TOURMALINE ACHIEVES RECORD PRODUCTION, ADDS 829 MILLION BOE OF 2P RESERVES AND REDUCES 2026 EP CAPEX
CALGARY, AB, March 4, 2026 /CNW/ - Tourmaline Oil Corp. (TSX: TOU) ("Tourmaline" or the "Company") is pleased to release financial and operating results for the full year and fourth quarter of 2025.
- Record Q4 2025 average production of 659,204 boepd and January 2026 average production of over 685,000 boepd.
- 829 million boe proved plus probable ("2P") reserve addition in 2025, including a corporate record single year organic 2P reserve addition of 457 million boe, both after accounting for 2025 production.
- Continued corporate operating costs reduction in Q4 2025, down over 9% from the first half of 2025 to $4.66/boe.
- Peace River High ("PRH") asset sale completed in February 2026 for proceeds of $765 million, prior to customary closing adjustments.
- 2026 forecasted EP capital expenditures reduced by $350 million as the Company remains focused on optimizing free cash flow(1)(2) ("FCF").
- Quarterly base dividend of $0.50/share to be paid on March 31, 2026 to shareholders of record at the close of business on March 16, 2026.
- Net debt(3) at year-end 2025 of $1.5 billion, inclusive of the impact of the PRH asset sale, or 0.45x forecasted 2026 cash flow(4) ("CF"), down from Q3 2025 net debt of $2.3 billion.
- Record Q4 2025 average production of 659,204 boepd, within the previous Q4 guidance range of 655,000 - 665,000 boepd.
- Q4 2025 average liquids production (oil, condensate, NGLs) was also a record at 152,673 bbls/d.
- January 2026 production averaged over 685,000 boepd prior to the impact of the PRH asset sale, a new record and ahead of expectations.
- First quarter 2026 average production of 660,000 - 670,000 boepd is anticipated, after taking into account the sale of the PRH assets which closed on February 2, 2026.
- In order to improve operating netbacks(5), Tourmaline has elected to terminate its discretionary deep cut gas plant deliveries in the Alberta Deep Basin in 2026 as contracts expire. This will reduce corporate average ethane production volumes by approximately 20,000 bpd on a full year basis but is expected to increase forecasted 2026 operating netback by approximately $65 million and forecasted 2027 operating netback by approximately $110 million through the elimination of deep cut processing fees as well as C2+ transportation and fractionation fees.
- Q4 2025 CF was $890 million ($2.29 per fully diluted share(6)). Full year 2025 CF was $3.4 billion ($8.84 per fully diluted share).
- Tourmaline sold its PRH complex to a Canadian senior producer for cash proceeds of $765 million, prior to customary closing adjustments. Through this transaction, Tourmaline has sold its most mature, highest-cost production and will replace it with new low-cost production streams flowing through newly constructed Tourmaline facilities. Although Tourmaline pioneered the Charlie Lake horizontal play in 2009-2010, this disposition will allow the Company to enhance its focus on the Company's two massive gas complexes. Tourmaline intends to utilize approximately $500 million of the proceeds of this disposition for permanent long-term debt reduction and approximately $265 million for the NEBC infrastructure buildout over the next two years.
- Net debt at year end 2025 was $1.5 billion, inclusive of the impact of the PRH asset sale, and down from Q3 2025 net debt of $2.3 billion. The Company is setting a long-term net debt target of $1.75 billion (approximately 0.5x net debt to cash flow).
- The multi-year EP Plan has been updated for full year 2025 results, asset sales, strong well performance, new commodity hedges, and cost reduction initiatives realized to date.
- The Company believes that during these unusually volatile times, the optimal business approach is to steadily reduce debt and continuously improve the overall cost structure. The Company is already executing on this plan.
- Q4 2025 EP capital spending was $812.7 million, within the original quarterly guidance range. Full year 2025 EP capital spending was $2.93 billion.
- The PRH asset sale and the redirection of discretionary Deep Basin deep cut volumes will reduce total corporate production by a total of approximately 50,000 boepd on a full year basis. Q1 2026 average production of 660,000 - 670,000 boepd is now expected (which includes Deep Basin deep cut production volumes for the entire quarter and PRH production volumes until February 2, 2026). The full year 2026 anticipated average production range is now 620,000 - 640,000 boepd.
- The 2026 full year EP capital program will be reduced by $350 million to $2.55 billion along with a $50 million cut in non-EP capital for a total capital expenditure reduction of $400 million. This reduction includes $175 million of the originally planned 2026 EP capex in the PRH complex and $175 million of expenditures in the gas complexes. The Company believes it is prudent to defer certain gas-focused expenditures until a sustained, stronger local price environment materializes. The gas complex expenditure reduction will have a negligible impact on production guidance (~1.0%) given stronger than anticipated 2026 well performance to date. The Company has identified an additional $200 million of drilling and completion capital that could be deferred from the 2026 EP capital program if commodity prices deteriorate further.
- At strip pricing(7), Tourmaline's revised EP Plan anticipates 2026 CF of $3.4 billion and FCF of $0.7 billion. All else equal for every US $0.10/mcf that AECO pricing improves, Tourmaline's 2026 CF and FCF increase by approximately $45 million. Similarly, for every US $1.00/mcf that both JKM and TTF pricing improve, Tourmaline's 2026 CF and FCF increase by approximately $50 million and Tourmaline's 2027 CF and FCF increase by approximately $70 million.
- Year-end 2025 proved developed producing ("PDP") reserves(8) of 1.47 billion boe were up 27% after accounting for 2025 annual production of 233 million boe. Total proved ("TP") reserves of 3.26 billion boe were up 20% after accounting for 2025 production. 2P reserves of 6.09 billion boe were up 15% after accounting for 2025 production.
- The 2025 2P organic reserve addition of 457 million boe was the largest single year organic 2P addition in corporate history.
- After 17 years of operations, Tourmaline now has 27.7 TCF of economic 2P natural gas reserves and 1.48 billion barrels of 2P oil, condensate and NGL reserves, all of which are pipeline-connected to markets across North America. At year-end 2025, 15.4% of the current internally estimated drilling inventory of 26,512 gross locations was booked in the 2025 year-end reserve report.
- Year-end 2025 oil, condensate and NGL 2P reserves of 1.48 billion barrels represent the second largest conventional liquids reserve base in Canada, based on public disclosure.
- Tourmaline has only booked 4,073 gross locations of a total drilling inventory of 26,512 gross locations (15.4% of the overall inventory) to achieve year-end 2025 2P reserves of 6.1 billion boe.
- Tourmaline replaced 356% of its 2025 annual production of 233 million boe with 2P additions of 829 million boe, including 2025 production.
- Tourmaline's 2025 PDP finding and development ("F&D") costs were $9.81 per boe including changes in future development capital ("FDC"), yielding a PDP reserve recycle ratio of 1.5 times. TP finding, development and acquisition ("FD&A") costs in 2025 were $10.95 per boe, including changes in FDC. 2P FD&A costs in 2025 were $9.09 per boe, including changes in FDC.
- The Company elected to increase drill and complete costs across the entire booked inventory (4,073 gross locations) to reflect the steady migration to longer horizontals and an increasing percentage of plug and perf style completions. Future facility capital was also increased to reflect the Company's planned NEBC infrastructure buildout. These 2025 additions to the Company's total FDC amount incorporated in the year-end 2025 reserve report resulted in a $3.21/boe increase to the Company's 2025 2P FD&A including FDC and an increase of $4.61/boe to the Company's 2P F&D costs including FDC. These additions to the Company's total FDC amounts are not expected to reoccur in future reserve reports. 2025 2P FD&A costs including the increased FDC were $9.09/boe, compared to 5-year 2P FD&A costs of $7.74/boe, including changes in FDC.
- Tourmaline's 2P reserve value (before taxes) equates to $98.86 per diluted share (after tax reserve value of $75.66 per diluted share) using the January 1, 2026 engineering price deck and a 10% discount rate. TP reserve value (before tax) is $64.06 per diluted share and $50.43 per diluted share (after tax). PDP reserve value is $38.94 per diluted share (before tax) and $32.89 per diluted share (after tax). The decrease in the 2P reserve value in the current reserve report (compared to the December 31, 2024 reserve report) is a result of a significant increase in reserve volumes being more than offset by significant backwardation in the JKM gas price as well as weaker AECO prices in the engineering price deck after 2027.
- Tourmaline's average realized natural gas price in Q4 2025 was CAD $3.77/mcf, significantly (CAD $1.51/mcf) above the AECO 5A benchmark price of CAD $2.26/mcf over the same period, as the Company continues to benefit from its diversified marketing portfolio and strategic hedging program.
- Tourmaline has an average of 879 mmcfpd of natural gas hedged for 2026 at a weighted average fixed price of CAD $4.54/mcf. This includes 55 mmcfpd hedged at a weighted average price of CAD $14.69/mcf in international markets and 130 mmcfpd at a weighted average price of CAD $6.70/mcf in Western U.S. markets.
