Tourmaline Oil Corp.

Good morning, ladies and gentlemen, and welcome to the Tourmaline Q2 2025 results conference call. At this time, note that all participant lines are in the listen-only mode. Following the presentation, we will conduct a question and answer session. And if at any time during this call you require immediate assistance, please press star zero for the operator. Also note that this call is being recorded on Thursday, July 31st, 2025. And I would like to turn the conference over to Scott Kirker. Please go ahead, sir.

Thank you, Sylvie, and welcome everyone to our discussion of Termaline's financial and operating results as at June 30, 2025, and for the three and six months ended June 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 Forum 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 Ford, Tourmaline's Vice President of Capital Markets. We'll start with Mike speaking to some of the highlights of the last quarter or year so far, and after his remarks, we'll be open for some questions. Mike, please go ahead.

Thanks, Scott, and good morning, everyone, and we're happy to review our Q2 results and then... answer some questions. Highlights, second quarter average production was 620,757 BOEs per day, and that was at the midpoint of the guidance range that we provided on May 7th, and up 10% from the second quarter of 2024. Second quarter cash flow was 823 million or 216 per diluted share. on total EP expenditures of $490 million and that generated free cash flow of $317 million for the quarter or $0.83 per diluted share. We've entered into a new long-term LNG feed gas supply agreement with Uniper. We'll talk more on that in a moment. We've released an updated EP plan that outlines growth from our current production levels of approximately 650,000 BOEs per day to 850,000 BOEs per day in the next decade, early in the next decade. And this build-out is fully funded by cash flow. And it will result in $2.5 to $3 billion of annual free cash flow at flat pricing on a maintenance budget by the end of the EP plan. Given the continued strong free cash flow generation, in Q2, the company has elected to declare and pay a special dividend of 35 cents per share on August 20th to shareholders of record on August 8th. Briefly on financial results, second quarter 25 earnings were very strong at $515 million or $1.35 per diluted share. The full year 25 EP capital budget remains unchanged and the range remains unchanged at $2.6 to $2.85 billion. We anticipate commodity prices to improve over the current strip in the second half of 2025 with the ramp up of the LNG Canada facility on the west coast resulting in hopefully higher free cash flow in the second half relative to first half. We continue to maintain a very strong balance sheet. Net debt at June 30, 2025 was approximately 0.5 times net debt to 25 forecast cash flow. On the production front, as mentioned, second quarter average production was a little over 620,000 BOEs per day. And that was achieved despite reductions related to wildfires in the Peace River High Complex. low commodity price-related periodic shut-ins in northeast BC, and multiple frac activity deferrals into the second half of this year, given low pricing. Full year 25 average production of 635,000 to 650,000 DOEs per day is now expected, given the EP activity deferrals, first from Q2 to Q3, and now from Q3 into Q4, as we... target higher pricing to bring new production on. The 25 exit average production of 680,000 to 690,000 BOEs per day and a preliminary 26 average production range of 690 to 710,000 BOEs per day is currently anticipated. In the five-year plan, we use the very bottom of that range to be conservative. Looking at the 25 capital program, Q2 EP capital spending was $70 million less than forecast, primarily due to those aforementioned activity deferrals. And we'll continue to monitor local natural gas prices and defer capital from Q3 into Q4 of this year or into Q1 of 26 as required, as we always optimize free cash flow. Briefly on marketing, our average realized natural gas price in the second quarter of this year was $3.34 per MCF Canadian, and that's 94% above the ACO 5A benchmark price of $1.72 per MCF Canadian. We continue to benefit from our diversified marketing portfolio and our strategic hedging program. We have an average of 1.1 BCF per day hedged for the balance of this year at a weighted average fixed price of $4.48 per MCF Canadian. We're pleased to disclose our third Gulf Coast LNG agreement. We've entered into a long-term LNG feed gas supply agreement with Uniper. Tourmaline will supply 80,000 mm BTU per day of natural gas in the U.S. Gulf Coast for an eight-year term, and that begins November 2028. We have secured long-term firm transportation to the U.S. Gulf Coast with TC Energy, and that allows Tourmaline's natural gas from both the Alberta Deep Basin and or the BC Montney complexes to directly access European natural gas markets. The firm transportation begins in November 2025, and that gives us the flexibility to sell locally in the Gulf or enter into short-term LNG feed gas supply deals prior to the start of the Uniper agreement. We are excited to provide more details regarding our multi-year Northeast BC Montigny development project, certainly one of the largest EP projects in the Western Canadian sedimentary basin. We have been systematically