Tourmaline Oil Corp. (TOU.TO and TRMLF) Q4 Results - Mar 5

[dan_s]

HIGHLIGHTS

Record Q4 2025 average production of 659,204 boepd and January 2026 average production of over 685,000 boepd. < Below my forecast.

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. < Below my forecast of $4.80/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("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 at year-end 2025 of $1.5 billion, inclusive of the impact of the PRH asset sale, or 0.45x forecasted 2026 cash flow ("CF"), down from Q3 2025 net debt of $2.3 billion. < Very strong balance sheet.

PRODUCTION UPDATE

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.

FINANCIAL RESULTS

This is the KEY STAT for me: Q4 2025 CF was $890 million ($2.29 per fully diluted share). Full year 2025 CF was $3.4 billion ($8.84 per fully diluted share). < Slightly above my forecast.

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). < Tourmaline's strong balance sheet is one of the reasons

CAPITAL BUDGET/EP PLAN

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, 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.

2025 RESERVES

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.

MARKETING UPDATE

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.

COST REDUCTION/MARGIN IMPROVEMENT UPDATE

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.

EP UPDATE

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.
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Bottomline is a solid Canadian upstream company that I added to the Sweet 16 on 1-1-2026 to add more exposure to gas in Western Canada. A high percentage of their gas is sold to into the U.S. market, so they get much higher realized natural gas prices than our other "Gassers".

[dan_s]

THP & Co Equity Research:

Q4 CFPS better vs. estimates on in-line production and marginally higher capex; FY'26 capex reduced with further room to go if macro warrants.

Sector: Upstream | Ticker: TOU-CA | Recommendation: Buy | Target: C$77 | Close: C$66.14 | Market Cap: C$25.6B | Analyst: Jeoffrey Lambujon

Calling the overall update neutral, with highlights including a slight beat on Q4'25 CFPS, confirmation of the PRH asset sale, a prudent reduction (with room for more) to FY'26 capex, that the base dividend ($0.50Cdn/quarter) will solely comprise Q1’26 shareholder returns, and the improvement to the long-term cost reduction outlook.
> On Q4'25 results, production was in-line at 659mboepd vs. TPHe/Street 657/659, with CFPS above expectations, at C$2.29 vs. TPHe/Street C$2.27/C$2.21 (C$890MM absolute vs. TPHe C$883MM);
> Q4'25 capex printed slightly above consensus at C$828MM vs. Street C$773MM.
> On guidance, the FY'26 budget was decreased to C$2.65B from the prior C$3.05B (TPHe/Street C$3.06B/C$3.02B), with the C$400MM reduction including C$350MM E&P (including C$175MM related to the divested PRH complex) and C$50MM of corporate.
> Updated FY'26 production guidance calls for 620-640mboepd vs. prior 690mboepd (TPHe/Street 691/692), with the ~60mboepd midpoint reduction comprised of ~30 PRH, ~20 ethane, and 0-20 deferred spending; Q1 guidance calls for 655-665mboepd (January pre-deal was tracking near estimates at >685mboepd vs. TPHe/Street 683/688).
> On the PRH sale, timing and valuation are TPHe in-line with expectations, given regulatory filings signaled the move and the C$765MM price tag TPHe representing ~4x cash flow, though good to see cash in the door (UOP = C$500MM debt reduction, C$265MM NEBC infra buildout).
> On the ethane component, TOU has elected to terminate its discretionary deliveries in the AB Deep Basin this year as contracts expire, which is to improve operating netbacks by C$65MM in 2026 and C$110MM in 2027.
> Longer-term, the change in spending plans will not affect the expected completion timing of the Aitken (Q4'26) and Groundbirch/Monias (Q4'27) gas plants.
> On today’s call, some near-term items of interest beyond management's macro outlook include (i) the potential for another C$200MM in discretionary capex reductions, (ii) the shareholder returns mix from here (no special declared for Q1’26, attributed to local pricing, slightly earlier than when our model gets there), with the company now under its newly initiated LT net debt target of C$1.75B pro-forma for the PRH sale (~C$1.5B), and (iii) continued progress on cost reductions (long-term opex + tport cost reduction target raised to C$1.50/boe from C$1.00/boe by 2031).

[dan_s]

Natural gas prices below are in $Cdn/mcf. They are getting much higher realized natural gas prices than our other Canadian companies.

The realized average natural gas price for the three months ended December 31, 2025 increased by 8% to
$3.77/mcf from $3.48/mcf for the same period of the prior year. The increase is the result of higher AECO and
Station 2 natural gas benchmark prices in the quarter, partially offset by lower realized gains on risk management
activities and financial instruments. For the year ended December 31, 2025, the realized average natural gas price
was $3.62/mcf, which is 7% higher than the same period of the prior year. The increase is the result of higher
natural gas benchmark prices for the twelve months ended December 31, 2025, at all major hubs, with the
exception of Station 2 and Sumas, where the Company sells its natural gas.