- In Q1 2026, Tourmaline has over 370 mmcfpd of physical gas exposed to the premium price Eastern markets (Dawn, Ventura, Chicago, Iroquois, Emerson and ANR SE), providing a strong uplift to Q1 cash flow. These markets traded at an average of CAD $24.00/mcf for the last ten days of January.
- The Company entered into a long-term natural gas storage agreement with AltaGas at its Dimsdale Storage Facility in Alberta in 2025, and AltaGas has announced a positive final investment decision ("FID") for the Phase 2 expansion of the facility. Tourmaline will have access to 6 bcf of storage capacity starting April 2026, increasing to 10 bcf in mid-2027 for a 10-year term. The Company views the acquisition of an additional large storage position as a strategic opportunity to improve financial performance and enhance operational flexibility in periods of natural gas volatility. This is another aspect of the Company's ongoing efforts to fully vertically integrate the overall gas business.
- Tourmaline will have an average of 213,000 mmbtu/d exposed to international pricing (TTF/JKM) in 2026. This will grow to 253,000 mmbtu/d by exit 2027 and 333,000 mmbtu/d by exit 2028. Both JKM and TTF prices have improved since year end 2025.
- Tourmaline embarked upon a comprehensive cost reduction initiative in mid-2025 with the focus on reducing all aspects of the cost equation. These realized cost reductions are expected to be sustainable on a long-term basis.
- Q4 2025 operating costs were $4.66/boe, down 3% from third quarter 2025 operating costs of $4.80/boe and down 9% from first half of 2025 operating costs of $5.14/boe.
- The sale of the PRH complex will reduce go-forward corporate operating costs by a further 7%, resulting in a 2026 operating cost guidance of $4.50/boe, a 9% year-over-year reduction.
- With the success of cost reduction initiatives to date, Tourmaline is revising its aggregate operating and transport cost reduction target by 2031 from $1.00/boe to $1.50/boe, with approximately $0.70/boe already achieved since the first half of 2025 when the target was initiated.
- Lower aggregate debt levels combined with the Company's recently initiated commercial paper program are expected to yield approximately $20-25 million in interest cost reductions in 2026 based on prevailing interest rates.
- Tourmaline has entered into agreements to control frac sand capacity in a transload facility in the NEBC Montney complex. The facility is expected to commence operations in Q2 2026. This vertical integration of the Company's sand business is estimated to save over $40M per year in capital costs.
- The NEBC infrastructure buildout will systematically reduce costs as various components of the buildout are completed. The first major component to be completed is the liquids hub and associated pipelines located in proximity to the Aitken gas processing complex. The project was commissioned in February 2026 with an initial capacity of 20,000 bbl/d and will handle all condensate from North Montney Phase 1 and future North Montney development phases with resulting expected overall corporate savings of $0.05/boe over the EP Plan period.
- By 2031, through expected total cost reductions of $1.50/boe, and sand-related capital savings of over $40 million per year, Tourmaline anticipates up to $500 million per year of aggregate structural cost reductions, compared to the Company's first half of 2025 total cost structure, which will flow through to lower corporate break evens and FCF margin improvement.
- Tourmaline drilled 331 gross wells in 2025 and led the Canadian industry(9) with a total of 1.7 million metres drilled during the year.
- In 2025, Tourmaline delivered its best overall well performance in the past five years in the NEBC Montney gas condensate complex (21% higher than the previous 5-year average based on the IP90 of 102 wells). This outperformance has been across the full suite of the BC Montney assets, from Aitken-Birch-Gundy in the north to Groundbirch-Doe-Monias in the south.
- The Company is currently planning to drill and complete a total of approximately 280 net wells in 2026 including approximately 140 net wells in both the Alberta Deep Basin and the NEBC gas condensate complexes. Tourmaline continues to increase its lateral length with the 2025 Deep Basin and NEBC program averaging 8,400 completed lateral feet, up over 1,100 feet from 2024. Drilling and completion costs per foot in the Deep Basin and NEBC are now in decline, dropping from $805 per lateral foot in 2024 to $780 per lateral foot in 2025 despite steadily higher tonnage in NEBC completions.
- The 2026 EP capital budget reduction will not impact the original start-up timing of the Aitken and Groundbirch/Monias gas plant projects in NEBC. Aitken is on schedule for a Q4 2026 completion, with Groundbirch/Monias completion expected in Q4 2027.
- The Company's ongoing new zone/new pool exploration program has resulted in 2.55 TCFe of 2P reserves (as at December 31, 2025) and 1,356 Tier1/Tier 2 drilling locations, with the vast majority of these additions occurring in the last five years. There are several potential high impact exploration and delineation wells planned in the 2026 program.
- Tourmaline has achieved Grade 'A' certification for methane performance across its NEBC assets under MiQ's global methane certification standard. Tourmaline is the first Canadian company to be certified under MiQ and the first company in MiQ's history to have certified integrated gas production and processing facilities.
- Tourmaline's cleantech engineering team continues to develop and implement new proprietary emission reduction technologies, execute expanded water management initiatives, explore industry leading methane mitigation technologies, and manage related third-party environmental research.
- Since embarking on the diesel displacement initiative for drilling rigs and frac spreads in June 2017, the Company has displaced 240 million litres of diesel, providing an emissions reduction of 160,000 tonnes of carbon dioxide and saving approximately $235 million (including the cost of the replacement natural gas). Drilling and completions operations powered by natural gas result in lower emissions of carbon dioxide, nitrogen oxides, sulphur dioxide and particulate matter compared to traditional diesel-powered drilling and completions operations.
- The compressed natural gas in long-haul trucking joint development with Clean Energy Fuels Corp., announced in April 2023, continues to progress with 5 stations operational across Alberta and British Columbia. An additional four new stations are planned in 2026. This initiative is expected to reduce costs and emissions in the long-haul trucking industry and build Canadian natural gas demand.
- Tourmaline completed construction of a new water recycling facility in 2025 and is planning to build three additional storage and recycling facilities in 2026. These facilities reduce freshwater usage and reduce well stimulation costs.
- The Company is a leader in methane emission mitigation and operates the West Wolf Emissions Testing Centre, the largest in the world, where new technologies to accurately measure and ultimately reduce methane emissions are developed.
- Tourmaline's Board of Directors has declared a quarterly base dividend of $0.50 per share, payable on March 31, 2026 to shareholders of record at the close of business on March 16, 2026. The quarterly base dividend is designated as an eligible dividend for Canadian income tax purposes.
- Weak WCSB local gas pricing and unusually low pricing at the PG&E and Malin sales hubs this winter will limit FCF and constrain the Company's ability to fund a special dividend in Q1. Sustained stronger pricing and the Company's ongoing margin improvement activities are expected to lead to further base dividend increases in the future. Special dividends are anticipated to be used in those periods of particularly strong pricing to return the majority of the incremental FCF to shareholders.