consolidating and delineating the Northeast BC Montigny gas condensate complex For over five years, and we're now entering the next phase, we're in the significant financial benefits of all those activities, which began during COVID, will be fully realized. We expect to add 1.1 BCF per day of new gas production and over 50,000 barrels per day of condensate and NGLs over the next six-year period. And this project will develop Tourmaline's most profitable inventory. It's the lowest capital cost. lowest operating costs, most liquid-rich, highest margin inventory we have, and it will improve all of the company's operating metrics as production from this new development project becomes a larger proportion of the corporate production base. The build-out consists of two new deep-cut gas plants, one in the North Montigny, one in the South Montigny, expansion of four existing gas processing complexes, three new hydrocarbon liquid hubs, five water recycling facilities, electrification of four of the gas processing plants, as well as several pipeline corridors connecting the company's large resource base to its existing and the new gas processing complexes. You know, recall we've been building, gathering, and processing infrastructure across Northeast BC and the Alberta Deep Basin since the company started, including over 10 new processing facilities. So we're good at this, and our cost management is very strong. This BC Montney development project has a strong focus on liquids growth and margin improvement, and the company already is the largest liquids producer in Northeast BC and will continue to grow those volumes. The infrastructure build out actually commenced in 2024 with several components already built or underway, and they're disclosed in the press release. The first significant production addition to come from all this is expected in Q4 of 2026 with the Aiken C38C plant expansion. And we feel that's a good time to add new basin volumes given that phase one of LNG Canada should be at full volume certainly by that point. The next production addition is phase one of the ground birch 15 and 25 deep cut gas plant, and that's planned for the second half of 2027. And importantly, both of those projects have all the necessary permits and long lead procurement is underway. Termaline expects production growth of 30% to 850,000 BOEs per day by 2031, cash flow growth of over 40%, and free cash flow improvement of over 2.5 times at flat pricing to 2.5 to 3 billion of free cash flow per annum once the overall project is completed and the EP program starts to trend towards maintenance capital levels. We've updated our multi-year EP growth plan as well, and that, as you can see, through to 2031, grows current average production levels from 650,000 to 850,000 BUEs per day. Once the Northeast BC infrastructure build-out is completed early next decade, the production growth rate is expected to drop, and the company intends to migrate towards a maintenance capital level which we currently estimate at about $2.5 billion per annum to maintain 850,000 BUEs per day. Associated free cash flow will grow to the $2.5 to $3 billion per annum mark at the flat price deck, and it does underscore the significant overall improvements that this BC Montney development project will impart. And at that point, we'll have a company that can continue to produce at these levels, and more importantly, generate annual free cash flow of this magnitude for literally decades, given we control the largest future drilling inventory in North America. And we've always taken a long-term view as we've built this company. That includes building and owning your own infrastructure as that improves realized margins and partially insulates us against ongoing price volatility. So really, this is just another planned step in the evolution of the company. will be a material larger, more profitable company right about the time that we expect the continent to be getting short on resource. And importantly, we'll continue to prioritize free cash flow on an annual basis as the new EP plan is executed, and we'll adjust the pace of capital spending accordingly. We can slow down if prices aren't cooperating, or we can accelerate if prices are ahead. where we're expecting. That doesn't seem to happen very often, but we do maintain our strong natural gas outlook for the second half of this decade. Just briefly on E&P, our 25 well results in both the northeast BC Montney and the Alberta Deep Basin continue to outperform prior years with above forecast deliverability from multiple assets spread across both gas complexes and this has allowed us to reduce capital spending and maintain in part production targets. With lower local gas prices thus far in Q3 of 25, we've already deferred some BC frac activities into Q4 and we have released one of the deep basin drilling rigs for the balance of at least this year. And of note, multiple new pool successes in several formations in the South Deep Basin via the second half 24, first half 25 EP program are evolving into a significant new growth project for the company. We plan several delineation wells over the next 12 months to further refine this multi-objective development. And it's certainly not included in the current EP plan. And I think that's it for the prepared remarks. And we're more than happy to answer any questions you may have.