CALGARY, AB, March 11, 2026 /PRNewswire/ - Strathcona Resources Ltd. ("Strathcona" or the "Company") (TSX: SCR) today reported its fourth quarter and full year 2025 financial and operating results as well as its year-end 2025 reserves. The Board of Directors also declared a quarterly dividend of $0.30 per common share and approved a share repurchase program for up to 5% of its outstanding shares, subject to customary TSX approvals.
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 ("PDPF&D")(4), including changes in future development costs ("PDPFDC"), 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) December December September December December
31, 2025 31, 2024 30, 2025 31, 2025 31, 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 710 1,025 807 3,622 4,255
other income(3)
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) (99) 88 573 911 604
Income
Operating Earnings(3) 146 190 236 930 970
Non-cash items(4) 167 217 165 766 1,074
Loss on risk management and foreign (75) (2) (18) (102) (107)
exchange contracts - realized, operating
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(R) 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) December December September December December
31, 2025 31, 2024 30, 2025 31, 2025 31, 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 & Heavy Bitumen
Medium Crude Oil Crude Oil
Gross Net Gross Net Gross Net
(Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (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 Natural Gas
Gas Liquids Oil Equivalent
Gross Net Gross Net Gross Net
(MMcf) (MMcf) (Mbbl) (Mbbl) (Mboe) (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 ofNet 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 0 % 5 % 10 % 15 % 20 % Unit
Value(2) Value(3)
(in $ millions)(1)
$/boe
(in $ millions)(1)
$/boe
Proved
Developed Producing 5,221 4,928 4,342 3,844 3,447 22.04 4,396 4,250 3,773 3,359 3,027 19.16
Developed 16 14 12 10 9 21.65 12 10 9 8 7 15.97
Non?Producing
Undeveloped 22,941 12,546 7,402 4,579 2,903 9.66 17,225 9,131 5,178 3,037 1,781 6.76
Total Proved(4) 28,178 17,487 11,755 8,434 6,359 12.20 21,633 13,391 8,960 6,404 4,815 9.30
Total Probable 26,602 10,424 5,122 2,939 1,876 7.74 20,202 7,748 3,732 2,101 1,317 5.64
Total Proved plus 54,780 27,912 16,877 11,373 8,235 10.38 41,835 21,138 12,692 8,505 6,132 7.81
Probable(4)
(1) Net present value of future net revenue includes all resource income, including the sale of oil, gas, by-product reserves, processing third party
reserves and other income.
(2) Calculated using net present value of future net revenue before deducting income taxes, discounted at 10% per year, and net reserves. The unit
values are based on net reserves volumes.
(3) Calculated using net present value of future net revenue after deducting income taxes, discounted at 10% per year, and net reserves. The unit values
are based on net reserves volumes.
(4)
Figures may not add due to rounding.
Forecast Prices and Costs as of December 31, 2025
Year Inflation Exchange Rate
Crude Oil Natural Gas
Natural Gas Liquids
(1) (%)(2) (Cdn$/US$)
(3)
WTI Cushing Oklahoma Canadian Light Sweet Western Canadian Alberta AECO-C Edmonton Pentanes Plus Edmonton Butane Edmonton Propane Ethane Plant
Crude Select Spot Gate
40 API 40 API 20.5 API
($Cdn/ ($Cdn/bbl) ($Cdn/bbl) ($Cdn/bbl) ($Cdn/bbl)
($US/bbl)
($Cdn/bbl) ($Cdn/bbl) mmbtu)
2026 - % 1.37 59.92 77.54 65.13 3.00 80.01 36.95 25.10 9.59
2027 2 % 1.36 65.10 83.60 70.43 3.30 86.19 39.79 27.28 10.64
2028 2 % 1.35 70.28 90.17 76.90 3.49 92.83 42.87 29.67 11.34
2029 2 % 1.35 71.93 92.32 78.71 3.58 95.04 43.89 30.37 11.66
2030 2 % 1.35 73.37 94.17 80.29 3.65 96.94 44.77 30.98 11.89
2031 2 % 1.35 74.84 96.06 81.90 3.72 98.89 45.66 31.60 12.14
2032 2 % 1.35 76.34 97.98 83.53 3.80 100.86 46.58 32.23 12.39
2033 2 % 1.35 77.87 99.93 85.20 3.88 102.88 47.51 32.87 12.64
2034 2 % 1.35 79.42 101.93 86.91 3.95 104.94 48.46 33.53 12.90
2035 2 % 1.35 81.01 103.97 88.65 4.03 107.04 49.43 34.20 13.16
Escalation of 2% per year thereafter
(1) Product sale prices will reflect these reference prices with further adjustments for quality and
transportation to point of sale.
