Tourmaline Oil Corp. (TOU) Earnings Call Transcript

Good morning, ladies and gentlemen, and welcome to the Tourmaline Q2 2025 Results Conference Call. [Operator Instructions] Also note that this call is being recorded on Thursday, July 31, 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 Tourmaline's financial and operating results as at June 30, 2025, and for the 3 and 6 months ended June 30, 2025 and 2024. My name is Scott Kirker, and I'm the Chief Legal Officer here at Tourmaline. 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 Tourmaline annual information form and our MD&A available on SEDAR 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 Heard 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. 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 7 and up 10% from the second quarter of 2024. Second quarter cash flow was $823 million or $2.16 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. I'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 billion 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 $0.35 per share on August 20 to shareholders of record on August 8. 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 billion 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 0.5x 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 BOEs 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 690,000 to 710,000 BOEs per day is currently anticipated. In the 5-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 CAD 3.34 per Mcf, and that's 94% above the AECO 5A benchmark price of CAD 1.72 per Mcf. 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 CAD 4.48 per Mcf. 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 MMBtu per day of natural gas in the U.S. Gulf Coast for an 8-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 multiyear Northeast BC Montney 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 Montney gas condensate complex for over 5 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 6-year period. And this project will develop Tourmaline's most profitable inventory. It's the lowest capital cost, lowest operating cost, 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 2 new deep cut gas plants, one in the North Montney, one in the South Montney, expansion of 4 existing gas processing complexes, 3 new hydrocarbon liquid hubs, 5 water recycling facilities, electrification of 4 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. 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 we'll 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 AkenC38C plant expansion. And we feel that's a good time to add new basin volumes given that Phase 1 of LNG Canada should be at full volume certainly by that point. The next production addition is Phase 1 of the Groundbirch 15 to 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. Tourmaline 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 2.5x at flat pricing to $2.5 billion 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 multiyear 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 BOEs 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 BOEs per day. Associated free cash flow will grow to the $2.5 billion 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 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. We will be a materially 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 of 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.

[Operator Instructions] And your first question will be from Kalei Akamine at Bank of America.

Look, thank you for the updated plan. I think this has been well telegraphed by you and your team versus our estimates, we found this very much in line. I'm hoping that I can get you to address maybe a couple of things here. First, when I'm looking at Slide #8, some of the midstream projects associated with this build-out maybe could have some better definition. So wondering if there are moving parts and what those moving parts could mean for the plan. And then our broad read of this is that this is probably the most conservative version. Where do you think that you could improve on this plan? Is it something like liquids yield? Is it capital? Or is it synergies from prior deals?

Well, we'll work backwards with that. Where we can improve is significantly on the realized liquids margins. We've included the base minimum of $1 per barrel improvement, and we fully expect to do significantly better than that. I don't know what you were looking for as far as further detail on all of the existing plant expansions or new builds. We've been kind of carefully planning this out for multiple years. So we kind of know exactly what we're going to build. So we can certainly take that offline and provide more detail for you. But maybe you can let us know what you're thinking there.

I guess, broadly, I'm looking at Slide #8 and specifically at Groundbirch and Conroy, where the build-out is up to a certain number. It seems like that up to number is still kind of influx. So maybe talk about what [ motiv ] to that number in between.

Sure. Well, there's going to be 2 sort of plant projects in Groundbirch. There's the Phase 1 deep cut, which will be 300 million a day, and that will handle the liquid-rich gas. And then on the ex Strathcona assets, we will expand that 60 million a day gas plant that they had to 150 million a day, and that will handle the dry gas component of the inventory that we're going to develop there. And then we have an opportunity in Phase 2 to take the Groundbirch to deep cut plant to higher levels.

That's helpful. My second question is, is it really about hedging. When you think about the big capital commitment over this period, does that motivate you to hedge maybe a tad more aggressively? Or given what your base case is for rates over the next several years, are you more motivated to perhaps hedge less and lean into the macro?

Yes. Well, we have those discussions daily, as you can imagine. Right now, we're probably just going to stick with the existing plan. And in any current year, we end up 30% to 35% hedged by the time that year is happening. If you look out, '26 isn't at that level yet, and that's mostly because we haven't seen the prices that we like. But if you look historically, that's typically what we've done. And we typically -- just because we've had weaker prices in the Western Canadian Sedimentary Basin, that hedging tends to be summer focused and focus more on those hubs rather than our export hubs in the U.S. So that you kind of nailed it, is the AECO outlook going to be significantly better so that maybe you don't hedge as much in the summer of '26 and '27. And I'd say the jury is out on making that decision at this point.

