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.

Thank you. Ladies and gentlemen, if you do have any questions at this time, please press star followed by one on your touchtone phone. You will then hear a prompt that your hand has been raised. And should you wish to decline from the polling process, please press star followed by two. And if you're using a speakerphone, we ask that you please Lift your handset before pressing any keys. Please go ahead and press star one now if you do have any questions. And your first question will be from Kelly Ackermine at Bank of America. Please go ahead.

Hey, good morning, guys, Mike and team. 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 number eight, 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 liquid yield? Is it capital? Or is it synergies from prior deals?

Well, we'll work backwards with that, yes, and good morning. 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 that, 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 probably I'm looking at slide number eight and specifically at ground birch and convoy where the build-out is up to a certain number. It seems like that up-to number is still kind of in flux. So maybe talk about what would motivate you to go up to that number or somewhere in between.

Sure. Well, there's going to be two sort of plant projects in ground birch. There's the phase one deep cut, which will be $300 million a day, and that will handle the liquid-rich gas. And then on the extra Kona 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 two to take the groundwork to deep cut plant to higher levels.

Thank you, Mike. That's helpful. My second question is, is really about heading. 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 ACO over the next several years, are you more motivated to perhaps hedge less and lean into the macro?

Yeah, well, we have those discussions daily, as you can imagine. You know, 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, you know, that you kind of nailed it. Is the ACO 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's out on making that decision at this point.

Got it. Thanks for the color, Mike. Thank you.

Next question will be from Sam Burwell at Jefferies. Please go ahead.

Hey, good morning, guys. 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.

Yeah, it's Jamie speaking. It's generally level loaded across the plan. Frankly, we're kind of building one to sometimes one and a bit gas plants in any given year. So this next several quarters is focused around the Aitkin C-38 build-out. In 26, there is long-lead spend now incorporated for ground birch, and that build-out is then completed in 27. And then we're getting into some of the phase two elements of both the North and South Montney. Importantly, though, this infrastructure build-out does pay a lot in the 2030-2031 timeframe. And you can see that free cash flow expand as that capital drops.

Okay, got it. Then follow up on the deferrals obviously makes sense given the ACO 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. Just trying to reconcile the production guidance with the CapEx guidance for 25.

Yeah, I think that's a distinct possibility. We'll probably migrate towards the lower end of capital. And as we announced in the press release, we are continuing to defer some capital activity out of Q3 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 ACO 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 BUEs 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, you know, 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. In an aggregate, it's backing up close to a 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 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. You've seen Chicago tighten up. We've seen even Cal 26, Eco 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 set up, you know, 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. You know, 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 to the back half of this year.

Okay, very, very helpful.

Much appreciated, guys.

Yeah, thank you.

Next question will be from Josh Silverstein at UBS. Please go ahead.

Hey, thanks. Good morning, guys. 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 us a little bit more color there, that'd be great.

We have a significant amount of flexibility. Uh, we're not projecting first production of any material nature really until, uh, Q4 of 2026 with the Aiken startup. Uh, and, uh, I don't think there's, you know, an opportunity to move that to mid-year, uh, but we can certainly, uh, have flexibility on, uh, when ground birch starts and when all the phase two components actually start. I mean, we've sort of got in the habit the last two and a half 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's 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 and 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 has kind of been pushed back out, you know, five years from now as well versus potentially earlier you were thinking about maybe 26 or 27. Thanks.

Yeah, 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, you know, 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.

Yeah, just to put some numbers on that, Josh, if you were to move ACO around like plus a dollar, 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.

Thanks, guys.

Thank you. Next question will be from Jamie Kubik at CIBC.

Please go ahead.

Yeah, good morning and thanks for taking my question. A specific one actually, but with respect to slide six and the updated EP plan, there's a great amount of detail on the infrastructure inclusions that you have in this plan. Can you talk a little bit about perhaps the percentage of new capital in the EP plan that is infrastructure weighted versus maybe new drilling capital compared to what was previously included?

Thanks. Yeah, so we did include facility capital for both ground birch and the North Mountain that wasn't included before. But also, we also included the drilling and completion capital associated with that extra 100,000 BUEs a day. And so in general, for the next several years, we're going to be allocating three to sometimes $350 million of infrastructure capital per year. And then the DNC's CapEx would be basically pushing at that $2.5 to $2.6 billion level. Once North Montney Phase 2 is completed, that infrastructure capital will thin. It's going to thin to roughly $100 million a year, sometimes less. And then also, as declines are coming down through the plan, which is important, we'd be roughly at 32% to 33% decline rate today because of the way the BC Montney production contributes to the business and the advantageous nature of how those type curves shape Decline still we see coming down through the end of the plan into the high to mid-20s. That allows that DC capital also to decelerate.