(2) Inflation rates for forecasting costs only. Prices inflated at 2% after 2026 where applicable.
(3)
The exchange rate is used to generate the benchmark reference prices in this table.
Reconciliation of Changes in Gross Reserves(1)
Light & Heavy Crude Bitumen Conventional Natural Gas Oil
Equivalent
Medium Oil Natural Gas Liquids
Crude Oil (Mbbl) (Mboe)
(Mbbl) (MMcf) (Mbbl)
(Mbbl)
Proved
December 31, 2024 1,829 470,436 698,305 1,330,420 141,676 1,533,983
Extensions and improved recovery(2) 8,264 8,115 17 16,382
Technical revisions(3) (92) 20,193 23,849 (1,376) 104 43,824
Discoveries(4)
Acquisitions 41,114 41,114
Dispositions (1,642) (1,469) (1,276,334) (135,891) (351,724)
Economic factors(5) (4) (1,870) (404) (103) (2,296)
Production (91) (19,224) (22,384) (47,716) (5,887) (55,540)
Infill drilling
December 31, 2025(6) 517,443 707,481 4,907 1 1,225,743
Probable
December 31, 2024 4,549 167,287 684,534 1,044,350 90,424 1,120,852
Extensions and improved recovery(2) 34,548 35,582 4 70,131
Technical revisions(3) (29) (3,484) 155 (3,371) (399) (4,319)
Discoveries(4)
Acquisitions 24,725 24,725
Dispositions (4,520) (2,705) (1,038,679) (90,024) (270,362)
Economic factors(5) (472) (112) (20) (587)
Production
Infill drilling
December 31, 2025(6) 219,899 720,159 2,283 1 940,440
Proved Plus Probable
December 31, 2024 6,378 637,723 1,382,840 2,374,769 232,100 2,654,835
Extensions and improved recovery(2) 42,812 43,697 21 86,513
Technical revisions(3) (121) 16,709 24,004 (4,747) (295) 39,505
Discoveries(4)
Acquisitions 65,839 65,839
Dispositions (6,162) (4,174) (2,315,014) (225,915) (622,086)
Economic factors(5) (5) (2,342) (515) (123) (2,883)
Production (91) (19,224) (22,384) (47,716) (5,887) (55,540)
Infill drilling
December 31, 2025(6) 737,342 1,427,640 7,190 2 2,166,183
(1) Gross reserves means Strathcona's working interest reserves before calculation of royalties, and before consideration
of Strathcona's royalty interests.
(2) Additions due to new wells drilled and booked during the year, and any reserve changes due to enhanced oil recovery.
(3) Technical revisions include changes in reserves associated with changes in operating costs, capital costs and commodity
price offsets.
(4)
Additions where no reserves were previously booked.
(5)
Changes to reserves volumes due to changes in price forecasts and/or inflation rates.
(6)
Figures may not add due to rounding.
