly
payments of principle and interest. The Company’s investments are measured at FVTOCI, with gains or
losses arising from changes in fair value recognized in other comprehensive income and accumulated in the
fair value instrument. The cumulative gain or loss will not be reclassified to profit or loss on disposal of the
investments. Accounts payable, accrued liabilities, and certain other long-term liabilities and long-term debt
are classified as financial liabilities at amortized cost. Risk management assets and liabilities are classified
as fair value through profit or loss.
m) Fair Value Measurement
Financial instruments consisting of accounts receivable, accounts payable and accrued liabilities, due to
related party, subordinated promissory note, subordinated term debt and bank debt on the statement of
financial position are carried at amortized cost. Investments are carried at fair value. All of the investments
are transacted in active markets. Bonterra determines the fair value of these transactions according to the
following hierarchy based on the amount of observable inputs used to value the instrument.
Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting
date. Active markets are those in which transactions occur in sufficient frequency and volume to provide
pricing information on an ongoing basis.
Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1. Prices in Level 2
are either directly or indirectly observable as of the reporting date. Level 2 valuations are based on inputs,
including quoted forward prices for commodities, time value and volatility factors, which can be substantially
observed or corroborated in the marketplace.
Level 3 – Valuations in this level are those with inputs for the asset or liability that are not based on observable
market data.
Bonterra’s investments have been assessed on the fair value hierarchy described above and are all
considered Level 1.
48 | Page
n) Risk Management Contracts
The Company is exposed to market risks resulting from fluctuations in commodity prices, foreign currency
exchange rates and interest rates in the normal course of its business. The Company may use a variety of
instruments to manage these exposures. For transactions where hedge accounting is not applied, the
Company accounts for such instruments using the fair value method by initially recording an asset or liability
and recognizing changes in the fair value of the instruments in earnings as unrealized gains or losses on risk
management contracts. Fair values of financial instruments are based on third party quotes or valuations
provided by independent third parties. Any realized gains or losses on risk management contracts are
recognized in net earnings in the period they occur. Bonterra’s risk management contracts have been
assessed on the fair value hierarchy described above and are all considered Level 2.
o) Net Earnings and Comprehensive Income Per Share
Per share amounts are calculated by dividing the net earnings or comprehensive income (loss) attributable
to common shareholders of the Company by the weighted average number of common shares outstanding
during the reporting period.
Diluted per share amounts are calculated similar to basic per share amounts except that the weighted
average common shares outstanding are increased to include additional common shares from the assumed
exercise of dilutive share-options. The number of additional outstanding common shares is calculated by
assuming that the outstanding in-the-money share-options were exercised and that the proceeds from such
exercises were used to acquire common shares at the average market price during the reporting period.
4. SIGNIFICANT ACCOUNTING ESTIMATES AND JUDGMENTS
Estimates and underlying assumptions are reviewed on an ongoing basis. Revisions to accounting estimates
are recognized in the year in which the estimates are revised and in any future years affected. The following
are the estimates and judgments applied by management that most significantly affect the Company’s
financial statements.
Exploration and Evaluation Expenditures
E&E costs are initially capitalized with the intent to establish commercially viable reserves. E&E assets
include undeveloped land and costs related to exploratory wells. The Company is required to make estimates
and judgments about future events and circumstances regarding the future economic viability of extracting
the underlying resources. Changes to project economics, resource quantities, expected production
techniques, unsuccessful drilling, expired mineral leases, production costs and required capital expenditures
are important factors when making this determination. To the extent a judgment is made that the underlying
reserves are not viable, the E&E costs will be impaired and charged to net earnings.
Impairment of Non-Financial Assets
PP&E and goodwill are aggregated into CGUs based on their ability to generate largely independent cash
flows and are assessed for impairment or in the case of PP&E impairment reversals. CGUs have been
determined based on similar geological structure, shared infrastructure, geographical proximity, commodity
type, and similar market risks. Oil and gas prices and other assumptions will change in the future, which may
impact the Company’s recoverable amounts and may therefore require a material adjustment to the carrying
value of PP&E. The determination of the Company's CGUs is subject to management's judgment. The
Company has a core CGU composed of its Alberta properties and secondary CGUs for its BC and
Saskatchewan properties.
The recoverable amount of E&E and PP&E, is determined based on the fair value less costs of disposal
using a discounted cash flow model and is assessed at the CGU level. The period the Company used to
project cash flows is approximately 50 years or the CGUs reserve life. Growth in cash flow from a single well
would be determined based on the extent of total reserves assigned, which is produced at declining rates
over the estimated reserve life. The fair value measurement of the Company’s E&E and PP&E, is designated
Level 3 on the fair value hierarchy.
49 | Page
The Company performs an impairment test on all of its CGUs for any potential impairment or related recovery
at least annually or when impairment or recovery indicators arise. In making these evaluations, the Company
uses the following information:
1) The net present value of the pre-tax cash flows from oil and gas reserves of each CGU based on
total proved plus probable reserves estimated by the Company’s independent reserve evaluator;
and
2) Key input estimates used in the determination of cash flows from oil and gas reserves include the
following:
a) Reserves - Assumptions that are valid at the time of reserve estimation may change significantly
when new information becomes available. Changes in forward price estimates, production costs
or recovery rates may change the economic status of reserves and may ultimately result in
reserves being revised.
b) Crude oil and natural gas prices - Forward price estimates of the crude oil and natural gas prices
are used in the discounted cash flow model. These prices are adjusted for quality differentials,
heat content and distance to market. Commodity prices have fluctuated widely in recent years
due to global and regional factors including supply and demand fundamentals, inventory levels,
exchange rates, weather, economic and geopolitical factors.
c) Discount rate - The Company uses a pre-tax discount rate of fifteen percent that reflects risks
specific to the assets for which the future cash flow estimates have not been adjusted. The
discount rate was determined based on the Company’s assessment of risk based on past
experience. Changes in the general economic environment could result in material changes to
this estimate.
