Q4 2025 Highlights
Production of 117,715 boe/d (100% liquids)(1)(2)
Operating Earnings of $146 million ($0.68 / share)(1)(3)
Free Cash Flow of $53 million ($0.25 / share)(1)(3)
FY 2025 Highlights
Production of 152,163 boe/d (86% liquids)(1)(2)
Operating Earnings of $930 million ($4.34 / share)(1)(3)
Free Cash Flow of $364 million ($1.70 / share)(1)(3)
YE 2025 Reserves Highlights
Proved Developed Producing ("PDP"), Proved ("1P") and Proved Plus Probable ("2P") reserves of 241 MMboe, 1,226 MMboe and 2,166 MMboe, reflecting growth from continuing operations of 2%, 5%, and 7% respectively
PDP finding and development costs ("PDP F&D")(4), including changes in future development costs ("PDP FDC"), of $21.24 / boe, equating to a 2025 PDP Recycle Ratio(4) of 1.8x; excluding approximately $400 million in capital spending on Meota Central and Cold Lake facility expansions which did not contribute to YE 2025 PDP bookings, PDP F&D was approximately $12.25 / boe, equating to a recycle ratio of 3.1x
297% organic 2P reserves replacement(4); 51 Year 2P Reserves Life Index(4) (29 Years 1P)
1P and 2P after-tax PV-10 net of debt(4) of $32.05 / share and $49.46 / share respectively
Three Months Ended(1)
Year Ended(1)
($ millions, unless otherwise indicated)
December31, 2025
December31, 2024
September30, 2025
December31, 2025
December31, 2024
WTI (US$/bbl)
59.14
70.27
64.93
64.81
75.72
WCS Hardisty (C$/bbl)
66.89
80.75
75.10
75.06
83.53
AECO 5A (C$/gj)
2.11
1.40
0.60
1.59
1.38
Bitumen (bbls/d)
62,538
59,732
61,157
61,327
59,516
Heavy oil (bbls/d)
54,660
50,997
53,943
52,658
51,107
Condensate and light oil (bbls/d)
65
20,763
250
10,339
19,922
Total oil production (bbls/d)
117,263
131,492
115,350
124,324
130,545
Other NGLs (bbls/d)
26
12,980
234
6,051
11,958
Natural gas (mcf/d)
2,558
256,386
3,701
130,729
243,456
Production (boe/d)
117,715
187,203
116,201
152,163
183,080
Sales (boe/d)
116,355
184,120
115,852
152,407
182,794
% Liquids(2)
99.7 %
77.2 %
99.6 %
85.7 %
77.8 %
Oil and natural gas sales, net of blending and
other income(3)
710
1,025
807
3,622
4,255
Royalties
99
209
128
470
663
Production and operating, Energy
65
59
37
237
248
Production and operating, Non-energy
90
139
104
511
564
Transportation and processing
95
144
92
479
577
General and administrative
24
28
22
98
101
Depletion, depreciation and amortization
152
196
151
697
874
Interest and finance costs(4)
39
60
37
200
258
Operating Earnings(3)
146
190
236
930
970
Other items(4)
245
102
(337)
19
366
(Loss) income and comprehensive (loss)
Income
(99)
88
573
911
604
Operating Earnings(3)
146
190
236
930
970
Non-cash items(4)
167
217
165
766
1,074
Loss on risk management and foreign
exchange contracts, realized, operating
(75)
(2)
(18)
(102)
(107)
Funds from Operations(3)
238
405
383
1,594
1,937
Capital expenditures
(176)
(393)
(281)
(1,186)
(1,296)
Decommissioning costs
(9)
(13)
(8)
(44)
(36)
Free Cash Flow(3)
53
(1)
94
364
605
Debt, net of cash and marketable securities(4)
2,095
2,462
(81)
2,095
2,462
Common shares (millions)
214
214
214
214
214
(1)
During the year ended December 31, 2025 the Company entered into three separate asset purchase and sale agreements to dispose of its Montney assets which has been presented in the Company's consolidated financial statements and management's discussion and analysis for the three months and year ended December 31, 2025 and 2024 as discontinued operations. The financial and operating results for these periods have been presented throughout this press release based on the aggregation of continuing and discontinued operations. The aggregation of continuing and discontinued financial results are non-GAAP measures and do not have a standardized meaning under IFRS® Accounting Standards (the "Accounting Standards"); see "Non-GAAP Measures and Ratios" section of this press release.