Undiscounted Future Net Revenue by Reserves Categories
Reserves Category Revenue Royalties Operating Costs Development Costs Abandonment Future Net Income Taxes Future Net
($ millions) and Revenue Revenue
Reclamation Costs Before After
Income Taxes Income
Taxes
Total Proved 96,723 21,944 30,045 14,633 1,922 28,178 6,545 21,633
Total Probable 98,389 30,106 26,860 14,230 592 26,602 6,400 20,202
Total Proved plus Probable 195,112 52,050 56,905 28,863 2,514 54,780 12,945 41,835
About Strathcona
Strathcona is one of North America's fastest growing pure play heavy oil producers with operations focused on thermal oil and enhanced oil recovery. Strathcona is built on an innovative approach to growth achieved through the consolidation and development of long-life assets. Strathcona's common shares (symbol SCR) are listed on the Toronto Stock Exchange (TSX).
For more information about Strathcona, visit www.strathconaresources.com.
Non-GAAP Measures and Ratios
The financial results for the three months and year ended December 31, 2025 and December 31, 2024, are presented below to reconcile continuing and discontinued operations to total results. Total results in a non-GAAP measure used by Management to assess the historical financial performance of the total business and is not intended to be indicative of future results.
Three Months Ended December 31, Three Months Ended December 31,
2025 2024(1)
($ millions, unless otherwise indicated) Continuing Discontinued Total Continuing Discontinued Total
Revenues and other income
Oil and natural gas sales 937 937 1,043 250 1,293
Sale of purchased products 14 14 16 16
Royalties (99) (99) (185) (24) (209)
Oil and natural gas revenues 852 852 874 226 1,100
(Loss) gain on risk management contracts (1) (1) 10 10
Midstream revenue 8 8
Other income 2 2
861 861 884 226 1,110
Expenses
Purchased product 15 15 16 16
Blending costs 236 236 268 268
Production and operating 163 (8) 155 152 46 198
Transportation and processing 95 95 88 56 144
General and administrative 24 24 21 7 28
Interest 24 24 39 39
Transaction related costs 25 8 33
Finance costs 15 15 12 9 21
Depletion, depreciation and amortization 152 152 141 55 196
Impairment 376 376
Foreign exchange (gain) loss (11) (11) 48 48
Changes in decommissioning liabilities (13) (13)
1,101 1,101 785 173 958
Gain on marketable securities 102 102
Loss on assets held for sale, net (12) (12)
(Loss) income before income taxes (138) (12) (150) 99 53 152
Income tax (recovery) expense (48) (3) (51) 49 15 64
(Loss) income and comprehensive (loss) income (90) (9) (99) 50 38 88
(1) Comparative periods have been revised to reflect current
period presentation.
Year Ended December 31, Year Ended December 31,
2025 2024(1)
($ millions, unless otherwise indicated) Continuing Discontinued Total Continuing Discontinued Total
Revenues and other income
Oil and natural gas sales 4,096 521 4,617 4,373 963 5,336
Sale of purchased product 67 67 75 75
Royalties (435) (35) (470) (567) (96) (663)
Oil and natural gas revenues 3,728 486 4,214 3,881 867 4,748
Loss on risk management contracts (86) (86) (44) (44)
Midstream revenue 24 24
Other income 16 16
3,682 486 4,168 3,837 867 4,704
Expenses
Purchased product 68 68 75 75
Blending costs 1,034 1,034 1,081 1,081
Production and operating 672 76 748 641 171 812
Transportation and processing 368 111 479 364 213 577
General and administrative 88 10 98 76 25 101
Interest 131 131 170 170
Transaction related costs 44 27 71 1 1
Finance costs 56 13 69 50 38 88
Depletion, depreciation and amortization 607 90 697 595 279 874
Impairment 376 376
Foreign exchange (gain) loss (34) (34) 68 68
Changes in decommissioning liabilities (13) (13)
3,397 327 3,724 3,121 726 3,847
Gain on marketable securities 171 171
Gain on sale of assets, net 609 609
Loss on settlement of other obligations (1) (1) (4) (4)
Income before income taxes 456 767 1,223 716 137 853
Income tax expense 90 222 312 209 40 249
Income and comprehensive income 366 545 911 507 97 604
(1) Comparative periods have been revised to reflect current
period presentation.