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(1) | This news release contains certain specified financial measures consisting of non-GAAP financial measures, non-GAAP financial ratios, capital management measures and supplementary financial measures. See "Non-GAAP and Other Financial Measures" in this news release for information regarding the following specified financial measures: "cash flow", "capital expenditures", "EP expenditures", "free cash flow", "operating netback", "operating netback per boe", "cash flow per diluted share", "free cash flow per diluted share", "adjusted working capital", "net debt", "reserve value per diluted share", "operating expenses per boe", "cash general and administrative expenses per boe" and "transportation costs per boe". Since these specified financial measures do not have standardized meanings under International Financial Reporting Standards ("GAAP"), securities regulations require that, among other things, they be identified, defined, qualified and, where required, reconciled with their nearest GAAP measure and compared to the prior period. See "Non-GAAP and Other Financial Measures" in this news release and in the Company's Management's Discussion and Analysis as at and for the year ended December 31, 2025 (the "Annual MD&A"), which information is incorporated by reference into this news release, for further information on the composition of and, where required, reconciliation of these measures. |
(2) | "Free cash flow" is a non-GAAP financial measure defined as cash flow less capital expenditures, excluding acquisitions and dispositions. Free cash flow is prior to dividend payments. See "Non-GAAP and Other Financial Measures" in this news release. |
(3) | "Net debt" is a capital management measure. See "Non-GAAP and Other Financial Measures" in this news release and in the Annual MD&A. |
(4) | "Cash flow" is a non-GAAP financial measure defined as cash flow from operating activities adjusted for the change in non-cash working capital (deficit) and current taxes. See "Non-GAAP and Other Financial Measures" in this news release and in the Annual MD&A. |
(5) | "Operating netback" is a non-GAAP financial measure. See "Non-GAAP and Other Financial Measures" in this news release and in the Annual MD&A. |
(6) | "Cash flow per diluted share" is a non-GAAP financial ratio. Cash flow, a non-GAAP financial measure, is used as a component of the non-GAAP financial ratio. See "Non-GAAP and Other Financial Measures" in this news release and in the Annual MD&A. |
(7) | Strip Pricing as of March 2, 2026. |
(8) | Reserves are "Company gross reserves", which are defined as the working interest share of reserves prior to the deduction of interest owned by others (burdens). Royalty interest reserves are not included in Company gross reserves. |
(9) | As reported by Daily Oil Bulletin Energy on February 25, 2026. |
Three Months Ended December 31, | Twelve Months Ended December 31, | ||||||
2025 | 2024 | Change | 2025 | 2024 | Change | ||
OPERATIONS | |||||||
Production | |||||||
Natural gas (mcf/d) | 3,039,185 | 2,779,365 | 9 % | 2,946,447 | 2,643,532 | 11 % | |
Crude oil, condensate and NGL (bbl/d) | 152,673 | 138,852 | 10 % | 147,121 | 138,584 | 6 % | |
Oil equivalent (boe/d) | 659,204 | 605,413 | 9 % | 638,196 | 579,173 | 10 % | |
Product prices(1) | |||||||
Natural gas ($/mcf) | $ 3.77 | $ 3.48 | 8 % | $ 3.62 | $ 3.38 | 7 % | |
Crude oil, condensate and NGL ($/bbl) | $ 47.08 | $ 56.99 | (17) % | $ 50.27 | $ 54.78 | (8) % | |
Operating expenses ($/boe) | $ 4.66 | $ 4.52 | 3 % | $ 4.93 | $ 4.75 | 4 % | |
Transportation costs ($/boe) | $ 5.06 | $ 4.97 | 2 % | $ 5.14 | $ 5.11 | 1 % | |
Operating netback ($/boe)(2) | $ 16.32 | $ 17.40 | (6) % | $ 16.02 | $ 16.26 | (1) % | |
Cash general and | $ 0.69 | $ 0.82 | (16) % | $ 0.78 | $ 0.77 | 1 % | |
FINANCIAL | |||||||
Commodity sales from production | |||||||
Total revenue from commodity sales and realized gains | 1,714,660 | 1,623,819 | 6 % | 6,591,299 | 6,044,773 | 9 % | |
Royalties | 135,121 | 125,699 | 7 % | 513,879 | 509,252 | 1 % | |
Cash flow | 890,117 | 850,330 | 5 % | 3,395,570 | 3,218,491 | 6 % | |
Cash flow per share (diluted) | $ 2.29 | $ 2.27 | 1 % | $ 8.84 | $ 8.93 | (1) % | |
Net earnings | (655,002) | 407,445 | (261) % | 262,672 | 1,264,109 | (79) % | |
Net earnings per share (diluted) | $ (1.69) | $ 1.09 | (255) % | $ 0.68 | $ 3.51 | (81) % | |
Capital expenditures (net of dispositions)(2) | 827,986 | 460,193 | 80 % | 2,932,280 | 1,901,461 | 54 % | |
Weighted average shares outstanding (diluted) | 383,938,857 | 360,249,193 | 7 % | ||||
Net debt | (1,523,871) | (1,702,732) | (11) % | ||||
PROVED + | |||||||
Natural gas (bcf) | 27,671.4 | 24,837.0 | 11 % | ||||
Crude oil (mbbls) | 124,518 | 119,331 | 4 % | ||||
Natural gas liquids (mbbls) | 1,355,332 | 1,236,385 | 10 % | ||||
Mboe | 6,091,751 | 5,495,212 | 11 % | ||||
Notes: | |
(1) | Product prices include realized gains and losses on risk management activities and financial instrument contracts. |
(2) | See "Non-GAAP and Other Financial Measures" in this news release and in the Annual MD&A. |
(3) | Excluding interest and financing charges. |
(4) | Reserves are "Company gross reserves", which are defined as the working interest share of reserves prior to the deduction of interest owned by others (burdens). Royalty interest reserves are not included in Company gross reserves. |
The following tables summarize the Company's gross reserves defined as the working interest share of reserves prior to the deduction of interest owned by others (burdens). Royalty interest reserves are not included in Company gross reserves. Company net reserves are defined as the working net carried and royalty interest reserves after deduction of all applicable burdens.
Reserves and Future Net Revenue Data (Forecast Prices and Costs)
Summary of Crude Oil, Natural Gas and Natural Gas Liquids Reserves and
Net Present Values of Future Net Revenue
as of December 31, 2025
Forecast Prices and Costs(1)
Light & Medium Crude Oil | Conventional Natural Gas | Shale Natural Gas(2) | Natural Gas Liquids | Total Oil Equivalent | ||||||
Reserves Category | Company Gross | Company Net | Company Gross | Company Net | Company Gross | Company Net | Company Gross | Company Net | Company Gross (Mboe) | Company Net (Mboe) |
Proved Developed Producing | 21,160 | 17,174 | 3,055,049 | 2,735,539 | 3,718,591 | 3,177,927 | 320,480 | 259,711 | 1,470,580 | 1,262,462 |
Proved Developed Non-Producing | 913 | 719 | 77,273 | 69,212 | 235,875 | 207,971 | 14,957 | 12,073 | 68,061 | 58,989 |
Proved Undeveloped | 46,004 | 35,868 | 2,707,566 | 2,420,305 | 5,028,848 | 4,397,996 | 381,895 | 306,033 | 1,717,302 | 1,478,285 |
Total Proved | 68,077 | 53,760 | 5,839,887 | 5,225,056 | 8,983,313 | 7,783,894 | 717,332 | 577,817 | 3,255,943 | 2,799,735 |
Total Probable | 56,441 | 44,105 | 3,887,703 | 3,405,262 | 8,960,502 | 7,602,413 | 638,000 | 483,364 | 2,835,808 | 2,362,082 |
Total Proved Plus Probable | 124,518 | 97,865 | 9,727,590 | 8,630,317 | 17,943,815 | 15,386,307 | 1,355,332 | 1,061,181 | 6,091,751 | 5,161,817 |
Reserves Category | Net Present Values of Future Net Revenue ($000s) | |||||||||||||
Before Income Taxes Discounted at | After Income Taxes Discounted at(3) | Unit Value Before | ||||||||||||
0 | 5 | 8 | 10 | 15 | 20 | 0 | 5 | 8 | 10 | 15 | 20 | ($/Boe) | ($/Mcfe) | |
Proved Developed Producing | 22,301,966 | 17,992,059 | 16,036,155 | 14,951,707 | 12,814,736 | 11,253,708 | 18,441,419 | 15,077,840 | 13,505,660 | 12,627,256 | 10,885,272 | 9,604,416 | 11.84 | 1.97 |
Proved Developed Non-Producing | 1,676,830 | 1,274,026 | 1,096,787 | 998,260 | 803,042 | 660,138 | 1,243,603 | 944,800 | 812,099 | 738,132 | 591,280 | 483,594 | 16.92 | 2.82 |