(2)
See "Product Type Production Information" section of this press release.
(3)
A non-GAAP financial measure which does not have a standardized meaning under the Accounting Standards; see "Non-GAAP Measures and Ratios" section of this press release.
(4)
See "Supplementary Financial Measures" Section of this press release.
Three Months Ended(1)
Year Ended(1)
($/boe, unless otherwise indicated)
December31, 2025
December31, 2024
September30, 2025
December31, 2025
December31, 2024
Oil and natural gas sales, net of blending costs and other income(2)
66.38
60.49
75.74
65.12
63.60
Royalties
9.24
12.31
12.02
8.45
9.91
Production and operating, Energy
6.23
3.46
3.51
4.28
3.71
Production and operating, Non-energy
8.30
8.18
9.79
9.18
8.42
Transportation and processing
8.80
8.51
8.63
8.61
8.62
General and administrative
2.23
1.68
2.06
1.76
1.51
Depletion, depreciation and amortization
14.23
11.59
14.20
12.52
13.06
Interest and finance costs
3.58
3.54
3.44
3.59
3.86
Operating Earnings(2)
13.77
11.22
22.09
16.73
14.51
Effective royalty rate (%)(2)
13.9 %
20.3 %
15.9 %
13.0 %
15.6 %
(1)
During the year ended December 31, 2025 the Company entered into three separate asset purchase and sale agreements to dispose of its Montney assets which has been presented in the Company's consolidated financial statements and management's discussion and analysis for the three months and year ended December 31, 2025 and 2024 as discontinued operations. The financial and operating results for these periods have been presented throughout this press release based on the aggregation of continuing and discontinued operations. The aggregation of continuing and discontinued financial results are non-GAAP measures and do not have a standardized meaning under the Accounting Standards; see "Non-GAAP Measures and Ratios" section of this press release.
(2)
A non-GAAP financial measure which does not have a standardized meaning under the Accounting Standards; see "Non-GAAP Measures and Ratios" section of this press release.
Annual Letter to Strathcona Shareholders
Strathcona has posted a letter to shareholders providing an in-depth review of the Company's 2025 financial and operating performance and year-end reserves, which has been posted on Strathcona's website at strathconaresources.com/investors/reports. Strathcona shareholders are encouraged to review the letter, which provides details regarding the Company's strategy going forward.
Quarter Review and Near-Term Priorities
Strathcona's fourth quarter production of 118 Mboe / d, up 1% quarter-over-quarter, was in-line with expectations, with full year capital expenditures of $1,186 million lower than the Company's 2025 capital budget of $1,200 million. Fourth quarter non-energy production and operating costs of $8.30 / boe reflected a decrease of 15% versus the third quarter, reflecting savings achieved across the portfolio following successful execution of cost improvement initiatives undertaken mid-year. Free cash flow of $53 million for the fourth quarter was impacted by $75 million of realized hedging losses, following the restructuring of the Company's WCS differential swaps at the end of 2025, as previously disclosed. Strathcona's WTI exposure remains unhedged for 2026, with approximately 50% of its WCS Hardisty differential exposure hedged at US$12.00 / bbl, and approximately 80% of its natural gas purchase exposure hedged at C$2.00 / GJ AECO.
In Cold Lake, production increased 2% quarter-over-quarter driven by the continued ramp up of Lower Drainage Wells ("LDWs") on the 105 and 108 pads at Orion. Subsequent to year-end, seven LDWs on the C-East pad were brought online at Tucker, which have exceeded expectations thus far with an average rate of over 750 bbls / d per well. Current activity is focused on the 8 well pair D01 West pad at Lindbergh, which began steaming in early 2026 and is expected to ramp to a peak rate of approximately 6,500 bbls / d.