"Oil and natural gas sales, net of blending and other income" is calculated by deducting purchased product and blending costs from oil and natural gas sales, sales of purchased product, midstream revenue and other income. Management uses this metric to isolate the revenue associated with the Company's production after accounting for the unavoidable cost of blending. Oil and natural gas sales, net of blending, is also reflected on a per boe basis calculated using sales volumes. This ratio is useful to management when analyzing realized pricing against benchmark commodity prices.
Three Months Ended Year Ended
($ millions, unless otherwise indicated) December December September December December
31, 2025 31, 2024 30, 2025 31, 2025 31, 2024
Oil and natural gas sales 937 1,293 1,012 4,617 5,336
Sales of purchased products 14 16 31 67 75
Other income 2 8 16
Purchased product (15) (16) (31) (68) (75)
Blending costs (236) (268) (222) (1,034) (1,081)
Midstream revenue 8 9 24
Oil and natural gas sales, net of blending and other income 710 1,025 807 3,622 4,255
"Effective royalty rate" is calculated by dividing royalties by oil and natural gas sales and sale of purchased product, net of blending and purchased product. This metric allows management to analyze the movement of royalty expenses in relation to realized and benchmark commodity prices.
"Operating Earnings - Discontinued" is considered a key financial metric for evaluating the profitability of Strathcona's discontinued operations. "Operating Earnings - Continuing" is a GAAP financial measure as it is used by the Chief Operating Decision Makers to evaluate profit or loss and is presented in the consolidated financial statements for year ended December 31, 2025 and 2024. A quantitative reconciliation of Operating Earnings - Discontinued to the most directly comparable GAAP financial measure, Oil and natural gas sales, is presented below.
Three Months Ended Year Ended
($ millions, unless otherwise indicated) December December September December December
31, 2025 31, 30, 2025 31, 2025 31,
2024(1) 2024(1)
Revenues
Oil and natural gas sales 250 3 521 963
Expenses
Royalties 24 35 96
Production and operating - Energy (1) 2 (1) 7
Production and operating - Non-energy (7) 44 (3) 76 164
Transportation and processing 56 111 213
Depletion, depreciation and amortization 55 90 279
General and administrative 7 (2) 10 25
Finance costs 9 13 38
Operating Earnings -Discontinued 8 53 9 186 141
(1) Comparative periods have been revised to reflect current
period presentation.
"Funds from Operations" is used by management to analyze operating performance and provides an indication of the funds generated by Strathcona's principal business to either fund operating activities, re-invest to either maintain or grow the business or make debt repayments. Funds from Operations is derived from Operating Earnings and adjusted for DD&A, finance costs, gains and losses on risk management contracts - realized and gains and losses on foreign exchange - realized, operating.
"Free Cash Flow" indicates funds available for deleveraging, funding future growth, or shareholder returns. Free Cash Flow is derived from Operating Earnings and adjusted for DD&A, finance costs, gains and losses on risk management contracts - realized and gains and losses on foreign exchange - realized, operating, capital expenditures and decommissioning costs.
Quantitative reconciliations of Funds from Operations and Free Cash Flow for both continuing and discontinued operations to the most directly comparable GAAP financial measure, Operating Earnings, are set forth below.
Three Months Ended Year
Ended
($ millions, unless otherwise indicated) December December September December December
31, 2025 31, 30, 2025 31, 2025 31,
2024(1) 2024(1)
Operating Earnings - Continuing 138 137 227 744 829
Depletion, depreciation and amortization 152 141 151 607 595
Finance costs 15 12 14 56 50
Loss on risk management contracts - realized (75) (5) (20) (100) (107)
Foreign exchange (loss) gain - realized, operating 3 2 (2)
Funds from Operations - Continuing 230 288 374 1,305 1,367
Capital expenditures (188) (280) (281) (957) (826)
Decommissioning costs (9) (7) (8) (42) (15)
Free Cash Flow - Continuing 33 1 85 306 526
(1) Comparative periods have been revised to reflect current
period presentation.
