Tourmaline Oil Corp.

Good morning, ladies and gentlemen, and welcome to the Tourmaline Q3 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 Thursday, November 6, 2025. 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 and operating results as at September 30, 2025 and for the three and nine months ended September 30, 2025 and 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'll start with Mike speaking to some of the highlights of the last quarter and our year so far. After his remarks, we'll be open for questions.

Go ahead, Mike. Thanks, Scott, and thanks everybody for dialing in. We're pleased to go through Q3 and then answer questions that you may have. A few highlights. Q3 25 average production of 634,750 BOEs per day was at the high end of our anticipated guidance range of 625,000 to 635,000 BOEs per day, despite storage injections and shut-ins during the quarter. We're pleased to announce that we have entered into a long-term natural gas storage agreement with Alta Gas at their Dimmesdale storage facility and we view the addition of another large storage position as a strategic opportunity to enhance financial performance and strengthen operational flexibility in volatile natural gas price environments like we just went through this past summer. We've also entered into two short-term and one long-term LNG gas supply contracts, which complement our existing extensive portfolio. Looking specifically at production, fourth quarter production is expected to average between 655,000 and 665,000 BOEs per day, with a 25 exit volume of 680,000 to 700,000 BOEs per day. Our third quarter liquids production of a little over 147,000 barrels per day was up 4% quarter over quarter and our 26 average production guidance of 690,000 to 710,000 BUEs per day remains unchanged, as does the current multi-year EP plan, which is forecast to yield 30% high margin production growth to 850,000 BUEs per day by 2031. Third quarter 2025 cash flow was $720 million and third quarter 25 earnings were $190 million. Our third quarter realizations were impacted by unusually large natural gas export maintenance outages. both the East Gate and the West Gate. As a result of these outages, ACO and Station 2 pricing averaged $0.64 and $0.48 per MCF, respectively, during the quarter. And while we curtailed gas supply during the weakest local price days, the sustained low local prices were the primary reason for lower than our expected third quarter cash flow. The curtailments on export pipelines reduced our volumes accessing downstream markets as well, and that includes our premium markets, you know, such as the Gulf Coast and the western U.S., by approximately 155 million cubic feet per day. So instead, these volumes were sold into ACO and Station 2 spot prices, and that meaningfully impacted our September natural gas revenue. On a positive note, the force majeure on the Great Lakes pipeline ended in early October, and Eastgate exports are at normal levels, and the Westgate maintenance ends during this month of November. Looking ahead, with the benefit of LMG Canada's demand creating additional capacity on local egress pipelines, second and third quarter 2026 ACO pricing is currently averaging $3 in MCF compared to $1.18 for the same price. uh period in 2025. and we think additional upside should be created uh if equal basis tightens further and that is what we anticipate happening uh third quarter 2025 um ep expenditures were 825 million the full year ep capital budget remains unchanged at 2.6 to 2.85 billion We closed a $71.7 million transaction with Topaz Energy Corp, whereby Topaz purchased a gore on the recently acquired Saguaro and Strathcona ground birch northeast BC Montney development lands. And in addition, on October 28th, we completed a secondary offering of Topaz common shares for gross proceeds of approximately $230 million. Moving to marketing, lots of activity as we continue to vertically integrate our gas business and maximize future realized prices. We have an average of 1.2 BCF per day of nat gas hedged for the remainder of 2025 at a weighted average fixed price of $4.33 per MCF Canadian. This includes 57 million cubic feet per day hedged at a weighted average price of $20.13 per MCF Canadian in international markets and 109 million cubic feet per day at a weighted average price of $6.86 per MCF in the western U.S. markets. Q3 25 ACO and station 2 nat gas prices were the weakest in over 30 years and as mentioned that negatively impacted cash flow. However, prices are improving thus far in the fourth quarter and the 2026 strip price outlook continues to migrate upwards. We are pleased to enter into that Dimmesdale storage deal. We'll have access to 6 BCF of storage capacity starting in April for a 10-year term with the ability to increase to 10 BCF in the event that AltaGas takes FID on Phase 2. And we view the addition of another large storage position as a really strategic opportunity to enhance financial performance. and provide operational flexibility with these very volatile prices. On the LNG front, we've entered into several new supply contracts as detailed in the release, and I won't go through