In Lloydminster Thermal, in December Strathcona closed on its acquisition of the Vawn thermal project ("Vawn") and undeveloped thermal lands at Plover Lake and Glenbogie. Vawn has since been fully incorporated into Strathcona's existing operations at Edam (located directly adjacent to Vawn, sharing the same reservoir), with both assets now benefiting from shared services and integrated reservoir management. Strathcona expects to be able to meaningfully increase Vawn's production above historical levels of approximately 5 Mbbls / d by year-end 2026 and will provide further details in coming quarters. Current capital activity remains focused on the Meota Central project, which is targeting first oil in the fourth quarter of 2026 and is expected to deliver a peak oil rate of approximately 13 Mbbls / d at a total installed cost of approximately $360 million. The project is currently 85% complete, on time and on budget.
In Lloydminster Conventional, production of 21 Mbbls / d reflected a 7% decrease quarter-over-quarter, driven by flood conformance challenges at Strathcona's Cactus Lake and Bodo-Cosine polymer floods. Production has since stabilized following successful conformance work completed over the previous quarter. Current capital activity is concentrated on the Company's annual drilling programs in Winter and Druid, which include a mixture of single and multi-lateral horizontal wells.
Selina Project Acquisition
Today Strathcona signed and closed the acquisition of a 50% operated working interest in the Selina Project ("Selina") in Cold Lake for total consideration of $23 million in cash. Strathcona previously held a 50% non-operated working interest in Selina, increasing its working interest to 100% and taking over operatorship. Selina is located near Strathcona's existing Lindbergh thermal project, with approvals from the Alberta Energy Regulatory ("AER") in place for 12,500 bbls / d of production. Strathcona expects to develop Selina over time in a capital-efficient manner by leveraging its existing central processing facility at Lindbergh. Strathcona estimates approximately 160 MMbbls of recoverable oil at Selina, none of which was booked in its reserves or contingent resources at year-end 2025 due to Strathcona previously not holding operatorship.
Normal Course Issuer Bid
Strathcona's Board has approved the filing of a notice with the Toronto Stock Exchange ("TSX") to commence a normal course issuer bid ("NCIB"). Once approved by the TSX, Strathcona may repurchase up to 5% of its issued and outstanding shares (up to a maximum of approximately 10.7 million common shares) over a twelve-month period.
Strathcona intends to act opportunistically from time to time to repurchase its shares at what it views as a discount to its intrinsic value, conservatively determined and after applying a margin of safety. For further details regarding the Company's rationale and strategy regarding the NCIB, shareholders are encouraged to review the Company's year-end shareholder letter posted on its website.
Outlook
Strathcona's 2026 production guidance of 120 to 130 Mbbls/d and capital budget of $1.0 billion is unchanged. Strathcona expects production of 115 to 120 Mbbls / d in the first half of 2026, ramping to an exit rate of approximately 135 Mbbls / d by 2026 year-end.
Following the Selina acquisition, Strathcona holds an estimated 3.0 billion of recoverable resources, equating to over 65 years relative to its 2026 production. Strathcona's long-range plan remains to grow production from 125 Mbbls / d in 2026 to 200 Mbbls / d by 2031 and 300 Mbbls / d by 2035 (in each case a 10% compound annual growth rate).
Quarterly Dividend
Strathcona's Board of Directors has declared a quarterly dividend of $0.30 per share to be paid on March 27, 2026 to shareholders of record on March 20, 2026. Payments to shareholders who are not residents of Canada will be net of any Canadian withholding taxes that may be applicable. Dividends paid by Strathcona are considered "eligible dividends" for Canadian tax purposes.
2025 Year End Reserves Details
The tables below summarize Strathcona's Year End 2025 reserves which were prepared by McDaniel & Associates Consultants Ltd. ("McDaniel"). A complete filing of our oil and gas reserves and other oil and gas information presented in accordance with National Instrument 51-101, Standards of Disclosure for Oil and Gas Activities is included in Strathcona's Annual Information Form for the year ended December 31, 2025, which can be found at www.sedarplus.ca and www.strathconaresources.com.