Next question will be from Sam Burwell at Jefferies.

I just wanted to get a sense of whether 2026 is the heaviest year of infrastructure CapEx spend. Is it materially more than '25 and '27? Just trying to get a better sense of the infrastructure CapEx trajectory?

Yes, it's Jamie speaking. It's generally level loaded across the plan. Frankly, we're kind of building to sometimes and a bit gas plant in any given year. So this next several quarters is focused around the AkenC38C build-out. In '26, there is long lead spend now incorporated for Groundbirch, and that build-out has been completed in '27. And then we're getting into some of the Phase 2 elements of both the North and South Montney. Importantly, though, this infrastructure build-out does tail off in the 2030, 2031 time frame. And you can see that free cash flow expand as that capital drops.

Okay. Got it. Then a follow-up on the deferrals obviously makes sense given the AECO pricing you're seeing now, but the CapEx guidance was unchanged. So I'm just wondering if there is a downside bias to 2025 CapEx or perhaps there are volumes that show up in, say, 2026 where the capital is deployed in 2025. So just trying to reconcile the production guidance with the CapEx guidance for '25.

Yes. I think that's a distinct possibility. We'll probably migrate towards the lower end of capital. And we've -- as we announced in the press release, we are continuing to defer some capital activity out of Q3 to later in the year. We're still targeting if pricing improves in Q4, and we might get into a discussion on this call on where AECO is going to go here over the next couple of months, we can very quickly pivot and execute a significant piece of the program in Q4 and hit or exceed that exit target of 680,000 to 690,000 BOEs a day. So maybe a little more U-shaped production profile than we've seen in previous years for us and that's strictly related to continuing weaker-than-expected summer gas prices. And those are -- a large part of that is being caused by export restrictions out of our basin due to maintenance. So there was maintenance at the East Gate through July, and that's continuing. And there's significant maintenance on the West Gate. And in aggregate, it's backing up close to 1 Bcf a day into the basin kind of at exactly the wrong time. And it's significantly more than the export backup than we were observing due to maintenance last summer. So it's a bit of an aberration. And we think by September -- well, we know by September, that all goes away and perhaps you can start seeing the -- more clearly the impact of pulling increasing volumes west on CGL to LNG Canada. Anything you want to add, Jamie?

I would say like the flip side of that is it coils the spring on how tight next year can get, and you're starting to see that being reflected in some of the basis markets. We've seen Chicago tighten up. We've seen even CAL '26 AECO Hub tighten up a bit here just in the last 10 sessions. And so the lack of ability to export this summer helps drain the storage capacity in the markets we would otherwise be exporting to, namely the Pac Northwest, California market and the Chicago market. And those markets have had generally a pretty hot summer, especially in the East, and that makes the '26 setup that much more interesting. I think the other thing we'll be watching carefully, of course, is the LNG Canada ramp-up, which frankly, so far has been very strong, seeing pulls up to 400 million a day implied by the cargoes and the visible scrapes we see well over 100 million a day now at the end of July, and we understand that ramp to continue to go well through the back half of this year.

Next question will be from Josh Silverstein at UBS.

Just for the long-term plan and the build-out here, can you just talk about how much flexibility or optionality you have in the development plan? Can you adjust the project slate or timing depending on commodity prices? If you can offer a little bit more color there, that would be great.

We have a significant amount of flexibility. We're not projecting first production of any material nature really until Q4 of 2026 with the Aken start-up. And I don't think there's an opportunity to move that to midyear, but we can certainly have flexibility on when Groundbirch starts and when all the Phase 2 components actually start. I mean we've sort of got in the habit the last 2.5 years of just deferring everything because prices haven't cooperated. So we're kind of looking forward to the other side of this. Maybe prices are better than it is being forecast for '26 and '27, and we can accelerate several of the items in there.

Got it. And then I also wanted to ask on the shareholder return profile. Given all the CapEx that the free cash flow really is kind of back-end weighted here, are you limiting the potential growth in shareholder returns through this period? And then I see the buyback in that kind of chart in the back have kind of been pushed back out 5 years from now as well versus potentially earlier, you were thinking about maybe '26 or '27?

Yes. I mean we've got a big project to execute here between '25 and '31. So the focus really is on per share growth and dividend yield. If we were just talking about if prices are better than expected, then that growth of free cash flow to over $2 billion per annum comes sooner, and that can open up other options for shareholder returns. Just to put some numbers on that, Josh. If you were to move AECO around like plus $1, that's over $500 million of incremental free cash flow for Tourmaline. And so I think it really does -- we are definitely well open to an improving gas price market in '26, and that can influence how we return cash to shareholders.