Proved Undeveloped | 22,289,928 | 13,562,876 | 10,305,918 | 8,646,213 | 5,674,702 | 3,770,473 | 16,576,660 | 9,821,393 | 7,287,783 | 5,997,234 | 3,693,228 | 2,227,362 | 5.85 | 0.97 |
Total Proved | 46,268,724 | 32,828,961 | 27,438,860 | 24,596,180 | 19,292,480 | 15,684,319 | 36,261,681 | 25,844,033 | 21,605,541 | 19,362,623 | 15,169,781 | 12,315,371 | 8.79 | 1.46 |
Total Probable | 47,073,880 | 23,307,656 | 16,451,121 | 13,361,389 | 8,489,541 | 5,799,002 | 34,976,107 | 17,159,157 | 12,006,018 | 9,687,734 | 6,046,297 | 4,051,063 | 5.66 | 0.94 |
Total Proved Plus Probable | 93,342,604 | 56,136,618 | 43,889,981 | 37,957,569 | 27,782,020 | 21,483,321 | 71,237,789 | 43,003,190 | 33,611,559 | 29,050,357 | 21,216,078 | 16,366,435 | 7.35 | 1.23 |
Notes: | |
(1) | Numbers may not add due to rounding. |
(2) | Shale Natural Gas is required to be presented separately from Conventional Natural Gas as its own product type pursuant to National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities ("NI 51-101"). While the Tourmaline Montney reserves do not strictly fit the definition of "shale gas" as defined in NI 51-101 because the natural gas is not "primarily adsorbed" as stated within the definition, the Montney reserves have been included as shale gas for purposes of this disclosure. |
(3) | The after-tax net present value of the Company's oil and gas reserves reflects Company-level tax pools. The Company's financial statements and management's discussion and analysis should be consulted for information at the Company level. |
Total Future Net Revenue ($000s)
(Undiscounted)
as of December 31, 2025
Forecast Prices and Costs(1)
Reserves Category | Revenue | Royalties | Operating | Capital | Abandonment | Future Net | Income | Future Net |
Proved Developed Producing | 44,048,706 | 6,307,932 | 12,849,844 | 81,045 | 2,507,918 | 22,301,966 | 3,860,547 | 18,441,419 |
Proved Developed Non-Producing | 2,767,252 | 371,004 | 548,968 | 113,251 | 57,200 | 1,676,830 | 433,228 | 1,243,603 |
Proved Undeveloped | 55,161,594 | 8,535,555 | 11,285,023 | 12,392,477 | 658,610 | 22,289,928 | 5,713,268 | 16,576,660 |
Total Proved | 101,977,552 | 15,214,491 | 24,683,836 | 12,586,772 | 3,223,728 | 46,268,724 | 10,007,043 | 36,261,681 |
Total Probable | 98,478,991 | 18,257,702 | 22,549,878 | 9,655,820 | 941,711 | 47,073,880 | 12,097,772 | 34,976,107 |
Total Proved Plus Probable | 200,456,543 | 33,472,193 | 47,233,714 | 22,242,592 | 4,165,439 | 93,342,604 | 22,104,815 | 71,237,789 |
Notes: | |
(1) | Numbers may not add due to rounding. |
(2) | Abandonment and Reclamation Costs includes all active and inactive assets, with or without associated reserves, inclusive of all wells (existing and undrilled), facilities and pipelines. |
(3) | The after-tax net present value of the Company's oil and gas reserves reflects Company-level tax pools. The Company's financial statements and management's discussion and analysis should be consulted for information at the Company level. |
Summary of Pricing and Inflation Rate Assumptions
Forecast Prices and Costs (1)
Year | Inflation % | Crude Oil and Natural Gas Liquids Pricing | ||||||||
CAD/USD | NYMEXWTI Near | MSW, Light | Alberta Natural Gas Liquids | |||||||
Constant | Then | Spec | Edmonton | Edmonton | Edmonton | |||||
2026 | 0.0 | 0.728 | 59.92 | 59.92 | 77.54 | 9.59 | 25.10 | 36.95 | 80.01 | |
2027 | 2.0 | 0.737 | 63.82 | 65.10 | 83.60 | 10.64 | 27.28 | 39.79 | 86.19 | |
2028 | 2.0 | 0.740 | 67.55 | 70.28 | 90.18 | 11.34 | 29.67 | 42.87 | 92.83 | |
2029 | 2.0 | 0.740 | 67.78 | 71.93 | 92.32 | 11.66 | 30.37 | 43.89 | 95.05 | |
2030 | 2.0 | 0.740 | 67.79 | 73.37 | 94.17 | 11.89 | 30.98 | 44.77 | 96.94 | |
2031 | 2.0 | 0.740 | 67.79 | 74.84 | 96.06 | 12.14 | 31.60 | 45.67 | 98.89 | |
2032 | 2.0 | 0.740 | 67.79 | 76.34 | 97.98 | 12.39 | 32.23 | 46.58 | 100.87 | |
2033 | 2.0 | 0.740 | 67.79 | 77.87 | 99.93 | 12.64 | 32.87 | 47.51 | 102.88 | |
2034 | 2.0 | 0.740 | 67.79 | 79.42 | 101.93 | 12.90 | 33.53 | 48.46 | 104.94 | |
2035 | 2.0 | 0.740 | 67.79 | 81.01 | 103.97 | 13.17 | 34.20 | 49.43 | 107.04 | |
2036 | 2.0 | 0.740 | 67.79 | 82.63 | 106.05 | 13.43 | 34.89 | 50.42 | 109.18 | |
2037 | 2.0 | 0.740 | 67.79 | 84.29 | 108.17 | 13.70 | 35.58 | 51.43 | 111.36 | |
2038 | 2.0 | 0.740 | 67.79 | 85.97 | 110.34 | 13.97 | 36.30 | 52.46 | 113.59 | |
2039 | 2.0 | 0.740 | 67.79 | 87.69 | 112.54 | 14.25 | 37.02 | 53.51 | 115.86 | |
2040 | 2.0 | 0.740 | 67.79 | 89.45 | 114.79 | 14.54 | 37.76 | 54.58 | 118.18 | |
2041+ | 2.0 | 0.740 | 67.79 | +2.0%/yr | +2.0%/yr | +2.0%/yr | +2.0%/yr | +2.0%/yr | +2.0%/yr | |
Year | Natural Gas and Sulphur Pricing | ||||||||||||
NYMEX Henry Hub | Midwest | AECO/NIT Then | Alberta Plant Gate | Huntingdon/ | British Columbia | Dutch TTF | JKM | ||||||
Spot | ARP $Cdn/ | Westcoast | Spot Plant Gate | ||||||||||
Constant | Then Current | Dawn Price @ Ontario Then | Constant | Then | |||||||||
2026 | 3.74 | 3.74 | 3.47 | 3.00 | 3.51 | 2.78 | 2.78 | 2.78 | 2.41 | 2.66 | 2.25 | 10.19 | 9.20 |
2027 | 3.70 | 3.78 | 3.55 | 3.30 | 3.54 | 3.02 | 3.08 | 3.08 | 3.56 | 3.07 | 2.65 | 9.94 | 9.70 |
2028 | 3.70 | 3.85 | 3.63 | 3.49 | 3.61 | 3.13 | 3.26 | 3.26 | 3.64 | 3.25 | 2.83 | 10.19 | 10.40 |
2029 | 3.71 | 3.93 | 3.70 | 3.58 | 3.69 | 3.16 | 3.35 | 3.35 | 3.72 | 3.34 | 2.92 | 10.50 | 11.08 |
2030 | 3.70 | 4.01 | 3.78 | 3.65 | 3.77 | 3.16 | 3.42 | 3.42 | 3.80 | 3.41 | 2.98 | 10.71 | 11.30 |
2031 | 3.70 | 4.09 | 3.85 | 3.72 | 3.85 | 3.16 | 3.49 | 3.49 | 3.89 | 3.47 | 3.04 | 10.92 | 11.53 |
2032 | 3.70 | 4.17 | 3.94 | 3.80 | 3.93 | 3.17 | 3.57 | 3.57 | 3.97 | 3.54 | 3.11 | 11.14 | 11.76 |
2033 | 3.70 | 4.26 | 4.01 | 3.88 | 4.02 | 3.17 | 3.64 | 3.64 | 4.06 | 3.62 | 3.18 | 11.36 | 11.99 |
2034 | 3.70 | 4.34 | 4.10 | 3.95 | 4.10 | 3.17 | 3.72 | 3.72 | 4.14 | 3.69 | 3.25 | 11.59 | 12.23 |
2035 | 3.70 | 4.43 | 4.17 | 4.03 | 4.18 | 3.17 | 3.79 | 3.79 | 4.23 | 3.77 | 3.32 | 11.82 | 12.49 |
2036 | 3.70 | 4.52 | 4.26 | 4.11 | 4.27 | 3.17 | 3.87 | 3.87 | 4.32 | 3.84 | 3.39 | 12.06 | 12.74 |
2037 | 3.70 | 4.61 | 4.34 | 4.20 | 4.35 | 3.17 | 3.95 | 3.95 | 4.40 | 3.92 | 3.46 | 12.30 | 12.99 |
2038 | 3.70 | 4.70 | 4.43 | 4.28 | 4.44 | 3.17 | 4.02 | 4.02 | 4.49 | 4.00 | 3.52 | 12.55 | 13.25 |
2039 | 3.70 | 4.79 | 4.52 | 4.36 | 4.53 | 3.17 | 4.11 | 4.11 | 4.58 | 4.08 | 3.60 | 12.80 | 13.52 |
2040 | 3.70 | 4.89 | 4.61 | 4.45 | 4.62 | 3.17 | 4.19 | 4.19 | 4.67 | 4.16 | 3.67 | 13.05 | 13.79 |
2041+ | 3.70 | +2.0%/yr | +2.0%/yr | +2.0%/yr | +2.0%/yr | 3.17 | +2.0%/yr | +2.0%/yr | +2.0%/yr | +2.0%/yr | +2.0%/yr | +2.0%/yr | +2.0%/yr |
Notes: | |
(1) | Crude oil and natural gas benchmark reference pricing, inflation and exchange rates utilized by GLJ in the GLJ Reserve Report and Deloitte LLP in the Deloitte Reserve Report, were an equal weighted average of the December 31, 2025 price forecasts published by GLJ and McDaniel & Associates Consultants Ltd. as at January 1, 2026 and Sproule Associates Ltd. as at December 31, 2025 (each of which is available on their respective websites at www.gljpc.com, www.mcdan.com and www.sproule.com). GLJ assigns a value to the Company's existing physical diversification contracts for natural gas at consuming market regions including U.S. Gulf Coast, U.S. Midwest, U.S. West and Canadian East, and international markets based on forecasted differentials to NYMEX Henry Hub as per the aforementioned consultant average price forecast, contracted volumes and transportation costs. No incremental value is assigned to potential future contracts which were not in place as of December 31, 2025. |
The following tables highlight Tourmaline's reserves, F&D and FD&A costs as well as the associated recycle ratios.
