Record annual production of 15,513 BOE per day, exceeding revised guidance and representing a 5% increase from the prior year
Expanded Charlie Lake core area through the closing of the previously announced Bonanza asset acquisition, consisting of low-decline oil pools producing approximately 760 BOE per day(3) and 21 top-tier drilling locations
Achieved reserves growth across Total Proved ("TP") and Total Proved Plus Probable ("TPP") reserve categories of 3%, underpinning TPP Reserve Life Index of 19.4 years; Reduced TP and TPP F&D costs(2) to $12.72/BOE and $14.93/BOE driving recycle ratios(2) of 2.1x and 1.8x, respectively
Capital spending of $69.9 million, in line with guidance
Adjusted Free Funds Flow(1) of $17.2 million, an increase of 65% versus prior year
Reaffirms 2026 guidance, with annual production expected to range from 16,200 to 16,400 BOE per day(3) and capital expenditures expected to be $75–$80 million
Patrick Oliver, President and Chief Executive Officer, stated: "It's fair to say that 2025 was a breakthrough year for Bonterra, reflecting our focus on disciplined growth. We took several key steps to strengthen both our financial position and our asset base, notably:
Successfully executing our Charlie Lake drilling program, which was the key driver in achieving an annual production record and supported improved capital efficiency;
Completing a strategic acquisition to further expand our Charlie Lake core area, which increased tier-1 drilling inventory;
Continuing delineation drilling in our Montney land base, including successfully drilling our first three-mile horizontal Montney well; and
Increasing the liquidity of the business through our Canadian high-yield debt refinancing transaction."
Mr. Oliver added, "By optimizing our stable Cardium production base and leveraging our high-impact assets in the Charlie Lake and Montney, we were able to deliver record production using significantly less capital. We are currently in the delineation phase on both assets, and with low reserve bookings to date, we see significant resource capture and growth opportunities ahead, creating sustainable long-term value for our shareholders."
2025 Financial and Operating Highlights
Production averaged 15,513 BOE per day during 2025, representing a 5% increase from 14,846 BOE per day in the prior year, which was primarily attributable to the execution of the Company's 2025 drilling program and the Pembina Cardium well reactivation activities completed early in the year. Fourth quarter 2025 volumes averaged 15,254 BOE per day(3).
Funds Flow1 and Adjusted Free Funds Flow1 totaled $94.2 million ($2.57 per fully diluted share) and $17.2 million ($0.47 per fully diluted share) respectively. Funds Flow decreased year over year by 20% primarily driven by decreased crude oil pricing and Adjusted Free Funds Flow increased by 65% despite lower crude oil prices primarily driven by a more efficient capital program in 2025.
Field Netback and Cash Netbacks1 in 2025 averaged $22.05 per BOE and $16.63 per BOE, respectively, with WTI crude oil prices averaging US$64.81 per barrel and AECO natural gas prices averaging $1.67 per mcf in 2025.
Production costs averaged $16.69 per BOE in 2025 compared to $16.54 per BOE in 2024. The marginal increase was primarily driven by initial third-party infrastructure charges related to the Charlie Lake and Montney plays, along with higher activity levels from the Company's well reactivation program.
Capital expenditures totaled $69.9 million in 2025, in line with the Company's previously provided annual capital expenditure guidance of $65 to $70 million:
$41.0 million was allocated to the drilling of 9 gross (8.4 net) operated wells, of which 7 gross (6.5 net) wells were completed, equipped, and tied-in, and to the drilling of 9 gross (1.5 net) non-operated wells. The two (1.9 net) remaining drilled and uncompleted ("DUC") wells have been completed and tied-in during the first quarter of 2026; and
$28.9 million was directed toward land and lease acquisitions, infrastructure, recompletions and compressor upgrades.
Bonanza Asset Acquisition closed on December 18, 2025, for cash consideration of $15.3 million, after closing adjustments:
Low decline base production: Approximately 760 BOE per day3 of existing production in low decline oil pools
Increased area footprint: 41 net sections of land in the Greater Bonanza Area adjacent to existing Charlie Lake operations
Charlie Lake drilling inventory: 21 identified top tier drilling locations complementary to its existing Charlie Lake inventory in addition to 3 low-risk infill locations in the Doig formation
Synergistic infrastructure: Strategic owned and operated infrastructure footprint of underutilized compression, batteries and gathering pipelines creates immediate half cycle drilling opportunities on the acquired lands and proximal existing lands and offers new gas processing optionality in the Greater Bonanza Area
Net Debt1 totaled $179.0 million at year end, representing a net debt to EBITDA level of 1.6:1 as compared to 1.2:1 as at December 31, 2024. The increase in net debt to EBITDA ratio is primarily due to an increase in debt from the Bonanza Asset Acquisition, the one-time costs associated with the debt refinancing transaction and a decrease in EBITDA from lower crude oil prices.
Normal Course Issuer Bid initiated in April, saw the Company repurchase 749,900 common shares for cancellation at an average price of $3.56 per share, representing approximately 2% of the outstanding shares at December 31, 2024.