Three Months Ended Year Ended
($ millions, unless otherwise indicated) December December September December December
31, 2025 31, 30, 2025 31, 2025 31,
2024(1) 2024(1)
Operating Earnings - Discontinued 8 53 9 186 141
Depletion, depreciation and amortization 55 90 279
Finance costs 9 13 38
Realized loss on deferred premium settlement 112
Funds from Operations - Discontinued 8 117 9 289 570
Capital expenditures 12 (113) (229) (470)
Decommissioning costs (6) (2) (21)
Free Cash Flow - Discontinued 20 (2) 9 58 79
(1) Comparative periods have been revised to reflect current
period presentation.
The following table reconciles operating earnings, funds from operations and free cash flow from continuing and discontinued operations:
Three Months Ended Year Ended
($ millions, unless otherwise indicated) December December September December December
31, 2025 31, 30, 2025 31, 2025 31,
2024(1) 2024(1)
Operating Earnings 146 190 236 930 970
Depletion, depreciation and amortization 152 196 151 697 874
Finance costs 15 21 14 69 88
Loss on risk management contracts - realized (75) (5) (20) (100) (107)
Foreign exchange (loss) gain - realized, operating 3 2 (2)
Realized loss on deferred premium settlement 112
Funds from Operations 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 53 (1) 94 364 605
(1) Comparative periods have been revised to reflect current
period presentation.
"Organic Capex" is defined as total property, plant and equipment expenditures, excluding capitalized overhead, expenditures on corporate assets, and capital expenditures on assets acquired during the period. Management uses Organic Capex to evaluate the underlying capital investment in Strathcona's existing asset base, excluding the effects of acquisitions and non-operational capital. This measure provides insight into the Company's capital efficiency.
"Organic Operating Netback" is used to assess the profitability and efficiency of Strathcona's field operations before the impact of acquisitions.
A quantitative reconciliation of "Organic Operating Netback" to the most comparable GAAP measure, "Oil and natural gas sales", is set forth below:
Year Ended
($ millions, unless otherwise indicated) December 31, 2025
Oil and natural gas sales 4,096
Sale of purchased product 67
Purchased product (68)
Blending costs (1,034)
Midstream revenue 24
Oil and natural gas sales, net of blending - Continuing 3,085
Royalties 435
Production and operating 672
Transportation 368
Field operating income - Continuing 1,610
Less: Operating income from properties acquired in the year (14)
Organic field operating income 1,596
Sales volumes (boe/d) 114,763
Less: sales volumes from properties acquired in the year (boe/d) (479)
Organic sales volumes (boe/d) 114,284
Organic operating netback ($/boe) 38.49
A quantitative reconciliation of "Organic Capex" to the most comparable GAAP measure, "Property, plant and equipment expenditures", is set for below:
Year Ended
($ millions, unless otherwise indicated) December 31, 2025
Property, plant and equipment expenditures 1,186
Less: capitalized overhead (49)
Less: expenditures on corporate assets (7)
Less: property, plant and equipment expenditures on assets disposed of in the year (229)
Organic Capex 901
Supplementary Financial Measures
"PDP F&D" are calculated as Organic Capex plus changes in PDP future development costs (-$72 million in 2025), divided by PDP reserve additions for the year (39 MMbbls in 2025), excluding the impact of acquisitions and dispositions. Management uses PDP F&D costs as a measure of capital efficiency for organic reserves development.
"PDP Recycle Ratio" is calculated by dividing the Organic Operating Netback by PDP F&D. PDP Recycle Ratio is used to measure the profit per barrel of oil to the cost of finding and developing that barrel of oil.
"Organic 2P Reserves Replacement" is calculated as 2P reserves additions, excluding acquisitions and dispositions, divided by annual production volumes.
"Reserves Life Index" calculated by dividing gross reserves by annualized fourth quarter production.
"1P and 2P after-tax PV-10 net of debt per share" is comprised of before tax present value for 1P and 2P reserves, discounted at 10 per cent, as determined in accordance with NI 51-101, adjusted for debt at the end of the period.
"Organic 2P Reserves Replacement" is calculated as 2P reserves additions, excluding acquisitions and dispositions, divided by annual production volumes.