No indicators of impairment or impairment reversal were identified at December 31, 2024.
Reserves Estimation
The capitalized costs of oil and gas properties and deferred consideration are depleted on a unit-of-
production basis at a rate calculated by reference to proved plus probable developed reserves determined
in accordance with National Instrument 51-101 and the Canadian Oil and Gas Evaluation handbook.
Commercial reserves are determined using best estimates of oil and gas in place, recovery factors and future
oil and gas prices. Amounts used for impairment calculations are also based on estimates of crude oil and
natural gas reserves and future costs required to develop those reserves.
Risk Management Contract
The Company accounts for such instruments using the fair value method by initially recording an asset or
liability, and recognizing changes in the fair value of the instruments in net earnings as unrealized gains or
losses on risk management contracts. Fair values of financial instruments are based on third party futures
quotes for commodities. Any realized or unrealized gains or losses on risk management contracts are
recognized in net earnings in the period they occur.
Share-option Compensation
The Company measures the cost of equity-settled transactions with employees by reference to the fair value
of the equity instruments at the date they are granted. Estimating the fair value requires the determination of
the most appropriate valuation model for a grant, which is dependent on the terms and conditions of the
grant. This also requires the determination of the most appropriate inputs to the valuation model including
the expected life of the option, risk-free interest rates, volatility and dividend yield.
Deferred Consideration
50 | Page
Deferred consideration is incurred when the sale of a royalty interest occurs that has contractual terms or
implicit obligations that requires future performance such future development costs and operating costs.
Management uses judgments in determining those cash flows such as cost, inflation and the discount rate
to determine the portion of proceeds that is deferred.
Decommissioning and Restoration Costs
Decommissioning and restoration costs will be incurred by the Company at the end of the operating lives of
the Company’s oil and gas properties. Provisions for decommissioning liabilities are based on cost estimates
which can vary in response to many factors including timing of abandonment, inflation, changes in legal
requirements, new restoration techniques and interest rates.
Income Taxes
The Company recognizes the net deferred tax benefit or expense related to deferred income tax assets or
liabilities to the extent that it is probable that the deductible temporary differences will reverse in the
foreseeable future. Assessing the recoverability of investment tax credit receivable requires the Company to
make significant estimates related to expectations of future taxable income. The provision for income taxes
is based on judgments in applying income tax law and estimates of the timing, likelihood and reversal of
temporary differences between the accounting and tax basis of assets and liabilities. The ability to realize on
the deferred tax assets and investment tax credit receivable recorded on the balance sheet may be
compromised to the extent that any interpretation of tax law is challenged, or taxable income differs
significantly from estimates.
Further details regarding accounting estimates and judgments are disclosed in Note 3.
5. EXPLORATION AND EVALUATION ASSETS
($ 000s)
Cost and carrying amount
Balance at January 1, 2023
4,563
Additions
1,222
Balance at December 31, 2023
5,785
Additions
1,190
Disposal of exploration and evaluation assets
(188)
Balance at December 31, 2024
6,787
51 | Page
6. PROPERTY, PLANT AND EQUIPMENT
Asset Acquisition of Oil and Natural Gas Property
On March 1, 2024, the Company acquired the Charlie Lake assets for cash consideration of $23.6 million
and $0.3 million in non-core mineral rights, including closing adjustments (the “Charlie Lake Asset
Acquisition”). This acquisition has been accounted for as an asset acquisition, which resulted in a $24.2
million increase in PP&E and the assumption of $0.3 million in decommissioning liabilities.
Impairment
There were no indicators of impairment losses or reversals identified for the year ended December 31, 2024
and December 31, 2023.
7. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES
Cost
($ 000s)
Oil and gas
properties
Production
facilities
Furniture
fixtures &
other
equipment
Total
property
plant &
equipment
Balance at January 1, 2023
1,542,394
415,183
2,461
1,960,038
Additions
93,907
30,948
401
125,256
Disposal
-
-
(51)
(51)
Adjustment to decommissioning liabilities
19,212
-
-
19,212
Balance at December 31, 2023
1,655,513
446,131
2,811
2,104,455
Additions
62,417
37,368
101
99,886
Acquisition
19,354
4,880
-
24,234
Adjustment to decommissioning liabilities
(15,586)
-
-
(15,586)
Disposal
-
(282)
-
(282)
Balance at December 31, 2024
1,721,698
488,097
2,912
2,212,707
Accumulated depletion and depreciation
($ 000s)
Oil and gas
properties
Production
facilities
Furniture
fixtures &
other
equipment
Total
property
plant &
equipment
Balance at January 1, 2023
(889,826)
(197,318)
(2,002)
(1,089,146)
Depletion and depreciation
(72,615)
(17,728)
(136)
(90,479)
Disposal and other
54
-
41
95
Balance at December 31, 2023
(962,387)
(215,046)
(2,097)
(1,179,530)
Depletion and depreciation
(77,485)
(19,534)
(118)
(97,137)
Disposal and other
2
202
-
204
Balance at December 31, 2024
(1,039,870)
(234,378)
(2,215)
(1,276,463)
Carrying amounts as at:
($ 000s)
December 31, 2023
693,126
231,085
714
924,925
December 31, 2024
681,828
253,719
697
936,244
($ 000s)
December 31,
2024
December 31,
2023
Accounts payable
24,294
30,625
Accrued liabilities
12,077
6,601
36,371
37,226
52 | Page
8. BANK DEBT
As at December 31, 2024 the Company had a total Bank Facility of $110,000,000 (December 31, 2023 -
$110,000,000), comprised of a $85,000,000 syndicated revolving credit facility, and a $25,000,000 non-
syndicated revolving credit facility. The amount drawn under the total Bank Facility at December 31, 2024
was $46,211,000 (December 31, 2023 - $14,822,000). The amounts borrowed under the total Bank Facility
bear interest at a floating rate based on the applicable Canadian prime rate or Banker’s Acceptance rate,
plus between 2.00 percent and 7.00 percent, depending on the type of borrowing and the Company’s
consolidated debt to EBITDA ratio. EBITDA is defined as net income for the twelve-month trailing period
excluding finance costs, provision for current and deferred taxes, depletion and depreciation, share-option
compensation, gain or loss on sale of assets and impairment of assets. As at December 31, 2024, the terms
of the total revolving Bank Facility provided that the loan facility was revolving to April 30, 2025, with a
maturity date of April 30, 2026, with no set terms of repayment on the credit facility.
The amount available for borrowing under the Bank Facility is reduced by outstanding letters of credit. Letters
of credit totaling $1,990,000 were issued as at December 31, 2024 (December 31, 2023 - $2,130,000).
Security for the Bank Facility consists of various floating demand debentures totaling $750,000,000
(December 31, 2023 - $750,000,000) over all of the Company’s assets and a general security agreement
with first ranking over all personal and real property.
Financial Covenants
The Company is subject to certain financial covenants under its Bank Facility and Subordinated Term Debt
facility as follows:
Consolidated debt to trailing twelve months EBITDA ratio shall not exceed 2.50:1.00; and
Asset coverage ratio of not less that 1.50:1.
Asset coverage ratio is defined as the proved developed producing reserves of the Company (before income
tax; discounted at 10 percent), as evaluated by an independent third-party engineering report as at
December 31, 2024 and evaluated on strip commodity pricing, divided by the consolidated debt of the
Company. The ratio is calculated and revaluated for strip pricing on June 30 and December 31 period ends.
As at December 31, 2024, Bonterra was in compliance with all financial covenants on its Bank Facility.
9. SUBORDINATED DEBENTURES
As at December 31, 2024 the Company has a total of 59,000 senior unsecured subordinated debenture units
outstanding. Each Unit is comprised of: (i) one senior unsecured debenture with a par value of $1,000 per
note and bearing interest at 9.0 percent per annum, payable semi-annually; and (ii) 56 common share
purchase warrants of Bonterra (“Warrants”). The debentures mature on October 20, 2025 and all or a portion
of the principal amount outstanding can be repaid without penalty after October 20, 2024, however, all
interest due to the maturity date must be paid. A total of 3,304,000 Warrants were issued, entitling the holder
to purchase one common share of Bonterra for each Warrant at a price of $7.75, until October 20, 2025. In
2024 $5,310,000 of interest was paid, (December 31, 2023 - $5,310,000).
The unsecured subordinated debentures were determined to be a compound instrument with a debt and
equity component. Based on the calculated fair value of the debentures, the effective interest rate was
determined on issuance to be 15.6 percent using the effective interest rate method, by discounting future
payments of interest and principal with the residual value allocated to Warrants and issue costs. The value
of the debt will accrete up to the principal balance at maturity. For more information about Warrants please
see Note 13.
The Company's subordinated debentures are classified as non-current liabilities as of December 31, 2024.
This classification is supported by the sufficient availability under the Company’s bank facility, which allows
provides the ability to refinance or defer repayment beyond the next financial year, ensuring the debentures
do not require settlement within that period.
On February 26, 2025, the Company fully repaid the subordinated debentures as described in Note 19.
53 | Page
10. SUBORDINATED TERM DEBT
As at December 31, 2024 the Company has a second lien, non-revolving subordinated term debt facility
(“Subordinated Term Debt”). The amount drawn under the Subordinated Term Debt at December 31, 2024
was $57,000,000 (December 31, 2023 - $76,000,000). The amounts borrowed under the Subordinated Term
Debt bear interest at a fixed rate of 11.70 percent to be applied to 25 percent of the term facility principle and
a floating interest rate of Canadian Prime Rate plus 6.25 percent on the remaining 75 percent of the principal
amount. The Company is required to make mandatory principal repayments equal to $4.75 million, payable
on the last banking day of February, May, August and November of each calendar year, commencing on
February 28, 2023. The term debt has a maturity date of November 30, 2026, upon which the remaining
outstanding principle balance is to be paid.
Based on the calculated fair value of the Subordinated Term Debt as at December 31, 2024, the effective
interest rate was determined to be 15.1 percent using the effective interest rate method. The effective interest
rate was calculated by discounting future payments of interest and principal with the residual value allocated
to issue costs of $6,310,000. The value of the debt will accrete up to the principal balance at maturity. Interest
paid in 2024 was $8,541,000 (December 31, 2023 - $11,046,000).