Reserves, Capital Expenditures and Cash Flow(1)
As at, and for the Year ended December 31, | 2025 | 2024 | 2023 |
Reserves (Mboe) | |||
Proved Producing | 1,470,580 | 1,345,354 | 1,204,499 |
Total Proved | 3,255,943 | 2,912,173 | 2,614,619 |
Proved Plus Probable | 6,091,751 | 5,495,212 | 5,008,374 |
Capital Expenditures ($ millions) | |||
Exploration and Development(2) | 2,989 | 2,226 | 2,023 |
Net Property Acquisitions (Dispositions)(3) | 229 | (325) | 51 |
Corporate Acquisitions(3) | 502 | 1,709 | 1,442 |
Total(4) | 3,720 | 3,610 | 3,516 |
Cash Flow ($/boe) | |||
Cash Flow | 14.58 | 15.18 | 19.52 |
Cash Flow - Three Year Average | 16.26 | 20.20 | 21.58 |
Notes: | |
(1) | Cash flow is defined as cash provided by operations adjusted for the change in non-cash operating working capital (deficit) and current income taxes. See "Non-GAAP and Other Financial Measures" below and in the Annual MD&A for further discussion. |
(2) | Includes capitalized G&A of $51 million, $45 million and $43 million for 2025, 2024 and 2023, respectively. |
(3) | Includes purchase price (cash and/or common shares) plus net debt, if applicable. |
(4) | Represents the capital expenditures used for purposes of F&D and FD&A calculations. |
Finding and Development Costs
Finding and Development Costs, Excluding FDC | 2025 | 2024 | 2023 | 3-Year Avg. |
Total Proved | ||||
Reserve Additions (MMboe) | 387.8 | 232.8 | 209.3 | |
F&D Costs ($/boe) | 7.71 | 9.56 | 9.66 | 8.72 |
F&D Recycle Ratio(1) | 1.9 | 1.6 | 2.0 | 1.9 |
Total Proved Plus Probable | ||||
Reserve Additions (MMboe) | 457.5 | 167.1 | 230.7 | |
F&D Costs ($/boe) | 6.53 | 13.32 | 8.77 | 8.46 |
F&D Recycle Ratio(1) | 2.2 | 1.1 | 2.2 | 1.9 |
Finding and Development Costs, Including FDC | 2025 | 2024 | 2023 | 3-Year Avg. |
Total Proved | ||||
Change in FDC ($ millions) | 1,669.4 | (161.5) | 231.8 | |
Reserve Additions (MMboe) | 387.8 | 232.8 | 209.3 | |
F&D Costs ($/boe) | 12.01 | 8.87 | 10.77 | 10.82 |
F&D Recycle Ratio(1) | 1.2 | 1.7 | 1.8 | 1.5 |
Total Proved Plus Probable | ||||
Change in FDC ($ millions) | 2,316.9 | (422.0) | 912.9 | |
Reserve Additions (MMboe) | 457.5 | 167.1 | 230.7 | |
F&D Costs ($/boe) | 11.60 | 10.79 | 12.72 | 11.74 |
F&D Recycle Ratio(1) | 1.3 | 1.4 | 1.5 | 1.4 |
Finding, Development and Acquisition Costs
Finding, Development and Acquisition Costs, Excluding FDC | 2025 | 2024 | 2023 | 3-Year Avg. |
Total Proved | ||||
Reserve Additions (MMboe) | 576.7 | 509.5 | 482.6 | |
FD&A Costs ($/boe) | 6.45 | 7.09 | 7.28 | 6.91 |
FD&A Recycle Ratio(1) | 2.3 | 2.1 | 2.7 | 2.4 |
Total Proved Plus Probable | ||||
Reserve Additions (MMboe) | 829.5 | 698.8 | 698.0 | |
FD&A Costs ($/boe) | 4.48 | 5.17 | 5.04 | 4.87 |
FD&A Recycle Ratio(1) | 3.3 | 2.9 | 3.9 | 3.3 |
Finding, Development and Acquisition Costs, Including FDC | 2025 | 2024 | 2023 | 3-Year Avg. |
Total Proved | ||||
Change in FDC ($ millions) | 2,597.7 | 1,201.6 | 1,654.1 | |
Reserve Additions (MMboe) | 576.7 | 509.5 | 482.6 | |
FD&A Costs ($/boe) | 10.95 | 9.44 | 10.71 | 10.39 |
FD&A Recycle Ratio(1) | 1.3 | 1.6 | 1.8 | 1.6 |
Total Proved Plus Probable | ||||
Change in FDC ($ millions) | 3,820.9 | 1,473.8 | 3,326.1 | |
Reserve Additions (MMboe) | 829.5 | 698.8 | 698.0 | |
FD&A Costs ($/boe) | 9.09 | 7.28 | 9.80 | 8.74 |
FD&A Recycle Ratio(1) | 1.6 | 2.1 | 2.0 | 1.9 |
Note: | |
(1) | The recycle ratio is calculated by dividing the cash flow per boe by the appropriate F&D or FD&A costs related to the reserve additions for that year. |
Conference Call Tomorrow at 9:00 a.m. MT (11:00 a.m. ET)
Tourmaline will host a conference call tomorrow, March 5, 2026 starting at 9:00 a.m. MT (11:00 a.m. ET).
To participate without operator assistance, you may register and enter your phone number at https://emportal.ink/4c60ro6 to receive an instant automated call back.
To participate using an operator, please dial 1-888-510-2154 (toll-free in North America), or 1-437-900-0527 (international dial-in), a few minutes prior to the conference call.
REPLAY DETAILS
If you are unable to dial into the live conference call on March 5, 2026, a replay will be available by dialing 1-888-660-6345 (international 1-289-819-1450), referencing Replay Code 13689. The recording will expire on March 19, 2026.
Reader Advisories
CURRENCY
All amounts in this news release are stated in Canadian dollars unless otherwise specified.
This news release contains forward-looking information and statements (collectively, "forward-looking information") within the meaning of applicable securities laws. The use of any of the words "forecast", "expect", "anticipate", "continue", "estimate", "objective", "ongoing", "on track", "may", "will", "project", "should", "believe", "plans", "intends" and similar expressions are intended to identify forward-looking information. More particularly and without limitation, this news release contains forward-looking information concerning Tourmaline's plans and other aspects of its anticipated future operations, management focus, objectives, strategies, financial, operating and production results and business opportunities, including the following: anticipated petroleum and natural gas production and production growth for various periods including estimated average production levels for Q1 2026 and full-year 2026; the reduction in estimated average ethane production levels and estimated increased 2026 and 2027 operating netbacks following the termination of the Company's use of discretionary deep cut gas processing; the use of proceeds from the sale of the Company's PRH Complex and the reduction in operating costs resulting from such sale; the Company's long-term net debt target; the anticipated 2026 full year EP capital program and the reduction thereto, including the impact on production guidance resulting from such reduction; anticipated commodity price improvement; the 2026 EP capital program; 2026 CF and FCF; the expected CF and FCF increases resulting from a U.S. $0.10/mcf tightening of the AECO basis; the expected CF and FCF increases resulting from a U.S. $1.00/mcf increase in both TTF and JKM pricing; production levels, CF, FCF and other information included in the Company's EP Plan; average production volumes exposed to international pricing in 2026 (JKM/TTF); expected interest cost reductions resulting from lower debt levels and the Company's commercial paper program; anticipated capital cost reductions resulting from the vertical integration of the Company's sand business; the anticipated growth, margin expansion and improvement in all operating metrics associated with the NEBC Montney infrastructure and development project; expected total cost reductions that the Company expects to realize by 2031 as a result of operating cost reductions and sand-related capital savings, and the flow through to lower corporate break evens and FCF margin improvement; the number of wells that the Company plans to drill and complete in 2026; the expectation that the EP capital budget reduction will not impact the original start up timing of the Aitken and Groundbirch/Monias gas plant projects in NEBC; the future declaration and payment of base and special dividends and the timing, cadence and amount thereof; the expansion of Tourmaline's market diversification portfolio; the timing and scale of future growth and developments projects, including the NEBC infrastructure build out; projected operating and drilling costs and drilling times; anticipated future commodity prices; the number of new compressed natural gas fueling stations that are planned for 2026; the expectation that sustained stronger pricing and the Company's ongoing margin improvement activities will lead to further base dividend increases in the future and that special dividends will be used in those periods of extremely strong pricing to return the majority of the incremental FCF to shareholders; as well as Tourmaline's future drilling locations, prospects and plans, business strategy, future development and growth opportunities, prospects and asset base. The forward-looking information is based on certain key expectations and assumptions made by Tourmaline, including expectations and assumptions concerning the following: prevailing and future commodity prices and currency exchange and interest rates; applicable royalty rates and tax laws; future well production rates and reserve volumes; operating costs, the timing of receipt of regulatory approvals; the performance of existing and future wells; the success obtained in drilling new wells; anticipated timing and results of capital expenditures; the sufficiency of budgeted capital expenditures in carrying out planned activities; the timing, location and extent of future drilling operations; the successful completion of acquisitions and dispositions and the benefits to be derived therefrom; the state of the economy and the exploration and production business; the availability and cost of financing, labour and services; ability to maintain its investment grade credit rating; and ability to market crude oil, natural gas and NGL successfully. Without limitation of the foregoing, future dividend payments, if any, and the level thereof is uncertain, as the Company's dividend policy and the funds available for the payment of dividends from time to time is dependent upon, among other things, FCF, financial requirements for the Company's operations and the execution of its growth strategy, fluctuations in working capital and the timing and amount of capital expenditures, debt service requirements and other factors beyond the Company's control. Further, the ability of Tourmaline to pay dividends is subject to applicable laws (including the satisfaction of the solvency test contained in applicable corporate legislation) and contractual restrictions contained in the instruments governing its indebtedness, including its credit facility.