"Interest and finance costs" is an aggregation of interest and finance costs. Management uses this metric to obtain a fulsome understanding of all interest and accretion costs the Company is subject to.
"Other items" is an aggregation of risk management contracts, foreign exchange, transaction related costs, gain on marketable securities, loss (gain) on sale of assets, loss on settlement of other obligations, deferred tax (recovery) expense, change in decommissioning liabilities and impairment from both continuing and discontinued operations. They are presented in such a manner to yield prominence to key financial metrics such as income and comprehensive income, Funds from Operations and Free Cash Flow.
Three Months Ended Year Ended
($ millions, unless otherwise indicated) December December September December December
31, 2025 31, 2024 30, 2025 31, 2025 31, 2024
Loss (gain) on risk management contracts 1 (10) 27 86 44
Foreign exchange (gain) loss (11) 48 17 (34) 68
Transaction related costs 33 19 71 1
Gain on marketable securities (102) (22) (171)
Loss (gain) on sale of assets 12 (616) (609)
Loss on settlements of other obligations 1 4
Deferred tax (recovery) expense (51) 64 238 312 249
Change in decommissioning liabilities (13) (13)
Impairment 376 376
Other items 245 102 (337) 19 366
"Non-cash items" is an aggregation of depletion, depreciation and amortization, finance costs, realized loss on deferred premium settlements and other income - decommissioning government grant.
"Debt, net of cash and marketable securities" is comprised of debt less cash and marketable securities, as derived under the Accounting Standards.
Presentation of Oil and Gas Information
This press release contains various references to the abbreviation "boe" which means barrels of oil equivalent. All boe conversions in this press release are derived by converting gas to oil at the ratio of six thousand cubic feet ("mcf") of natural gas to one barrel ("bbl") of crude oil. Boe may be misleading, particularly if used in isolation. A boe conversion rate of 1 bbl : 6 mcf is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio of oil compared to natural gas based on currently prevailing prices is significantly different than the energy equivalency ratio of 1 bbl : 6 mcf, utilizing a conversion ratio of 1 bbl : 6 mcf may be misleading as an indication of value.
References in this press release to initial production rates and other short-term production rates and test results are useful in confirming the presence of hydrocarbons, however, such rates are not determinative of the rates at which such wells will commence production and decline thereafter and are not indicative of long-term performance or of ultimate recovery. While encouraging, readers are cautioned not to place reliance on such rates in calculating aggregate production for the Company or the assets for which such rates are provided. A pressure transient analysis or well-test interpretation has not been carried out in respect of all wells. Accordingly, the test results should be considered to be preliminary.
Product Type Production Information
National Instruments 51-101 - Standards of Disclosure for Oil and Gas Activities includes condensate within the natural gas liquids product type. The Company has disclosed condensate as combined with light oil and separately from other natural gas liquids in this press release since the price of condensate as compared to other natural gas liquids is currently significantly higher and the Company believes that this presentation provides a more accurate description of its operations and results therefrom. References to "natural gas" in this press release refer to conventional natural gas. References to "liquids" in this press release refer to, collectively, bitumen, heavy oil, condensate and light oil (comprised of condensate and light oil) and other natural gas liquids (comprised of ethane, propane and butane only).