them, but they're there for you to read. In aggregate, we'll have an average of 213,000 MMBTUs exposed to international pricing in 26th. That'll grow to $250,000 by exit 27 and $330,000 by exit 28. So a very attractive progression. Turning to the capital budget and the EP plan, as mentioned, spending in the quarter was $825.5 million. As we executed capital projects deferred from Q2, along with the original Q3 budgeted items, really to prepare for incremental production volumes in advance. of higher anticipated winter gas prices which are materializing our full year ep spending remains unchanged for 2025 and 2026. the 26 ep capital program is 2.9 billion and that is unchanged from the release on july 29th of 2025. Utilizing current strip pricing, our EP plan anticipates 26 cash flow of approximately $4 billion and free cash flow of approximately $0.9 billion. The strip pricing includes a 26-acre basis of $1.66 per MCF, and we anticipate that basis tightening towards $1 US as the basin dynamics adjust for LNG Canada's demand. And for every 10 cents per MCF U.S. that ACO basis tightens, our 26 cash flow and free cash flow would increase by approximately $50 million. And should natural gas prices weaken in 2026, we certainly have the option to reduce capital spending as appropriate to optimize free cash flow and our planned shareholder returns. Approximately $250 million of currently planned capital spending could be deferred in such a low-price scenario, and that would really have only a minor impact on 2026 production guidance. On our cost reduction focus and margin improvement initiatives, the ongoing Northeast BC development project and infrastructure build out will provide both significant growth and margin expansion by improving all of our operating metrics. Q3 2025 corporate OpEx of $480 per BOE was down 34 cents of BOE from the first half of this year, so approximately a 7% improvement. And early components of the Northeast BC build-out have been completed, and that has initiated the cost reduction progression and is contributing to the reduction in OpEx in the third quarter, and this process will really accelerate going forward. The Northeast BC development project is anticipated to systematically reduce combined corporate OPEX and transportation costs by at least a dollar per BOE as it is put in place over the next six years. And we see the opportunity for meaningful progress on this target in 2026 and all subsequent years. And there is potential to increase the overall total long-term target moving forward. We have a comprehensive corporate focus on reducing all aspects of the cost equation, as well as our per well EP capital costs in 2026. So we're targeting a 5% OpEx reduction in the deep basin next year and targeting a further 5% reduction in DMC costs over currently budgeted levels. And these reductions are not captured in the multi-year EP plan yet, because we'll make sure we realize them first. and we've always had a very strong cost structure and we plan to make it even stronger going forward we have elected to pursue the potential sale of our peace river high light oil and gas complex so the charlie lake play which we actually pioneered back in duvernay oil corp days if completed this sale would further lower corporate opex and provide proceeds that could be reinvested into our higher margin BC growth assets or emerging EP opportunities that we've assembled in the deep basin. So this initiative is just a subset of the significant internal value creation opportunities that exist within the company's overall portfolio. Specifically on E&P in the quarter, we drilled 68 wells. completed 88 wells and entered the fourth quarter with 38 ducts, the majority of which are expected to be completed in the near term should gas prices continue to improve. We were very pleased our 25 Northeast BC Montney IP90 well performance to date is up 26% over the five-year average performance as we drill steadily longer horizontal wells in that complex and the percentage of plug-and-purse style stimulations has been increased. And despite these more expensive completions, our 2025 Montney D&C costs are trending down on a per lateral foot basis. Our new pool, new zone exploration success continues across all complexes, and we have 12 to 15 new pool or follow-up delineation wells currently in the four Q4 25 and 2026 drilling program. So lots of exciting opportunities on that front. On the dividend, our board has declared a special dividend of 25 cents per share that will be payable on November 25th to shareholders of record on November 14th, 2025. And the company intends to declare the quarterly base dividend of 50 cents per share in December. We commenced paying special dividends in September of 2021, and that special dividend has varied between $0.35 per share and $2.25 per share until this quarter where it's $0.25. And while the 26 free cash flow outlook continues to improve, we will continue to find the balance between the planned EP growth program and the size and cadence of the special dividend. And I think that's enough for formal remarks, and there's four of us here ready to answer questions you may have.