2025 Financial and Operating Results
As at and for the year ended
December 31, 2025
December 31, 2024
December 31, 2023
($000s except $ per share)
FINANCIAL
Revenue - realized oil and gas sales
247,874
279,957
319,517
Funds flow(1)
94,168
118,668
147,305
Per share - basic
2.57
3.18
3.96
Per share - diluted
2.55
3.18
3.95
Cash flow from operations
89,480
114,952
140,183
Per share - basic
2.44
3.08
3.77
Per share - diluted
2.43
3.08
3.76
Net earnings (loss)(2)
(17,125
)
10,203
44,943
Per share - basic
(0.47
)
0.27
1.21
Per share - diluted
(0.46
)
0.27
1.20
Capital expenditures
69,932
101,076
126,478
Oil and gas property acquisition(3)(4)
16,029
24,234
-
Total assets
959,434
975,043
967,870
Net debt(5)
179,049
167,210
145,440
Bank debt
40,722
46,211
14,822
Shareholders' equity
522,032
540,639
528,258
OPERATIONS
Light oil
-bbl per day
6,415
6,639
7,209
-average price ($ per bbl)
81.24
94.35
97.58
NGLs
-bbl per day
1,511
1,513
1,359
-average price ($ per bbl)
41.61
46.97
48.80
Conventional natural gas
-MCF per day
45,524
40,164
33,814
-average price ($ per MCF)
2.09
1.68
3.12
Total barrels of oil equivalent per day (BOE)(6)
15,513
14,846
14,204
Notes for the table above:
(1)
Funds flow is a non-IFRS measure. See advisories later in this press release.
(2)
Net loss for the year ended December 31, 2025, primarily reflects a one-time debt extinguishment cost of $11.6 million.
(3)
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.
(4)
On December 18, 2025, the Company acquired the Bonanza Assets adjacent to the Company's Charlie Lake area assets for cash considerations of $15.3 million in mineral rights, including closing adjustments. This acquisition has been accounted for as an asset acquisition, which resulted in a $16.0 million increase in PP&E and the assumption of $0.7 million in decommissioning liabilities.
(5)
Net debt is a non-IFRS measure. See advisories later in this press release.
(6)
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.
Operations Update
Charlie Lake
The Company entered 2026 with one three-mile (0.9 net) DUC well and has since drilled an additional 3 (2.8 net) Charlie Lake wells. The DUC well and two of the new Charlie Lake drills have been completed, tied-in and are in the early stages of cleaning up post completion operations, while the third new Charlie Lake well is planned to be completed before the end of March and tied-in early in the second quarter. The Company anticipates having 30-day peak rate on new results in its next quarterly release. Net production from the Charlie Lake asset in December 2025 was approximately 3,660 BOE per day3 representing 23% of December 2025 corporate production.
Montney
The Montney remains a strategic asset in the Company's portfolio for enhancing shareholder value. Based on the strong production results to date from its two operated wells Bonterra has drilled its third Montney well to continue the delineation of its Montney land base. The third well was drilled in Q4 2025 and was completed and tied-in in Q1 of 2026. The well is a three-mile horizontal and was completed with an increased fracture stimulation intensity compared to Bonterra's previous two Montney wells. The new Montney well is in the early stages of cleaning up post completion operations. The Company anticipates having 30-day peak rate results in its next quarterly release. Net production from the Montney asset in December 2025 was approximately 780 BOE per day3 representing 5% of December 2025 corporate production.
2026 Outlook
The Company reaffirms its production and capital guidance for 2026 outlined below:
Annual average production range of 16,200 to 16,400 BOE per day3, weighted approximately 50 to 52% to oil and liquids; and
Capital expenditure range of $75 million to $80 million.
The 2026 capital program is geared to grow corporate production through capital allocation across all three of the Company's assets. Capital directed to the Cardium will further enhance the optimization of the base cash flow stream, and the Charlie Lake and Montney activity is planned to increase production exposure in these plays and to further prove out the value of the resource in these high-impact assets, including testing the new lands from our recent acquisition.
Bonterra remains committed to a disciplined approach to managing leverage levels and will focus use of Free Funds Flow to debt repayment and share buybacks in 2026.
The Company retains capital flexibility for the remainder of the year in response to prevailing commodity price conditions.
To mitigate risk and add stability during periods of market volatility, hedges have been put in place on approximately 48% of Bonterra's expected crude oil and 25% of its natural gas production through the first six months of 2026. Through the first six months of 2026, Bonterra has secured WTI prices between $55.00 USD to $80.95 USD per bbl on 3,044 bbls per day; and natural gas prices between $1.29 to $3.30 per GJ on approximately 12,743 GJ per day.
In addition, Bonterra has secured WTI pricing between $60.00 USD and $66.75 USD per barrel on 2,250 barrels per day, representing 33% of expected crude oil production for the second half of 2026. Natural gas prices averaging $2.76 per GJ for 8,474 GJ per day have also been secured covering the second half of 2026 and the first quarter of 2027, primarily through fixed-price contracts.
2025 Reserves Highlights
The Company is pleased to announce the summary results of its independent reserve report prepared by Sproule International Limited with an effective date of December 31, 2025. The Sproule Report reflects the success of the 2025 capital program driven by the Company's Charlie Lake and Montney resource plays.
