Tourmaline Oil Corp.

Good morning, ladies and gentlemen, and welcome to the Tourmaline Q4 2025 results conference call. At this time, all lines are in listen only mode. Following the presentation, we will conduct a question and answer session. If at any time during this call you require immediate assistance, please press star zero for the operator. This call is being recorded on March 5th, 2026. I would now like to turn the conference over to Scott Kirker. Please go ahead.

Thank you, Operator, and welcome, everyone, to our discussion of Termaline's financial operating results for the quarters and years in December 31, 2025 and December 31, 2024. My name is Scott Kirker, and I'm the Chief Legal Officer here at Termaline. Before we get started, I refer you to the advisories on forward-looking statements contained in the news release, as well as the advisories contained in the Termaline Annual Information Form and our MD&A available on CDAR and on our website. I also draw your attention to the material factors and assumptions in those advisories. I'm here with Mike Rose, Tourmaline's President and Chief Executive Officer, Brian Robinson, our Chief Financial Officer, and Jamie Hurd, Tourmaline's Vice President of Capital Markets. We will start with Mike speaking to some of the highlights of the last quarter and the full 2025 year. After his remarks, we will be open for questions.

Go ahead, Mike. Thanks, Scott, and thanks, everybody who dialed in. So we're pleased to announce our Q4 2025 Disclosure and Reporting and update on 26 activities so far. So a few highlights, we had record production in Q4 of 25, and that carried on and set a new record in January of this year. We added 829 million BOEs of 2P reserves in 25, including a corporate record single year organic 2P addition of 457 million BOEs. We realized continued corporate operating cost reductions in Q4 of 25. down over 9% from the first half of 2025 to current $4.66 per POE. Peace River High asset sale was completed in February 2026 for proceeds of $765 million. And net debt at year-end 25 of $1.5 billion, inclusive of the impact of the Peace River High Asset sale, was down from Q3 25 net debt of $2.3 billion and represents 0.5 times forecasted 26 cash flow. On production, in addition to record Q4 production, our Q4 25 average liquids production was a record 152,673 barrels per day. January 26th, production averaged over 685,000 BOEs per day. That's prior to the sale of the Peace River High asset. We've elected to terminate our discretionary deep cut gas plant deliveries in the Alberta deep basin. Those contracts expire. This will reduce corporate average ethane production volumes by approximately 20,000 barrels per day on a full year basis, but is expected to increase 26 operating net bags by approximately $65 million and forecasted $27 million. operating net back by approximately $110 million, and that's through the elimination of deep cut processing fees, as well as C2 plus transportation and fractionation fees. And really, this is all part of the overall cost reduction and margin improvement initiative that's ongoing. Looking a little deeper at financial results, Q4 25 cash flow was $890 million or $229 per fully diluted share and full year 25 cash flow was $3.4 billion. As mentioned, we've sold the Peace River High Complex to a Canadian senior producer for cash proceeds of $765 million. The company has sold its most mature highest cost production and will replace that with new low cost production streams flowing through newly constructed tourmaline facilities. And although we pioneered the Charity Lake horizontal play in the first place in 2009 and 2010, this disposition allows us to enhance the focus on our two massive natural gas complexes. We intend to utilize the proceeds in the following way, $500 million for permanent long-term debt reduction and the remaining $265 million to fund, in part, the BC infrastructure build-out split between the next two years, and that's the Phase 1 build-out. As mentioned, net debt year-end 2025 was $1.5 billion. and that's down from $2.3 billion in Q3-25. We've set a long-term net debt target of $1.75 billion. A few comments on the capital budget. We have updated the multi-year EP plan and the COV, and it's been updated for results in 25, asset sales, very strong, well-performance, new commodity hedges, and the new cost reduction initiatives that we've realized to date. We believe that during these unusually volatile times, the best business approach is to just steadily reduce debt and continually improve the overall cost structure, and that's exactly what we're doing. Q425 EP CapEx was $813 million, and that was within the original guidance range. The combination of the Peace River High asset sale And the redirection of discretionary deep base and deep cut volumes will reduce total corporate production by a total of approximately 50,000 BUEs per day on a full year basis. Importantly, the 26 full year EP CapEx program will be reduced by $350 million to $2.55 billion, along with a $50 million cut in our non-EP capital program. for a total CapEx reduction of $400 million. This reduction includes the $175 million of originally planned CapEx on the Peace River High Complex and a further $175 million of expenditures in the gas complexes. We believe it's prudent to defer certain gas-focused expenditures until we see a sustained, stronger local price as both ACO and Station 2 prices in the Western Canadian Sedimentary Basin and the prices in the Pacific Northwest and California are unusually low. The gas complex expenditure reductions will have a negligible impact on our 26 production guidance given much stronger than anticipated 26 well performance to date. We have identified an additional $200 million of D&C capital that could be deferred from the 26 EP capital program if commodity prices remain weak. At strict pricing, Termaline's revised EP plan anticipates 26 cash flow of $3.4 billion and free cash flow of a little over $0.7 billion. All else equal for every US $0.10 per MCF that ACO pricing improves, our 26 cash flow and free cash flow increase by approximately $45 million. Similarly, because we are exposed to these markets for every dollar per MCF US that both JKM and TTF improve, 26 cash flow improves by $50 million and 27 cash flow by $70 million. Some comments on reserves. Year-end 2025 PDP reserves were 1.47 billion BOEs, and that's up 27%. Total approved reserves of 3.26 billion BOEs were up 20% over 2024, and our 2P reserves eclipsed the 6 billion BOE mark, and they were up 15% year-over-year. So after 17 years of full operations, the company has 27.7 TCF of economic 2P natural gas reserves and just under 1.5 billion barrels of 