Statements relating to "reserves" are also deemed to be forward looking information, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated and that the reserves can be profitably produced in the future.
Although Tourmaline believes that the expectations and assumptions on which such forward-looking information is based are reasonable, undue reliance should not be placed on the forward-looking information because Tourmaline can give no assurances that it will prove to be correct. Since forward-looking information addresses future events and conditions, by its very nature it involves inherent risks and uncertainties. Actual results could differ materially from those currently anticipated due to a number of factors and risks. These include, but are not limited to: the risks associated with the oil and gas industry in general such as operational risks in development, exploration and production; delays or changes in plans with respect to exploration or development projects or capital expenditures; supply chain disruptions; the uncertainty of estimates and projections relating to reserves, production, revenues, costs and expenses; health, safety and environmental risks; commodity price and exchange rate fluctuations; interest rate fluctuations; changes in rates of inflation; marketing and transportation; loss of markets; environmental risks; competition; incorrect assessment of the value of acquisitions; failure to complete or realize the anticipated benefits of acquisitions or dispositions; hazards such as fire, explosion, blowouts, cratering, and spills, any of which could result in substantial damage to wells, production facilities, other property and the environment or in personal injury; stock market volatility; ability to access sufficient capital from internal and external sources; uncertainties associated with counterparty credit risk; failure to obtain required regulatory and other approvals including drilling permits and the impact of not receiving such approvals on the Company's long-term planning; climate change risks; severe weather (including wildfires, floods and drought); risks of wars or other hostilities or geopolitical events, civil insurrection and pandemics; risks relating to Indigenous land claims and duty to consult; data breaches and cyber attacks; risks relating to the use of artificial intelligence; changes in legislation, including but not limited to tax laws, royalties and environmental regulations (including greenhouse gas emission reduction requirements and other decarbonization or social policies and including uncertainty with respect to the interpretation and impact of omnibus Bill C-59 and the related amendments to the Competition Act (Canada)); trade policy, barriers, disputes or wars (including new tariffs or changes to existing international trade arrangements); and general economic and business conditions and markets. Readers are cautioned that the foregoing list of factors is not exhaustive.
Additional information on these and other factors that could affect Tourmaline, or its operations or financial results, are included in the Company's most recently filed Management's Discussion and Analysis (See "Forward-Looking Statements" therein), Annual Information Form (See "Risk Factors" and "Forward-Looking Statements" therein) and other reports on file with applicable securities regulatory authorities and may be accessed through the SEDAR+ website (www.sedarplus.ca) or Tourmaline's website (www.tourmalineoil.com).
The forward-looking information contained in this news release is made as of the date hereof and Tourmaline undertakes no obligation to update publicly or revise any forward-looking information, whether as a result of new information, future events or otherwise, unless expressly required by applicable securities laws.
The reserves data set forth above is based upon the reports of GLJ Ltd. ("GLJ") and Deloitte LLP, each dated effective December 31, 2025, which have been consolidated into one report by GLJ and adjusted to apply certain of GLJ's assumptions and methodologies and pricing and cost assumptions. The price forecast used in the reserve evaluations is an average of forecast prices published by Sproule Associates Ltd. as at December 31, 2025 and GLJ and McDaniel & Associates Consultants Ltd. as at January 1, 2026 (each of which is available on their respective websites at www.sproule.com, www.gljpc.com, and www.mcdan.com), and will be contained in the Company's Annual Information Form for the year ended December 31, 2025, which will be filed on SEDAR+ (accessible at www.sedarplus.ca) on or before March 31, 2026.
There are numerous uncertainties inherent in estimating quantities of crude oil, natural gas and NGL reserves and the future cash flows attributed to such reserves. The reserve and associated cash flow information set forth above are estimates only. In general, estimates of economically recoverable crude oil, natural gas and NGL reserves and the future net cash flows therefrom are based upon a number of variable factors and assumptions, such as historical production from the properties, production rates, ultimate reserve recovery, timing and amount of capital expenditures, marketability of oil and natural gas, royalty rates, the assumed effects of regulation by governmental agencies and future operating costs, all of which may vary materially. For those reasons, estimates of the economically recoverable crude oil, NGL and natural gas reserves attributable to any particular group of properties, classification of such reserves based on risk of recovery and estimates of future net revenues associated with reserves prepared by different engineers, or by the same engineers at different times, may vary. The Company's actual production, revenues, taxes and development and operating expenditures with respect to its reserves will vary from estimates thereof and such variations could be material.
All evaluations and reviews of future net revenue are stated prior to any provisions for interest costs or general and administrative costs and after the deduction of estimated future capital expenditures for wells to which reserves have been assigned. The after-tax net present value of the Company's oil and gas properties reflects the tax burden on the properties on a stand-alone basis and utilizes the Company's tax pools. It does not consider the corporate tax situation, or tax planning. It does not provide an estimate of the after-tax value of the Company, which may be significantly different. The Company's financial statements and the management's discussion and analysis should be consulted for information at the level of the Company.
The estimates of reserves and future net revenue for individual properties may not reflect the same confidence level as estimates of reserves and future net revenue for all properties, due to effects of aggregations. The estimated values of future net revenue disclosed in this news release do not represent fair market value. There is no assurance that the forecast prices and cost assumptions used in the reserve evaluations will be attained and variances could be material.
The reserve data provided in this news release presents only a portion of the disclosure required under National Instrument 51-101. All of the required information will be contained in the Company's Annual Information Form for the year ended December 31, 2025, which will be filed on (SEDAR+ accessible at www.sedarplus.ca) on or before March 31, 2026.
BOE Equivalency
In this news release, production and reserves information may be presented on a "barrel of oil equivalent" or "BOE" basis. BOEs 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. In addition, as the value ratio between natural gas and crude oil based on the current prices of natural gas and crude oil is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value.
This news release contains metrics commonly used in the oil and natural gas industry. Each of these metrics is determined by the Company as set out below or elsewhere in this news release. These metrics are "F&D" costs, "FD&A" costs, "recycle ratio", "F&D recycle ratio", and "FD&A recycle ratio". These metrics are considered "non-GAAP ratios" and do not have standardized meanings and may not be comparable to similar measures presented by other companies. As such, they should not be used to make comparisons. See "Non-GAAP and Other Financial Measures" in this news release and in the Annual MD&A. The non-GAAP financial measures used as a component of these non-GAAP ratios are capital expenditures and cash flow.
Management uses these oil and gas metrics for its own performance measurements and to provide shareholders with measures to compare the Company's performance over time, however, such measures are not reliable indicators of the Company's future performance and future performance may not compare to the performance in previous periods.
"F&D" costs are calculated by dividing the sum of the total capital expenditures for the year (in dollars) by the change in reserves within the applicable reserves category (in boe). F&D costs, including FDC, includes all capital expenditures in the year as well as the change in FDC required to bring the reserves within the specified reserves category on production.
"FD&A" costs are calculated by dividing the sum of the total capital expenditures for the year inclusive of the net acquisition costs and disposition proceeds (in dollars) by the change in reserves within the applicable reserves category inclusive of changes due to acquisitions and dispositions (in boe). FD&A costs, including FDC, includes all capital expenditures in the year inclusive of the net acquisition costs and disposition proceeds as well as the change in FDC required to bring the reserves within the specified reserves category on production.
The "recycle ratio" is calculated by dividing the cash flow per boe by the appropriate F&D or FD&A costs related to the reserve additions for that year.