The Company's quarterly and year-to-date average daily production volumes, and the references to "natural gas", "crude oil" and "liquids", reported in this press release consist of the following product types, as defined in NI 51-101 and using a conversion ratio of 6 mcf : 1 bbl where applicable:
Three Months Ended Year Ended
December December September December December
31, 2025 31, 2024 30, 2025 31, 2025 31, 2024
Heavy crude oil (bbl/d) 54,660 50,997 53,943 52,658 51,107
Light and medium crude oil (bbl/d) 61 617 18 263 651
Total crude oil (bbl/d) 54,721 51,614 53,961 52,921 51,758
Bitumen (bbl/d) 62,538 59,732 61,157 61,327 59,516
NGLs (bbl/d) 30 33,126 466 16,128 31,229
Total liquids (bbl/d) 117,289 144,472 115,584 130,376 142,503
Conventional natural gas (mcf/d) 2,558 256,386 3,701 130,729 243,456
Total (boe/d) 117,715 187,203 116,201 152,163 183,080
The Company's reserve volumes, and the references to "total oil" reported in this press release consist of the following product types as defined by NI 51-101:
2025
NI 51-101 NI 51-101 NI 51-101
Light & Medium Heavy Oil Bitumen Total
Oil Oil
Reserves Category (MMbbl) (MMbbl) (MMbbl) (MMbbl)
Proved
Developed Producing (1) 101 139 241
Developed Non-Producing (1) 1 1
Undeveloped (1) 415 568 983
Total Proved (1) 517 707 1,225
Probable (1) 220 720 940
Total Proved plus Probable (1) 737 1,428 2,165
(1) Figures may not add due to
rounding
NI 51-101 NI 51-101
Natural Gas Natural
Liquids Gas Total
Reserves Category (MMbbl) (Bcf) (MMboe)
Proved
Developed Producing (1) 2 241
Developed Non-Producing (1) 1
Undeveloped (1) 2 984
Total Proved (1) 5 1,226
Probable (1) 2 940
Total Proved plus Probable (1) 7 2,166
(1) Figures may not add due to
rounding
Forward-Looking Information
Certain statements contained in this press release constitute forward-looking information within the meaning of applicable securities laws. The forward-looking information in this press release is based on Strathcona's current internal expectations, estimates, projections, assumptions and beliefs. Such forward-looking information is not a guarantee of future performance and involves known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking information. The Company believes the material factors, expectations and assumptions reflected in the forward-looking information are reasonable as of the time of such information, but no assurance can be given that these factors, expectations and assumptions will prove to be correct, and such forward-looking information included in this press release should not be unduly relied upon.
The use of any of the words "expect", "target", "anticipate", "intend", "estimate", "objective", "ongoing", "may", "will", "project", "believe", "depends", "could" and similar expressions are intended to identify forward-looking information. In particular, but without limiting the generality of the foregoing, this press release contains forward-looking information pertaining to the following: the Company's business strategy and future plans; the expected peak rate of the 8 well pair D01 West pad at Lindbergh, including the timing thereof; the expectation that Strathcona will be able to meaningfully increase Vawn's production above historical levels and that Strathcona will provide further details in respect of the same in coming quarters; the expected peak oil rate, total installed costs and timing for first oil in respect of the Meota Central project; Strathcona's expectations in respect of the Selina Project, including its ability to leverage its existing central processing facility at Lindbergh to reduce capital costs and the amount of recoverable oil; Strathcona's intention to commence a normal course issuer bid, including the number of shares to be repurchased thereunder and Strathcona's strategy in respect of the same; Strathcona's initial 2026 production guidance of 120 to 130 Mbbls/d and capital budget of $1.0 billion; Strathcona's expected production of 115 to 120 Mbbls / d in the first half of 2026, and its expectation of ramping to an exit rate of approximately 135 Mbbls / d by year-end; and Strathcona's long-range plan to grow existing production from 125 Mbbls / d in 2026 to 200 Mbbls / d by 2031 and 300 Mbbls / d by 2035.
All forward-looking information reflects Strathcona's beliefs and assumptions based on information available at the time the applicable forward-looking information is disclosed and in light of the Company's current expectations with respect to such things as: Strathcona's ability to generate sufficient cash flow to fund debt repayment and dividend payments; Strathcona's ability to declare and pay dividends; the success of Strathcona's operations and growth and expansion projects; expectations regarding production growth, future well production rates and reserve volumes; expectations regarding Strathcona's capital program, including the outlook for general economic trends, industry trends, prevailing and future commodity prices, foreign exchange rates and interest rates; the availability of third party services; prevailing and future royalty regimes and tax laws; future well production rates and reserve volumes; fluctuations in energy prices based on worldwide demand and geopolitical events; the impact of inflation; the integrity and reliability of Strathcona's assets; decommissioning obligations; Strathcona's ability to comply with its financial covenants; and the governmental, regulatory and legal environment. In addition, certain forward-looking information with respect to the Company's 2025 guidance assumes commodity prices and exchange rates of: US$70 / bbl WTI, US$12 / bbl WCS-WTI differential, 1.36 USD-CAD and C$2.75 / GJ AECO. Management believes that its assumptions and expectations reflected in the forward-looking information contained herein are reasonable based on the information available on the date such information is provided and the process used to prepare the information. However, it cannot assure readers that these expectations will prove to be correct.