Security for the Subordinated Term Debt consists of various floating demand debentures totaling
$150,000,000 (December 31, 2023 - $150,000,000) over all of the Company’s assets and a general security
agreement with second ranking over all personal and real property.
As at December 31, 2024, Bonterra was in compliance with all financial covenants on its second lien
Subordinated Term Debt facility (as described in Note 9).
On January 28, 2025 the Company fully repaid the subordinated term debt as described in Note 19.
11. DECOMMISSIONING LIABILITIES
At December 31, 2024, the estimated total uninflated and undiscounted amount required to settle the
decommissioning liabilities was $179,396,000 (December 31, 2023- $176,425,000). The provision has been
calculated assuming a 2.0 percent inflation rate (December 31, 2023 – 2.0 percent inflation rate). These
obligations will be settled at the end of the useful lives of the underlying assets, which extend up to 50 years
into the future. This amount has been discounted using a risk-free interest rate of 3.45 percent (December
31, 2023 – 2.87 percent).
(1) The change is estimate was primarily due to an increase in estimated costs less a decrease in the discount rate.
(2) Included in liabilities settled is $444,000 of abandonment deposits (December 31, 2023 - $2,455,000).
($ 000s)
December 31,
2024
December 31,
2023
Decommissioning liabilities, January 1
123,108
109,215
Changes in estimate
(1)
(15,279)
19,212
Liabilities settled during the year
(2)
(7,683)
(8,307)
Government grant in-kind (Note 19)
-
(782)
Accretion on decommissioning liabilities
3,692
3,770
Total decommissioning liabilities, end of year
103,838
123,108
Current portion of decommissioning liabilities
(5,161)
(5,040)
Decommissioning liabilities
98,677
118,068
54 | Page
12. INCOME TAXES
Income tax expense varies from the amounts that would be computed by applying Canadian federal and
provincial tax rates as follows:
The Company has the following tax pools, which may be used to reduce taxable income in future years,
limited to the applicable rates of utilization:
The Company has $64,111,000 (December 31, 2023 - $64,725,000) of capital losses carried forward which
can only be claimed against taxable capital gains.
($ 000s)
December 31,
2024
December 31,
2023
Deferred tax asset (liability) related to:
Investments
-
(75)
(149,093)
(152,653)
Investment tax credits
-
(1,216)
Decommissioning liabilities
24,565
28,899
Share issue costs
715
1,141
Financial derivative
(192)
(543)
Subordinated debenture
(720)
(1,476)
Subordinated term debt
(518)
(916)
Corporate capital tax losses carried forward
7,377
7,448
Unrecorded benefits of capital tax losses carried forward
(7,377)
(7,374)
Unrecorded benefits of successored resource related pools
(3,997)
(4,009)
Deferred tax liability
(129,240)
(130,774)
Exploration and evaluation assets and property, plant and equipment
($ 000s)
December 31,
2024
December 31,
2023
Earnings before taxes
13,857
59,377
Combined federal and provincial income tax rates
23.01%
23.02%
Income tax provision calculated using statutory tax rates
3,189
13,666
Increase (decrease) in taxes resulting from:
Share-option compensation
528
743
Change in unrecorded benefits of tax pools
(9)
45
Change in estimates and other
(54)
(20)
3,654
14,434
($ 000s)
Rate of
Utilization (%)
Amount
Undepreciated capital costs
7-100
78,299
Share issue and financing costs
20
3,109
Canadian oil and gas property expenditures
10
72,605
Canadian development expenditures
30
125,387
Canadian exploration expenditures
100
8,587
287,987
55 | Page
13. SHAREHOLDERS’ EQUITY
Authorized
The Company is authorized to issue an unlimited number of common shares without nominal or par value.
The Company is authorized to issue an unlimited number of Class “A” redeemable Preferred Shares and an
unlimited number of Class “B” Preferred Shares. There are currently no outstanding Class “A” redeemable
Preferred Shares or Class “B” Preferred Shares.
The weighted average common shares used to calculate basic and diluted net earnings per share for the
year ended, are as follows:
(1) The Company did not include 5,720,000 share-options and warrants (December 31, 2023 – 5,496,849) in the dilutive effect of share-
options and warrants calculations as these were anti-dilutive.
Warrants
A summary of the status of warrants issued by the Company as of December 31, 2024 and changes during
the period are presented below:
The Warrants issued entitle the holder to purchase one Common Share of Bonterra for each Warrant at a
price of $7.75, until October 20, 2025.
Options
The Company provides an equity settled option plan for its directors, officers, and employees. Under the
plan, the Company may grant options for up to 3,732,488 (December 31, 2023 – 3,725,325 common shares).
The exercise price of each option granted cannot be lower than the market price of the common shares on
the date of grant and the option’s maximum term is five years.
A summary of the status of the Company’s stock options as of December 31, 2024 and changes during the
year are presented below:
Issued and fully paid - common shares
Number
Amount
($ 000s)
Number
Amount
($ 000s)
Balance, beginning of year
37,253,252
783,185
36,912,892
781,679
Issued pursuant to the Company's share option plan
71,628
50
340,360
596
Transfer from contributed surplus to share capital
131
910
Balance, end of year
37,324,880
783,366
37,253,252
783,185
December 31, 2024
December 31, 2023
2024
2023
Basic shares outstanding
37,302,410
37,197,337
Dilutive effect of share options and warrants
(1)
22,854
134,317
Diluted shares outstanding
37,325,264
37,331,654
Number of
warrants
Weighted
exercise
price
As at December 31, 2024 and December 31, 2023
2,753,000
$7.75
56 | Page
(1) 108,500 options (December 31, 2023 – 247,000) were exercised under the cashless option method, which resulted in 61,628
(December 31, 2023 -140,610) shares being issued in which the Company received no proceeds. Under the cashless option
method, the remaining options between the number of options exercised and shares issued are cancelled.