And so that's how you get to the $2.5 billion at the end.

Okay, thank you. Maybe I'll ask another one here. Just with respect to the liquids mix and the production profile, I guess how is that trending this year versus – your expectations and how do you think that might change in the back half of 25 or into 2026?

Yeah, I think ultimately the mix won't change. There'll be short-term aberrations in any given year, but ultimately it's pretty much that 75 gas, 25% total liquid, and that's where it is at the end of the plant. We're down a little on liquids this year. We had an extended turnaround in the Peace River High Complex, which reduced liquids for a longer period than we had forecast for Q2. And then just the sequence of the pad drilling in the BC Montney, several of the early pads We're in gassier areas. And some of the deferrals were when we were saving capital in Q2 were a couple of the liquid-rich pads. We subsequently completed those. And so you'll see total liquids production trend up here through the balance of the year.

Great, thanks. I'll sneak in one more here just with respect to shut-ins. Termaline did mention in its disclosures that you did have some shut-ins in Q2 related to natural gas. I guess, is that something that you're thinking about extending through Q3 by much, just given where Station 2 and ACO pricing have gotten to, and how should we think about that part going forward?

We're certainly looking. We actually have a little bit of gas shut in today. You know, we'll see where prices go through the balance of August. But we've certainly left that as an option for us in August. Anyway, we expect September pricing to be better. And the shut ins have been strictly on the B.C. money, generally the north money. It's gas that goes through third parties. with higher OPEX, and, of course, part of the infrastructure build-out is that gas comes into our own facilities in the future with much lower OPEX.

Okay, thanks. I'll turn it back.

Thank you. Next question will be from Aaron Bukowski at TD Cowan.

Please go ahead.

Thanks. Good morning. A couple of small questions from me. The first is on margin expansion. You've obviously discussed margin expansion as you grow up in Northeast BC. Some of that comes from higher revenue. Some of it comes from lower costs. Of the dollar per BOE cost savings that you talked about, what would roughly the split be between OPEX savings and transportation cost savings, if you have that available?

Yeah, it's about 50-50, Aaron. And we'll see if we can do better on the OPEX, but that's what we're modeling in right now. So 50 cents on each.

Thanks. And my second question is on the transport to the Gulf. I guess, to what extent do you see Tourmaline being able to get more physical transport capacity down to the Gulf in the coming years?

Well, it's something we work really hard at. And I would expect sometime in the next two or three years, we'll find another pathway down there on existing pipes with lower tolls. There might be some further brownfield work that seems to be on the table again south of the border, which might help that exercise. But our marketers spend a lot of time trying to cobble together transportation routes from the Gulf all the way back into the basin.

Perfect. Thanks, Mike.

Thank you.

Next question will be from Philip Lamoureux at Lamoureux Vineyard. Please go ahead.

Hi, Mike. In years past, when we had board meetings down in Tucson with Ron Wiggum and Andy and Lee and John Ellick, I remember we were running debt at about two and a half times cash flow thereabouts, and talked about whether we should put a cap or suggest a cap of don't go over three times cash flow. And now you're running 0.5, paying a huge dividend, a very attractive dividend if people have their eyes open. And it's just amazing what you've accomplished. I just want to do a thank you for what you've done.

Well, thanks, Bill. Yeah.

Thank you. Once again, ladies and gentlemen, if you do have any questions, please press star followed by one on your touchtone phone. And your next question will be from Faye Lee at Adlam Brown. Please go ahead.

Hi, Mike. It's Faye here. I'm just going to slide five, your five-year plan. In 2031, you have like $2.6 billion in your capital program. I'm assuming if this was a six-year plan that there would be some production growth in 2032. Does that confirm that? And if that's the case, I'm just wondering if you can give me some sense of what sustaining capital call it would be to keep production flat at 850. Just wondering what that number would be if it's not 2.6 billion.

Yeah, you bet, Fai. Yeah, we're modeling $2.5 billion to maintain that 850,000 BOEs per day. And the answer to the first part of your question is, yes, there probably will be some modest growth going forward, 20, 32 and beyond. In that, the last slide in the deck, we do depict that to some extent, but we do show the production growth rate dropping from that 5% to 6%. into the 1% to 2% per annum range. And so, I mean, I think that's the type of production growth that you can think about for, you know, the years past the existing six-and-a-half-year plan.

Okay, great. Thanks.

That's very helpful. Thanks, bye.

Thank you.

And at this time, Mr. Kirker, we have no further questions registered. Please proceed.

Thank you, Sylvie. Thanks, everyone, for attending the conference call. We'll see you again next quarter.

Thank you, sir. Ladies and gentlemen, this does indeed conclude your conference call for today. Once again, thank you for attending. And at this time, we do ask that you please disconnect your line.