2P oil condensate and NGL reserves. These are all pipeline connected to markets across North America. And at year end 25, we'd only booked a little over 15% of our current reserves. of 26,500 gross locations, and that's kind of been our historical booking average off the total inventory for the last few years. It's always around 15%. Reserve replacement was 356%, which is big for a large company, of 25 annual production of 233 million BUEs, with the 2P additions of 829 million BUEs. The company has elected to increase D&C cross costs across our entire booked inventory, including the previously booked inventory. And that's to reflect our steady migration to longer horizontals. They're 75% longer well since 2018. and an increasing percentage of plug-and-purse style completions, mostly in the Northeast BC Montney. We also increased future facility capital in the year-end 25 report. So these one-time increases actually bumped up the 2P F&D for 25 alone by 321 per BOE. Looking at some marketing highlights, the company has an average of about 880 million cubic feet per day of NatGas hedged in 26, and that's at a weighted average fixed price of Canadian $4.54 per MCF. In the first quarter, we had over 370 million cubic feet per day of our physical gas exposed to the premium price eastern markets, which was good when they ran. So that's Don, Ventura, Chicago, Iroquois, Emerson, and Hay and R Southeast. And that provided a strong uplift to our Q1 cash flow. We have entered into a long-term natural gas storage agreement with all the gas at their Dimmesdale storage facility in Alberta. We did that in the second half of 2025. Subsequently, AltaGas has announced a positive final investment decision for the Phase 2 expansion of that facility. So, in 26, we'll have access to 6 BCF of storage capacity, and that starts in April of this year. And then next year, in mid-27, it increases to 10 BCF, and that's for a 10-year term. And we view the acquisition of an additional large storage position as a strategic opportunity to improve financial performance and enhance our operational flexibility in periods of natural gas volatility. And it's really just another aspect of our ongoing efforts to fully integrate our natural gas business. Updating the cost reduction and margin improvement activities. We did embark upon that initiative in mid-25, and the focus is on reducing all aspects of the cost equation. And we're excited by the rapid progress that we've made already. So Q4 op-ex was $4.66 a BUE. That was down 3% from the third quarter in 2025, and 9% from the first half of 2025 when costs were $5.14 a BUE. The Peace River High Complex Sale will reduce go-forward corporate OpEx by a further 7%, so our 26 OpEx guidance is $4.50 per BUE. With the success of the cost reduction initiatives to date, We are revising our aggregate operating and transport cost reduction target that was $1 per BOE by 2031 to $1.50 per BOE and approximately $0.70 per BOE have already been achieved since the first half of 2025. We've also entered into agreements to control our frac sand capacity in BC via a transload facility. It's expected to commence operations in Q2 of 26. In this vertical integration of our sand business, it's estimated to save a minimum of $40 million per year in capital costs. The ongoing Northeast BC infrastructure build-out will systematically reduce costs as well as various components are completed. First major component completed is the liquids hub and associated pipelines. With it, that's located in proximity to the Aiken Gas Processing Complex. By 2031, Thermaline expects up to $500 million per year of aggregate commodity price independent structural cost reductions, and that's compared to the first half 25 cost structure. And that will flow through to lower corporate break-evens and our free cash flow margin improvements. On the EP front, in 2025, we drilled 320 gross wells and we led the Canadian industry with a total of 1.7 million meters drilled during the year. In 2025, we delivered our best overall well performance in the past six years in the BC Montigny gas condensate complex. We're 22% higher in 2025 than the previous five-year average. And that's based on the IP and IT of 102 wells. And this outperformance has been across the full suite of the BC Montney assets from Aitken Birch Gundy in the north to Ground Birch Dole Manias in the south. And it speaks to the size and scale of this fully de-risked asset base. We continue to increase lateral length, 25 deep basin in Northeast BC program. averaging 8,400 completed lateral feet, and that's up 1,100 feet over 2024. D and C cost per foot in the deep basin in BC are actually now in decline, and the stats are quoted there. The 26 EP capital budget reduction that we have announced, the $175 million, will not impact the original startup of timing of the Aitken and the ground-bridge Manias gas plant projects in BC. Aiken is on schedule for a Q4 26 completion and Manias completion is expected in Q4 of 27. Our ongoing new zone, new pool exploration program has now resulted after approximately five years in 2.55 TCF equivalent of 2P reserve additions and approximately 1,350 Tier 1 and Tier 2 drilling locations. We've got several high-impact exploration and delineation wells planned in the 26th program. We figure this is by far the largest and most consistent exploration program in the basin. On EPI, or Environmental Performance Improvement, importantly, Tourmaline has achieved Grade A certification for methane performance across our entire Northeast BC asset base. That's under MIQ's Global Methane Certification Standard. We're 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. And the timing of this is significant given the ongoing negotiations on methane between the province of Alberta and the federal government. There are several other EP highlights, as there always are, detailed in the release. You can read those at your leisure. On the dividend, our board of directors has declared a quarterly base dividend of 50 cents per share payable on March 31, 26 to shareholders of record at the close of business on March 16, 26. And the weak Western Canadian sedimentary basin local gas pricing and unusually low pricing at the PG&E and Malin sales hubs this winter will limit free cash flow and constrain our ability to fund a special dividend in Q1. Sustained stronger pricing and our ongoing margin improvement activities are expected to lead to further base dividend increases and special dividends are anticipated to be used in those periods of particularly strong pricing to return the majority of incremental free cash flow to shareholders. So that's it for the formal remarks and we're here to answer questions.