The following table summarizes information about options outstanding and exercisable as at December 31,
2024:
The Company records compensation expense equally over the annual three-year vesting period, based on
the fair value of options granted to directors, officers and employees. In 2024, the Company granted 147,000
options with an estimated fair value of $198,000 or $1.35 per option using the Black-Scholes option pricing
model with the following key assumptions:
(1) Risk-free interest rate is based on the weighted average Government of Canada benchmark bond yields for one, two, and three
year terms to match corresponding vesting periods.
(2) The expected volatility is measured as the standard deviation of expected share price returns based on statistical analysis of
historical weekly share prices for a representative period.
Number of
options
Weighted
average exercise
price
At January 1, 2023
2,751,750
$6.86
Options granted
1,171,000
5.47
Options exercised
(1)
(446,750)
2.92
Options forfeited
(171,000)
7.81
Options expired
(45,000)
5.18
At December 31, 2023
3,260,000
$6.87
Options granted
147,000
4.81
Options exercised
(1)
(118,500)
2.67
Options forfeited
(145,500)
7.21
Options expired
(37,500)
8.13
At December 31, 2024
3,105,500
$6.90
Range of exercise
prices
Number
outstanding
Weighted-
average
remaining
contractual life
Weighted-
average
exercise price
Number
exercisable
Weighted-
average
exercise price
$ 1.00 - $ 5.00
165,000
3.0 years
$ 4.37
65,000
$ 4.35
5.01 - 10.00
2,910,500
3.1 years
6.99
1,531,955
7.39
10.01 - 15.00
30,000
0.9 years
12.32
15,000
12.32
$ 1.00 - $ 15.00
3,105,500
3.0 years
$ 6.90
1,611,955
$ 7.31
Options outstanding
Options exercisable
December 31, 2024
December 31, 2023
Weighted-average risk free interest rate (%)
(1)
3.46
3.85
Weighted-average expected life (years)
2.0
2.0
Weighted-average volatility (%)
(2)
45.79
55.778
Forfeiture rate (%)
6.15
6.40
57 | Page
14. OIL AND GAS SALES, NET OF ROYALTIES
15. OTHER INCOME
Government Grant In-kind
The Government of Alberta’s Site Rehabilitation Program (“SRP”) provides grant funding through service
providers to abandon or remediate oil and gas sites. The Company derecognized approximately $nil of asset
retirement obligations as an in-kind grant (December 31, 2023 - $782,000). The benefit of the in-kind grant
is recognized through other income.
($ 000s)
December 31,
2024
December 31,
2023
Oil and gas sales
Crude oil
229,249 256,745
Natural gas liquids
26,011
24,212
Natural gas
24,697
38,560
279,957 319,517
Less royalties:
Crown
(27,633)
(32,953)
Freehold, gross overriding
royalties and other
(12,009) (13,451)
(39,642) (46,404)
Oil and gas sales, net of royalties
240,315
273,113
($ 000s)
December 31,
2024
December 31,
2023
Investment income
326
440
Administrative income
252
321
Gain on sale of property and equipment
178 17
Government grant in-kind
-
782
Other income
756
1,560
58 | Page
16. SUPPLEMENTAL CASH FLOW INFORMATION
17. FINANCIAL RISK MANAGEMENT
Financial Risk Factors
The Company undertakes transactions in a range of financial instruments including:
Accounts receivable
Accounts payable and accrued liabilities
Bank debt
Subordinated debentures
Subordinated term debt
The Company’s activities result in exposure to a number of financial risks including market risk (commodity
price risk, interest rate risk, and foreign exchange risk), credit risk and liquidity risk.
The Company’s overall risk management program seeks to mitigate these risks and reduce the volatility on
Bonterra’s financial performance. Financial risk is managed by senior management under the direction of
the Board of Directors.
Bonterra is exposed to credit risk, liquidity risk and market risk as part of its normal course of business. The
Company’s overall risk management program seeks to mitigate these risks and reduce the volatility of
Bonterra’s financial performance. The Company does not speculatively trade in risk management contracts.
($ 000s)
December 31,
2024
December 31,
2023
Change in non-cash working capital:
Accounts receivable
(414)
1,962
Crude oil inventory
7
159
Prepaid expenses
2,395
296
Investment tax credit receivable
-
5,761
Abandonment deposit
(444)
(19)
Accounts payable and accrued liabilities
(855)
1,653
689
9,812
Changes related to:
Operating activities
5,297
1,609
Investing activities
(4,608)
8,203
689
9,812
Finance expense
($ 000s)
December 31,
2024
December 31,
2023
Interest expense:
Bank debt
3,970
3,359
Subordinated debenture
5,310
5,310
Subordinated term debt
8,541
11,046
17,821
19,715
Accretion:
Decommissioning liabilities
3,692
3,770
Subordinated debentures
3,287
2,816
Subordinated term debt
1,732
2,136
8,711
8,722
Total finance costs
26,532
28,437
Interest expense and paid
17,821
19,715
59 | Page
Bonterra’s risk management contracts are entered into in order to manage the risks relating to commodity
prices from its business activities.