The forward-looking information included in this press release is not a guarantee of future performance and involves known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking information, including, without limitation: changes in commodity prices; changes in the demand for or supply of Strathcona's products; the continued impact, or further deterioration, in global economic and market conditions, including from inflation, tariffs and/or certain geopolitical conflicts, such as the ongoing Russia/Ukraine conflict and the conflict in the Middle East, and other heightened geopolitical risks and the ability of the Company to carry on operations as contemplated in light of the foregoing; determinations by the Organization of the Petroleum Exporting Countries and other countries as to production levels; unanticipated operating results or production declines; changes in tax or environmental laws, climate change, royalty rates or other regulatory matters; changes in Strathcona's development plans or by third party operators of Strathcona's properties; competition from other producers; inability to retain drilling rigs and other services; failure to realize the anticipated benefits of the Company's acquisitions; incorrect assessment of the value of acquisitions; delays resulting from or inability to obtain required regulatory approvals, including TSX approval of our normal course issuer bid; increased debt levels or debt service requirements; changes in foreign exchange rates; inaccurate estimation of Strathcona's oil and gas reserve and contingent resource volumes; limited, unfavourable or a lack of access to capital markets or other sources of capital; increased costs; a lack of adequate insurance coverage; the impact of competitors; and the other factors discussed under the "Risk Factors" section in Strathcona's Management's Discussion & Analysis and Annual Information Form, each for the year ended December 31, 2025, and from time to time in Strathcona's public disclosure documents, which are available at www.sedarplus.ca.
Declaration of dividends is at the sole discretion of the board of directors of Strathcona and will continue to be evaluated on an ongoing basis. There are risks that may result in Strathcona changing, suspending or discontinuing its quarterly dividends, including changes to its free cash flow, operating results, capital requirements, financial position, debt levels, market conditions or corporate strategy and the need to comply with requirements under its credit agreement and applicable laws respecting the declaration and payment of dividends. There are no assurances as to the continuing declaration and payment of future dividends or the amount or timing of any such dividends.
Management approved the capital budget and production guidance contained herein as of the date of this press release. The purpose of the capital budget and production guidance is to assist readers in understanding Strathcona's expected and targeted financial position and performance, and this information may not be appropriate for other purposes.
This earnings release contains information that may constitute future-oriented financial information or financial outlook information (collectively, "FOFI") about Strathcona's prospective financial performance, financial position or cash flows, all of which is subject to the same assumptions, risk factors, limitations and qualifications as set forth above. Readers are cautioned that the assumptions used in the preparation of such information, although considered reasonable at the time of preparation, may prove to be imprecise or inaccurate and, as such, undue reliance should not be placed on FOFI. Strathcona's actual results, performance and achievements could differ materially from those expressed in, or implied by, FOFI. Strathcona has included FOFI in order to provide readers with a more complete perspective on Strathcona's future operations and management's current expectations relating to Strathcona's future performance. Readers are cautioned that such information may not be appropriate for other purposes.
The foregoing risks should not be construed as exhaustive. The forward-looking information contained in this press release speaks only as of the date of this press release and Strathcona does not assume any obligation to publicly update or revise such forward-looking information to reflect new events or circumstances, except as may be required pursuant to applicable laws. Any forward-looking information contained herein is expressly qualified by this cautionary statement.
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SOURCE Strathcona Resources Ltd.
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