The following provides a summary of specific details from the Sproule Report, which was prepared following the guidelines, criteria, and methodologies outlined in the Canadian Oil and Gas Evaluation Handbook ("COGE Handbook") and National Instrument 51-101, Standards of Disclosure for Oil and Gas Activities ("NI 51-101"). Further reserves-related information, as mandated by NI 51-101, will be incorporated into Bonterra's Annual Information Form, to be filed on the Company's profile at www.sedarplus.ca and available on the Company's website.
Reserves increases in TP and TPP categories:
Unchanged year over year - Proved Developed Producing ("PDP") reserves of 34.3 million BOE
3% increase year over year - TP reserves of 87.8 million BOE
3% increase year over year - TPP reserves of 109.7 million BOE
Net present value of future net revenue discounted at 10% (before tax) for TPP totaled $1.2 billion, while TP totaled $859.2 million and PDP totaled $468.5 million
Reserve Life Index ("RLI")2 for TPP, TP, and PDP of approximately 19.4 years, 15.5 years and 6.1 years, respectively (based on 2025 average production of 15,513 BOE per day)
Reserve Replacement2 of 99% of 2025 production on a PDP basis, 150% on a TP basis and 164% on a TPP basis
F&D Costs2 including FDC of $12.72/BOE on TP and $14.93/BOE on TPP
Recycle ratio2 including FDC of 2.1 times on TP reserves, 1.8 times on TPP reserves
Future Development Capital ("FDC") for TP is forecast to be $804 million, an increase of 2% or $18 million compared to 2024 TP FDC of $786 million
Summary of Gross Oil and Gas Reserves as of December 31, 2025
Light and Medium Crude Oil
Conventional Natural Gas
Natural Gas Liquids
Oil Equivalent
Future Development Capital
(MBbl)
(MMcf)
(MBbl)
(MBoe)
($000s)
Proved
Developed Producing
15,418.6
93,403
3,340.3
34,325.9
-
Developed Non-Producing
1,619.3
7,081
247.1
3,046.6
5,681
Undeveloped
23,033.0
137,204
4,547.8
50,448.2
798,583
Total Proved
40,070.9
237,688
8,135.1
87,820.7
804,264
Total Probable
10,001.3
59,240
2,013.1
21,887.6
18,298
Total Proved plus Probable
50,072.2
296,927
10,148.2
109,708.3
822,562
Reconciliation of Company Gross Reserves by Principal Product Type as of December 31, 2025
Light & Medium Crude Oil
Conventional Natural Gas
Natural Gas Liquids
Oil Equivalent
Total Proved
Proved + Probable
Total Proved
Proved + Probable
Total Proved
Proved + Probable
Total Proved
Proved + Probable
(MBbl)
(MBbl)
(MMcf)
(MMcf)
(MBbl)
(MBbl)
(Mboe)
(Mboe)
Opening Balance December 31, 2024
41,438
51,724
214,580
267,790
7,796
9,714
84,997
106,070
Extensions (1)
2,132
2,826
27,437
35,030
790
1,002
7,495
9,666
Acquisitions (2)
762
952
9,605
12,022
196
246
2,559
3,202
Dispositions (3)
(169
)
(218
)
(32
)
(42
)
(0
)
(0
)
(175
)
(226
)
Economic Factors (4)
(834
)
(758
)
(3,251
)
(2,884
)
(127
)
(106
)
(1,503
)
(1,345
)
Technical Revisions (5)
(917
)
(2,112
)
5,965
1,627
32
(156
)
109
(1,997
)
Production
(2,341
)
(2,341
)
(16,616
)
(16,616
)
(551
)
(551
)
(5,662
)
(5,662
)
Closing Balance December 31, 2025
40,071
50,072
237,688
296,927
8,135
10,148
87,821
109,708
Notes for table above:
(1)
Includes the drilling of step-out and infill wells in 2025 and the booking of new step-out future drilling locations.
(2)
Additions in volumes relating to the acquisition of an asset in the Greater Bonanza Area.
(3)
Reduction in volumes due to the selling of non-core assets. In 2025, operated properties in Saskatchewan and Eastern Alberta were divested in their entirety.
(4)
The economic factors reflect the change in reserves due to the changes in the average commodity price forecasts of Sproule, GLJ Petroleum Consultants and McDaniels & Associates Consultants Ltd. for December 31, 2024 compared to December 31, 2025 commodity price forecast.
(5)
Technical revisions are attributable to changes in previously booked estimates. In 2025, positive technical revisions were recorded in developed producing entities, primarily associated with improved well performance, as well as in the majority of pre-booked locations due to improved offset and analogue production performance. Negative technical revisions were recorded in the Montney property related to revisions to pre-booked locations to better align with future development plans and not due to well performance expectations.
(6)
Gross Reserves means the Company's working interest reserves before calculation of royalties and before considerations of the Company's royalty interests.
Summary of Net Present Values of Future Net Revenue as of December 31, 2025
($M)
Net Present Value Before Income Taxes Discounted at (% per year)
Reserves Category:
0%
5%