Liquidity Risk Management
Liquidity risk is the risk that the Company will encounter difficulty in meeting obligations associated with its
financial liabilities. The Company’s financial performance and position are largely dependent on the
commodity prices received for its oil and natural gas production. Commodity prices have fluctuated widely in
recent years due to crude oil inventory levels, domestic infrastructure constraints, global economic and
geopolitical factors. Bonterra continues to retain available committed borrowing capacity that provides it with
financial flexibility and the ability to meet ongoing obligations as they become due.
After examining the economic factors that are causing the liquidity risk facing the Company, the judgment
applied to these factors, and the various initiatives that Bonterra has and will undertake to strengthen its
financial position, the Company believes it will have sufficient liquidity to support its ongoing operations and
meet its financial obligations as they come due for at least the next twelve months. There can be no
assurance that the next borrowing base redetermination will not result in a borrowing base shortfall, and that
the necessary funds or additional security will be available to eliminate the shortfall. Upon receipt of notice
from the lenders, the shortfall would have to be remedied within 30 days or by such other means as
acceptable to the lenders.
Credit Risk
Credit risk is the risk that a contracting party will not complete its obligations under a financial instrument and
cause the Company to incur a financial loss. Bonterra is exposed to credit risk on all financial assets included
on the statement of financial position. To help mitigate this risk:
•
The Company only enters into material agreements with credit worthy counterparties. These include
major oil and gas companies or major Canadian chartered banks; and
•
Agreements for product sales are primarily on 30-day renewal terms. Of the $25,778,000 accounts
receivable balance at December 31, 2024 (December 31, 2023 - $25,364,000) over 84 percent
(December 31, 2023 – 83 percent) relate to product sales or risk management contracts with national
and international banks and oil and gas companies.
On a quarterly basis, Bonterra assesses if there has been any impairment of the financial assets of the
Company. During the year ended December 31, 2024, there was no material impairment provision required
on any of the financial assets of the Company. Bonterra does have credit risk exposure, as the majority of
the Company’s accounts receivable are with counterparties having similar characteristics. However,
payments from Bonterra’s largest accounts receivable counterparties have consistently been received within
30 days and the sales agreements with these parties are cancellable with 30 days’ notice if payments are
not received.
As at December 31, 2024, approximately $196,000 or 0.8 percent of the Company’s total accounts receivable
are aged over 90 days and considered past due (December 31, 2023 - $591,000 or 2.3 percent). The majority
of these accounts are due from various joint venture partners. Bonterra actively monitors past due accounts
and takes the necessary actions to expedite collection, which can include withholding production or netting
payables when the accounts are with joint venture partners. Should the Company determine that the ultimate
collection of a receivable is in doubt, it will provide the necessary provision in its allowance for doubtful
accounts with a corresponding charge to earnings.
If Bonterra subsequently determines an account is uncollectable, the account is written off with a
corresponding charge to the allowance account. The Company’s allowance for doubtful accounts balance at
December 31, 2024 is $1,733,000 (December 31, 2023 - $1,878,000) with the expense being included in
general and administrative expenses. There were no material accounts written off during the period.
The maximum exposure to credit risk is represented by the carrying amounts of accounts receivable. There
are no material financial assets that Bonterra considers past due.
60 | Page
Capital Risk Management
The Company’s objectives when managing capital, which it defines to include shareholders’ equity, debt and
working capital balances, are to safeguard Bonterra’s ability to continue as a going concern, so that it can
continue to provide returns to its shareholders and benefits for other stakeholders and to maintain a capital
structure that provides a low cost of capital. In order to maintain or adjust the capital structure, the Company
may adjust the current debt structure and/or issue common shares.
The Company monitors its capital structure based on the ratio of net debt (total debt adjusted for working
capital) to EBITDA. This ratio is calculated using each quarter end net debt divided by the preceding twelve
months’ EBITDA. At December 31, 2024, the Company had a net debt to EBITDA level of 1.2:1 as compared
to 0.8:1 as at December 31, 2023. The increase in Bonterra’s net debt to EBITDA ratio is primarily due to an
increase in net debt relating to the Charlie Lake Asset Acquisition and a decrease in EBITDA from lower
commodity prices. To provide cashflow protection the Company has hedged at least 30 percent of its forecasted
oil and natural gas production (net of royalties payable) over the next nine months.
Section (a) of this note provides Bonterra’s net debt to EBITDA ratio.
Section (b) addresses in more detail the key financial risk factors that arise from the Company’s activities,
including its policies for managing these risks.
a) Net debt to EBITDA ratio
The net debt and EBITDA amounts are as follows:
(3) Included in current liabilities is the current portion of the Subordinated Term Debt of $19,000,000 (December 31, 2023 -
$19,000,000).
b) Risks and mitigation
Market risk is the risk that the fair value or future cash flow of the Company’s financial instruments will
fluctuate because of changes in market prices. Components of market risk to which Bonterra is exposed are
discussed below.