Summary of Oil and Gas Reserves (Forecast Prices and Costs) as of December 31, 2025
Reserves Category
Light &
Medium Crude Oil
Heavy
Crude Oil
Bitumen
Gross(Mbbl)
Net(Mbbl)
Gross(Mbbl)
Net(Mbbl)
Gross(Mbbl)
Net(Mbbl)
Proved
Developed Producing
--
2
101,464
93,159
139,440
103,453
Developed Non-Producing
--
--
580
540
--
--
Undeveloped
--
--
415,399
373,398
568,041
392,449
Total Proved(1)
--
2
517,443
467,097
707,481
495,903
Total Probable
--
1
219,899
193,777
720,159
467,720
Total Proved Plus Probable(1)
--
3
737,343
660,874
1,427,640
963,623
Reserves Category
Conventional Natural Gas
Natural Gas Liquids
Oil Equivalent
Gross(MMcf)
Net(MMcf)
Gross(Mbbl)
Net(Mbbl)
Gross(Mboe)
Net(Mboe)
Proved
Developed Producing
2,438
2,146
1
1
241,312
196,974
Developed Non-Producing
3
3
--
--
581
540
Undeveloped
2,466
2,195
--
--
983,851
766,213
Total Proved(1)
4,907
4,343
1
1
1,225,743
963,727
Total Probable
2,283
2,027
1
--
940,440
661,837
Total Proved Plus Probable(1)
7,190
6,371
2
2
2,166,183
1,625,564
(1)
Figures may not add due to rounding.
Summary of Net Present Value of Future Net Revenue Attributable to Oil and Gas Reserves (Forecast Prices and Costs) as of December 31, 2025
Reserves Category
Before Deducting Income Taxes
After Deducting Income Taxes
0 %
5 %
10 %
15 %
20 %
Unit Value(2)
0 %
5 %
10 %
15 %
20 %
Unit Value(3)
(in $ millions)(1)
$/boe
(in $ millions)(1)
$/boe
Proved
Developed Producing
5,221
4,928
4,342
3,844
3,447
22.04
4,396
4,250
3,773
3,359
3,027
19.16
Developed
Non‑Producing
16
14
12
10
9
21.65
12
10
9
8
7
15.97
Undeveloped
22,941
12,546
7,402
4,579
2,903
9.66
17,225
9,131
5,178
3,037
1,781
6.76
Total Proved(4)
28,178
17,487
11,755
8,434
6,359
12.20
21,633
13,391
8,960
6,404
4,815
9.30
Total Probable
26,602
10,424
5,122
2,939
1,876
7.74
20,202
7,748
3,732
2,101
1,317
5.64
Total Proved plus
Probable(4)
54,780
27,912
16,877
11,373
8,235
10.38
41,835
21,138
12,692
8,505
6,132
7.81
(1)
Net present value of future net revenue includes all resource income, including the sale of oil, gas, by-product reserves, processing third party reserves and other income.
(2)
Calculated using net present value of future net revenue before deducting income taxes, discounted at 10% per year, and net reserves. The unit values are based on net reserves volumes.
(3)
Calculated using net present value of future net revenue after deducting income taxes, discounted at 10% per year, and net reserves. The unit values are based on net reserves volumes.
(4)
Figures may not add due to rounding.
Forecast Prices and Costs as of December 31, 2025
Year(1)
Inflation(%)(2)
Exchange Rate(Cdn$/US$)(3)
Crude Oil
Natural Gas
Natural Gas Liquids
WTI Cushing Oklahoma40 API($US/bbl)
Canadian Light Sweet Crude 40 API($Cdn/bbl)
Western Canadian Select20.5 API($Cdn/bbl)
Alberta AECO-C Spot($Cdn/mmbtu)
Edmonton Pentanes Plus($Cdn/bbl)
Edmonton Butane($Cdn/bbl)
Edmonton Propane($Cdn/bbl)
Ethane Plant Gate($Cdn/bbl)