The Company uses F&D and FD&A as a measure of the efficiency of its overall capital program including the effect of acquisitions and dispositions. 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 reserves additions for that year.
Also included in this news release are estimates of Tourmaline's 2026 CF and FCF and long-term net debt, which are based on, among other things, the various assumptions as to production levels, receipt of drilling permits, capital expenditures and other assumptions disclosed in this news release and, with respect to 2026 CF and FCF and long-term net debt, Tourmaline's estimated average production of 620,000 – 640,000 boepd, commodity price assumptions for natural gas ($3.85/mmbtu US, $1.88/mcf AECO, $2.49/mmbtu PG&E Citygate U.S., $13.00/mcf JKM U.S.), crude oil ($66.77/bbl WTI U.S.) and an exchange rate assumption (USD/CAD) of $0.74. In addition, such estimates are provided for illustration only and are based on budgets and forecasts as of the date hereof that are subject to change and a variety of contingencies including prior years' results. To the extent such estimates constitute a financial outlook, they are included to provide readers with an understanding of Tourmaline's anticipated CF and FCF and long-term net levels based on the capital expenditure, production, pricing, exchange rate and other assumptions described herein and readers are cautioned that the information may not be appropriate for other purposes.
This news release contains the terms "cash flow", "capital expenditures", "EP expenditures", "free cash flow", and "operating netback", which are considered "non-GAAP financial measures" and the terms "cash flow per diluted share", "free cash flow per diluted share", "operating netback per boe", and "cash flow per-boe", which are considered "non-GAAP financial ratios". These terms do not have a standardized meaning prescribed by GAAP. In addition, this news release contains the terms "adjusted working capital" and "net debt", which are considered "capital management measures" and do not have standardized meanings prescribed by GAAP. Accordingly, the Company's use of these terms may not be comparable to similarly defined measures presented by other companies. Investors are cautioned that these measures should not be construed as an alternative to or more meaningful than the most directly comparable GAAP measures in evaluating the Company's performance. See "Non-GAAP and Other Financial Measures" in the most recent Management's Discussion and Analysis for more information on the definition and description of these terms.
Management uses the term "cash flow" for its own performance measure and to provide shareholders and potential investors with a measurement of the Company's efficiency and its ability to generate the cash (net of current income taxes) necessary to fund its future growth expenditures, to repay debt or to pay dividends. The most directly comparable GAAP measure for cash flow is cash flow from operating activities. A summary of the reconciliation of cash flow from operating activities to cash flow is set forth below:
Three Months Ended | Years Ended | |||||
(000s) | 2025 | 2024 | 2025 | 2024 | ||
Cash flow from operating activities (per GAAP) | $700,112 | $666,110 | $3,387,019 | $2,729,780 | ||
Current income taxes(1) | (11,039) | (36,665) | (33,228) | (65,173) | ||
Current income taxes paid (recovered) | 3,246 | (34) | 31,382 | 526,768 | ||
Change in non-cash working capital (deficit) | 197,798 | 220,919 | 10,397 | 27,116 | ||
Cash flow | $ 890,117 | $850,330 | $ 3,395,570 | $ 3,218,491 | ||
(1) | For the purposes of this reconciliation, current income taxes exclude $11.3 million of income taxes related to the capital gain on the sale of Topaz shares during the three and twelve months ended December 31, 2025 (three and twelve months ended December 31, 2024 - $19.0M). Refer to Notes 11 and 14 of the Company's consolidated financial statements as at and for the year ended December 31, 2025 for further details. |
Management uses the term "capital expenditures" as a measure of capital investment in exploration and production activity, as well as property acquisitions and divestitures. The most directly comparable GAAP measure for capital expenditures is cash flow used in investing activities. A summary of the reconciliation of cash flow used in investing activities to capital expenditures is set forth below:
Three Months Ended | Years Ended | |||
(000s) | 2025 | 2024 | 2025 | 2024 |
Cash flow used in investing activities (per GAAP) | $ 523,856 | $ 123,552 | $2,733,529 | $ 1,638,627 |
Corporate acquisitions | – | (169,040) | – | (169,040) |
Change in non-cash working capital | 82,904 | 174,216 | (10,675) | 100,409 |
Investment in long-term asset | – | – | (11,800) | – |
Proceeds from sale of investments | 221,226 | 331,465 | 221,226 | 331,465 |
Capital expenditures | $ 827,986 | $ 460,193 | $2,932,280 | $ 1,901,461 |
Management uses the term "EP expenditures" or exploration and production expenditures as a measure of capital investment in exploration and production activity, and such spending is compared to the Company's annual budgeted exploration and production expenditures. The most directly comparable GAAP measure for exploration and production spending is cash flow used in investing activities. A summary of the reconciliation of cash flow used in investing activities to exploration and production expenditures is set forth below:
Three Months Ended | Years Ended | |||
(000s) | 2025 | 2024 | 2025 | 2024 |
Cash flow used in investing activities (per GAAP) | $ 523,856 | $123,552 | $2,733,529 | $ 1,638,627 |
Change in non-cash working capital | 82,904 | 174,216 | (10,675) | 100,409 |
Proceeds from sale of investments | 221,226 | 331,465 | 221,226 | 331,465 |
Corporate acquisitions | – | (169,040) | – | (169,040) |
Investment in long-term asset | – | – | (11,800) | – |
Property acquisitions | (2,024) | (7,379) | (19,307) | (33,083) |
Proceeds from divestitures | 801 | 300,858 | 75,622 | 357,692 |
Other | (14,028) | (10,256) | (62,883) | (52,607) |
Exploration and production expenditures | $ 812,735 | $ 743,416 | $2,925,712 | $ 2,173,463 |
Management uses the term "free cash flow" for its own performance measure and to provide shareholders and potential investors with a measurement of the Company's efficiency and its ability to generate the cash necessary to fund its future growth expenditures, to repay debt and provide shareholder returns. Free cash flow is defined as cash flow less capital expenditures, excluding acquisitions and dispositions. Free cash flow is prior to dividend payment. The most directly comparable GAAP measure for cash flow is cash flow from operating activities. See "Non-GAAP Financial Measures – Cash Flow" and " Non-GAAP Financial Measures – Capital Expenditures" above.
Three Months Ended | Years Ended | |||
(000s) | 2025 | 2024 | 2025 | 2024 |
Cash flow | $ 890,117 | $850,330 | $3,395,570 | $ 3,218,491 |
Capital expenditures | (827,986) | (460,193) | (2,932,280) | (1,901,461) |
Property acquisitions | 2,024 | 7,379 | 19,307 | 33,083 |
Proceeds from divestitures | (801) | (300,858) | (75,622) | (357,692) |
Free Cash Flow | $63,354 | $ 96,658 | $ 406,975 | $992,421 |
Management uses the term "operating netback" as a key performance indicator and one that is commonly presented by other oil and natural gas producers. Operating netback is defined as the sum of commodity sales from production, premium on risk management activities and realized gain on financial instruments less the sum of royalties, transportation costs and operating expenses. A summary of the reconciliation of operating netback from commodity sales from production, which is a GAAP measure, is set forth below:
Three Months Ended | Years Ended | |||
(000s) | 2025 | 2024 | 2025 | 2024 |
Commodity sales from production | $ 1,423,017 | $1,215,050 | $4,940,024 | $4,729,771 |
Premium on risk management activities | 202,830 | 280,791 | 1,230,294 | 828,468 |
Realized gain on financial instruments | 88,813 | 127,978 | 420,981 | 486,534 |
Royalties | (135,121) | (125,699) | (513,879) | (509,252) |
Transportation costs | (306,801) | (276,602) | (1,198,061) | (1,082,592) |
Operating expenses | (282,530) | (251,594) | (1,148,182) | (1,006,541) |
Operating netback | $ 990,208 | $969,924 | $3,731,177 | $3,446,388 |
Non-GAAP Financial Ratios
Management calculates "operating netback per-boe" as operating netback divided by total production for the period. Operating netback per-boe is a key performance indicator and measure of operational efficiency and one that is commonly presented by other oil and natural gas producers. A summary of the calculation of operating netback per boe is set forth below:
Three Months Ended | Years Ended | |||
($/boe) | 2025 | 2024 | 2025 | 2024 |
Revenue, excluding processing income | $ 28.27 | $ 29.15 | $ 28.30 | $ 28.52 |
Royalties | (2.23) | (2.26) | (2.21) | (2.40) |
Transportation costs | (5.06) | (4.97) | (5.14) | (5.11) |
Operating expenses | (4.66) | (4.52) | (4.93) | (4.75) |
Operating netback | $ 16.32 | $ 17.40 | $ 16.02 | $ 16.26 |
Management uses cash flow per boe to highlight how much cash flow is generated by each boe produced. The ratio is calculated by dividing cash flow by total production for the period. See "Non-GAAP Financial Measures – Cash Flow". See "Reserves Performance Ratios" section for information on annual cash flow per boe and comparative period data used.