Commodity Price Risk
($ 000s)
December 31,
2024
December 31,
2023
Bank debt
46,211
14,822
Subordinated term debt
(1)
35,750
53,018
Subordinated debentures
55,872
52,585
Current liabilities
61,389
62,175
Current assets
(32,012) (37,160)
Net debt
167,210
145,440
Net earnings
10,203
44,943
Adjustments to net earnings:
Unrealized gain on risk management contracts
1,525 (1,559)
Deferred consideration
(958) (1,009)
Finance costs
26,532
28,437
Share-option compensation
2,293
3,228
Depletion and depreciation
97,137
90,479
Current income tax expense
5,167
11,134
Deferred income tax expense
(1,513)
3,300
EBITDA (trailing twelve months)
140,386 178,953
Net debt to EBITDA ratio
1.2
0.8
61 | Page
The Company’s principal operation is the production and sale of crude oil, natural gas and natural gas liquids.
Fluctuations in prices of these commodities directly impact Bonterra’s performance and ability to continue
with its dividends.
The Company has used various risk management contracts to set price parameters for a portion of its
production. Bonterra has assumed the risk in respect of commodity prices, except for a small portion of
physical delivery sales and risk management contracts to manage commodity risk on the Company’s higher
operating cost areas.
Bonterra is exposed to credit risk, liquidity risk and market risk as part of its normal course of business. The
Company’s overall risk management program seeks to mitigate these risks and reduce the volatility of
Bonterra’s financial performance. Financial risk is managed by senior management under a risk
management program approved by the Company’s Board of Directors.
Physical Delivery Sales Contracts
Bonterra enters into physical delivery sales contracts to manage commodity price risk. These contracts are
considered normal executory sales contracts and are not recorded at fair value in the financial statements.
As of December 31, 2024, the Company has the following physical delivery sales contracts in place.
(1)
“WTI” refers to West Texas Intermediate, a grade of light sweet crude oil used as benchmark pricing in the United States.
(2)
"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.
(3)
“MSW differential” is the primary difference between WTI and MSW steam index benchmark pricing.
(4)
“AECO Daily” refers to a grade or heating content of natural gas used as daily index benchmark pricing in Alberta, Canada.
(5)
“AECO Monthly” refers to a grade or heating content of natural gas used as monthly index benchmark pricing in Alberta, Canada.
Subsequent to December 31, 2024, the Company entered into the following physical delivery sales
contracts.
Risk Management Contracts
The Company also enters into financial derivative instruments or risk management contracts to manage
commodity price risk. These contracts are not considered normal executory sales contracts and are
recorded at fair value in the financial statements.
Product
Type of contract
Volume
Gas
Fixed Price - AECO Daily
(4)
2,500 GJ/day
Jan 1, 2025
to Oct 31, 2025
-
2.39
CAD/GJ
Gas
Physical collar - AECO Monthly
(5)
2,500 GJ/day
Apr 1, 2025
to Mar 31, 2026
1.75
to
2.70
CAD/GJ
Contract price ($)
Term
Product
Type of contract
Volume
Gas
Physical collar - AECO Monthly
2,500 GJ/day
Mar 1, 2025
to Dec 31, 2025
1.75
to
2.38
CAD/GJ
Gas
Physical collar - AECO Monthly
4,000 GJ/day
Jul 1, 2025
to Mar 31, 2026
2.00
to
3.20
CAD/GJ
Term
Contract price ($)
($ 000s)
December 31,
2024
December 31,
2023
Risk management contracts
Realized gain
3,569
1,801
Unrealized gain (loss)
(1,525)
1,559
2,044
3,360
62 | Page
As of December 31, 2024, the Company has the following risk management contracts in place.
Subsequent to December 31, 2024, the Company entered into the following risk management contracts.
Interest Rate Risk
Interest rate risk refers to the risk that the value of a financial instrument or cash flows associated with the
instrument will fluctuate due to changes in market interest rates. Interest rate risk arises from interest bearing
financial assets and liabilities that the Company uses. Bonterra’s principal exposure its borrowings which
have a variable interest rate which gives rise to a cash flow interest rate risk.
As of December 31, 2024, the Company’s debt facilities consist of a $85,000,000 syndicated revolving credit
facility, and a $25,000,000 non-syndicated revolving credit facility, $57,000,000 second lien Subordinated
Term Debt and $59,000,000 in senior unsecured subordinated debentures. The borrowings under the total
bank facilities are at bank prime plus or minus various percentages as well as by means of banker’s
acceptances (“BAs”) within Bonterra’s credit facility.
The subordinated debt has a fixed interest rate of 11.7 percent for a quarter of the outstanding balance and
prime plus 6.25 percent for the remaining outstanding balance. Subordinated debentures are at a fixed
interest rate of nine percent. Bonterra manages its exposure to interest rate risk on its floating interest rate
debt through entering into various term lengths on its BAs but in no circumstances do the terms exceed six
months.
Sensitivity Analysis
Based on historic movements and volatilities in the interest rate markets and management’s current
assessment of the financial markets, the Company believes that a one percent variation in the Canadian
prime interest rate is reasonably possible over a 12-month period. A one percent increase (decrease) in the
Canadian prime rate would decrease (increase) both annual net earnings and comprehensive income by
$685,000.
Oil
Financial collar - WTI
500 BBL/day
Jan 1, 2025
to Mar 31, 2025
70.00
to
86.35
USD/BBL
Oil
Financial collar - WTI
500 BBL/day
Jan 1, 2025
to Jun 30, 2025
65.00
to
80.00
USD/BBL
Oil
Financial collar - WTI
500 BBL/day
Jan 1, 2025
to Jun 30, 2025
65.00
to
77.50
USD/BBL
Oil
Financial collar - WTI
500 BBL/day
Jan 1, 2025
to Jun 30, 2025
60.00
to
74.00
USD/BBL
Oil
Financial collar - WTI
500 BBL/day
Jan 1, 2025
to Dec 31, 2025
65.00
to
75.00
USD/BBL
Oil
Financial collar - WTI
500 BBL/day
Jul 1, 2025
to Dec 31, 2025
65.00
to
75.50
USD/BBL
Gas
Financial collar - AECO Monthly
5,000 GJ/day
Jan 1, 2025
to Mar 31, 2025
2.75
to
3.30
CAD/GJ
Gas
Financial collar - AECO Monthly
7,500 GJ/day
Jan 1, 2025
to Jun 30, 2025
1.75
to
2.43
CAD/GJ
Gas
Financial collar - AECO Monthly
5,000 GJ/day
Apr 1, 2025
to Mar 31, 2026
1.75
to
2.70
CAD/GJ
Product
Type of contract
Volume
Oil
Fixed price - MSW stream index
250 BBL/day
Apr 1, 2025
to Dec 31, 2025
71.75
USD/BBL
Oil
Fixed price - MSW differential
500 BBL/day
Apr 1, 2025
to Sep 30, 2025
(5.25)
USD/BBL
Term
Contract price ($)
63 | Page
Foreign Exchange Risk
The Company has no foreign operations and currently sells all of its product sales in Canadian currency.
However, Bonterra is exposed to currency risk in that crude oil is priced in US currency, then converted to
Canadian currency. The Company currently has no outstanding risk management agreements. It will assume
full risk in respect of foreign exchange fluctuations.
18. COMMITMENTS AND FINANCIAL LIABILITIES
Bonterra has the following maturity schedule for its financial liabilities and commitments:
(6) Principal amount.
The Company has entered into firm service gas transportation agreements in which it guarantees certain
minimum volumes of natural gas will be shipped on various gas transportation systems. The terms of the
various agreements expire in one to seven years. The future minimum payment amounts for the firm service
gas transportation agreements are calculated using current tariff rates.
Bonterra also has non-cancellable office lease commitments for building and office equipment. The building
and office equipment leases have an average remaining life of 1.9 years.
19. SUBSEQUENT EVENTS
Subsequent to December 31, 2024, the Company entered into the following transactions:
i) Restructuring of Subordinated Debt
On January 28, 2025, the Company completed a restructuring of its outstanding subordinated debentures
and subordinated term debt through the issuance of senior secured second lien notes.
Issuance of Senior Secured Second Lien Notes
On January 28, 2025, the Company closed a private placement offering of $135 million aggregate
principal amount of Senior Secured Second Lien Notes (the "Notes"). The Notes:
Were issued at $981.16 per $1,000 of principal amount,
Bear interest at an annual rate of 10.50%, payable semi-annually, and
Have a five-year term, maturing on January 28, 2030.
Interest payments of $7.1 million will be made bi-annually on January 28 and July 28, beginning July
28, 2025.
Repayment of Subordinated Term Debt
($ 000s)
Recognized
on
Financial
Statements
Less than
1 year
Over 1 year
to 3 years
Over 3 years
to 5 years
Over 5 years
to 7 years
Total
Accounts payable and
accrued liabilities
Yes - Liability
36,371
-
-
-
36,371
Bank debt
Yes - Liability
-
46,211
-
-
46,211
Subordinated debentures
(1)
Yes - Liability
59,000
-
-
59,000
Subordinated term debt
(1)
Yes - Liability
19,000
38,000
-
-
57,000
Future interest
No
9,921
3,231
-
-
13,152
Firm service commitments
No
1,824
2,866
1,601
149
6,440
Office lease commitments
No
518
475
-
-
993
Total
126,634
90,783
1,601
149
219,167
64 | Page
As part of the restructuring, the Company fully repaid its subordinated term debt on January 28, 2025,
including:
Principal repayment of $57 million,
Accrued and unpaid interest of $0.5 million, and
An early redemption fee of $3.4 million, allocated between finance expenses, transaction and other
costs.
Repayment of Subordinated Debentures
On February 26, 2025, the Company fully repaid its subordinated debentures, including:
Principal repayment of $59 million,
Accrued and unpaid interest of $0.8 million, and
An early redemption fee of $3.5 million, allocated between finance expenses, transaction and other
costs.
ii) Disposal of non-core Saskatchewan Assets
On January 24, 2025, the Company disposed of its non-core Shaunavon Saskatchewan assets for total
consideration of $1.5 million, excluding closing adjustments.
65 | Page
CORPORATE INFORMATION
Board of Directors
D. Michael G. Stewart - Chair
John J. Campbell
David M. Humphreys
Stacey E. McDonald
Patrick G. Oliver
Jacqueline R. Ricci
Officers
Patrick G. Oliver, President & CEO
Scott A. Johnston, CFO & Corporate Secretary
Brad A. Curtis, Senior VP, Business Development
Registrar and Transfer Agent
Odyssey Trust Company
Auditors
Deloitte LLP
Solicitors
Borden Ladner Gervais LLP
Bankers
CIBC
ATB Financial
Business Development Bank of Canada
Head Office
901, 1015 – 4th Street SW
Calgary, Alberta T2R 1J4
Telephone: 403.262.5307
Fax: 403.265.7488
Email: info@bonterraenergy.com
Website
www.bonterraenergy.com
901, 1015 – 4th Street SW
Calgary, Alberta, T2R 1J4
TEL 403.262.5307
FAX 403.265.7488
info@bonterraenergy.com
www.bonterraenergy.com