See "Reserves Performance Ratios" and "Industry Metrics" for information on the composition of the non-GAAP financial measures used as a component of and comparative period data for finding and development costs, finding, development and acquisition costs and recycle ratio.
Capital Management Measures
Management uses the term "adjusted working capital" for its own performance measures and to provide shareholders and potential investors with a measurement of the Company's liquidity. A summary of the reconciliation of working capital (deficit) to adjusted working capital (deficit), is set forth below:
As at December 31, | ||
(000s) | 2025 | 2024 |
Working capital (deficit) | $ (419,306) | $ (167,623) |
Fair value of financial instruments – short-term (asset) | (135,676) | (315,365) |
Lease liabilities – short-term | 8,034 | 8,385 |
Decommissioning obligations – short-term | 75,000 | 60,000 |
Unrealized foreign exchange in working capital – (asset) liability | 991 | (15,354) |
Adjusted working capital (deficit) | $ (470,957) | $(429,957) |
Management uses the term "net debt", as a key measure for evaluating its capital structure and to provide shareholders and potential investors with a measurement of the Company's total indebtedness. A summary of the composition of net debt, is set forth below:
As at December 31, | ||
(000s) | 2025 | 2024 |
Long-term debt | $ (1,052,914) | $ (1,272,775) |
Adjusted working capital (deficit) | (470,957) | (429,957) |
Net debt | $ (1,523,871) | $ (1,702,732) |
The following measures are supplementary financial measures: cash flow per diluted share, reserve value per diluted share, operating expenses ($/boe), cash general and administrative expenses ($/boe) and transportation costs ($/boe). These measures are calculated by dividing the numerator by a diluted share count or by total production for the period, depending on the financial measure discussed.
ESTIMATED DRILLING INVENTORY
This news release discloses drilling locations. Drilling locations are categorized as follows: (i) proved undeveloped locations; (ii) probable undeveloped locations; (iii) unbooked locations; and (iv) an aggregate total of (i), (ii) and (iii). Of the 26,512 (gross) locations disclosed in this news release, 2,316 are proved undeveloped locations (including drilled-uncompleted locations ("DUCs")), 1,757 are probable undeveloped locations, and 22,439 are unbooked. Proved producing wells, proved undeveloped locations, including DUCs, and probable undeveloped locations are booked and derived from the Company's most recent independent reserves evaluation as prepared by GLJ and Deloitte LLP as of December 31, 2025, and account for drilling locations that have associated proved and/or probable reserves, as applicable. Unbooked locations are internal estimates based on the Company's prospective acreage and an assumption as to the number of wells that can be drilled per section based on industry practice and internal review. Unbooked locations do not have attributed reserves or resources (including contingent and prospective). Unbooked locations have been identified by management as an estimation of the Company's multi-year drilling activities based on evaluation of applicable geologic, seismic, engineering, production and reserves information. There is no certainty that the Company will drill all unbooked drilling locations and if drilled there is no certainty that such locations will result in additional oil and gas reserves, resources or production. The drilling locations on which the Company will actually drill wells, including the number and timing thereof is ultimately dependent upon the availability of funding, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results, additional reservoir information that is obtained and other factors. While a certain number of the unbooked drilling locations have been derisked by drilling existing wells in relative close proximity to such unbooked drilling locations, the majority of other unbooked drilling locations are farther away from existing wells where management has less information about the characteristics of the reservoir and therefore there is more uncertainty whether wells will be drilled in such locations and if drilled there is more uncertainty that such wells will result in additional oil and gas reserves, resources or production.
SUPPLEMENTAL INFORMATION REGARDING PRODUCT TYPES
This news release includes references to full-year 2025 average daily production, Q4 2025 average daily production, January 2026 average daily production, Q1 2026 expected average daily production and full-year 2026 expected average daily production. The following table is intended to provide supplemental information about the product type composition for each of the production figures that are provided in this news release:
Light and Medium | Conventional | Shale Natural | Natural Gas | Oil Equivalent | |
Company Gross | Company Gross | Company Gross | Company Gross | Company Gross | |
2025 Average Daily Production | 53,122 | 1,562,414 | 1,384,033 | 93,999 | 638,196 |
Q4 2025 Average Daily Production | 56,295 | 1,591,495 | 1,447,690 | 96,378 | 659,204 |
January 2026 Average Daily Production | 55,500 | 1,660,000 | 1,520,000 | 99,500 | 685,000 |
Q1 2026 Expected Average Daily Production | 51,465 | 1,563,795 | 1,551,165 | 94,375 | 665,000 |
2026 Expected Average Daily Production | 48,450 | 1,515,125 | 1,500,385 | 78,965 | 630,000 |
(1) | For the purposes of this disclosure, condensate has been combined with Light and Medium Crude Oil as the associated revenues and certain costs of condensate are similar to Light and Medium Crude Oil. Accordingly, NGLs in this disclosure exclude condensate. |
See also "Forward-Looking Statements" and "Non-GAAP and Other Financial Measures" in the most recently filed Management's Discussion and Analysis.
Certain Definitions:
1H | first half |
2H | second half |
AECO | Alberta Energy Company and is the Canadian benchmark price for natural gas |
AECO basis | the price differential between AECO and NYMEX Henry Hub |
bbl | barrel |
bbls/day | barrels per day |
bbl/mmcf | barrels per million cubic feet |
bcf | billion cubic feet |
bcfe | billion cubic feet equivalent |
bpd or bbl/d | barrels per day |
boe | barrel of oil equivalent |
boepd or boe/d | barrel of oil equivalent per day |
bopd or bbl/d | barrel of oil, condensate or liquids per day |
C2+ | a hydrocarbon mixture consisting of ethane and heavier hydrocarbons. |
CNG | compressed natural gas |
DUC | drilled but uncompleted wells |
Dutch TTF or TTF | a natural gas pricing location within the Netherlands |
EP | exploration and production |
FERC | Federal Energy Regulatory Commission |
gj | gigajoule |
gjs/d | gigajoules per day |
JKM | Japan Korea Marker |
LPG | Liquefied Petroleum Gas |
mbbls | thousand barrels |
mmbbls | million barrels |
mboe | thousand barrels of oil equivalent |
mboepd | thousand barrels of oil equivalent per day |
mcf | thousand cubic feet |
mcfpd or mcf/d | thousand cubic feet per day |
mcfe | thousand cubic feet equivalent |
mmboe | million barrels of oil equivalent |
mmbtu | million British thermal units |
mmbtu/d | million British thermal units per day |
mmcf | million cubic feet |
mmcfpd or mmcf/d | million cubic feet per day |
MPa | megapascal |
mstb | thousand stock tank barrels |
natural gas | conventional natural gas and shale gas |
NEBC | Northeast British Columbia |
NGL or NGLs | natural gas liquids |
NYMEX Henry Hub | the benchmark pricing point for U.S. natural gas futures contracts traded on the New York Mercantile Exchange |
PGE | Pacific Gas & Electric |
PRH | Peace River High |
Tcf | trillion cubic feet |
MANAGEMENT'S DISCUSSION AND ANALYSIS AND CONSOLIDATED FINANCIAL STATEMENTS
To view Tourmaline's Management's Discussion and Analysis and Consolidated Financial Statements for the periods ended December 31, 2025 and 2024, please refer to SEDAR+ (www.sedarplus.ca) or Tourmaline's website at www.tourmalineoil.com.
Tourmaline is Canada's largest and most active natural gas producer dedicated to producing the lowest-development-cost natural gas in North America. We are an investment grade exploration and production company providing strong and predictable operating and financial performance through the development of our two core areas in the Western Canadian Sedimentary Basin. With our existing large reserve base, decades-long drilling inventory, relentless focus on execution, cost management, safety and environmental performance improvement, we are excited to provide shareholders an excellent return on capital and an attractive source of income through our base dividend and surplus free cash flow distribution strategies.
SOURCE Tourmaline Oil Corp.
For further information, please contact: Tourmaline Oil Corp., Michael Rose, Chairman, President and Chief Executive Officer, (403) 266-5992 OR Tourmaline Oil Corp., Brian Robinson, Chief Financial Officer, (403) 767-3587; [email protected] OR Tourmaline Oil Corp., Scott Kirker, Chief Legal Officer and External Affairs, (403) 767-3593; [email protected] OR Tourmaline Oil Corp., Jamie Heard, Vice President, Capital Markets, (403) 767-5942; [email protected] OR Tourmaline Oil Corp., Suite 2900, 250 - 6th Avenue S.W., Calgary, Alberta T2P 3H7, Phone: (403) 266-5992; Facsimile: (403) 266-5952, E-mail: [email protected], Website: www.tourmalineoil.com
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