Tourmaline Oil Corp

TSX:TOU

Good morning, ladies and gentlemen, and welcome to the Tourmaline Q1 2025 Results Conference Call. [Operator Instructions] This call is being recorded on Thursday, May 8, 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 Tourmaline's financial and operating results as of March 31, 2025, and for the 3 months ended March 31, 2025 and 2024. My name is Scott Kirker. I'm the Chief Legal Officer here at Tourmaline Oil.

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. After his remarks, we will be open for questions.

Go ahead, Mike.

Thanks, Scott, and good morning, everybody. Thanks for dialing in and being online. So we're pleased to review our first quarter '25 results, update EP activities and update the outlook.

A few of the highlights. First quarter '25 average production was 638,000 BOEs a day, up 8% over first quarter of '24 and slightly ahead of our first quarter '25 expected production range. First quarter '25 cash flow was $963 million on total CapEx of $825 million. EP spending was about $800 million, and that generated free cash flow of $150 million for the quarter.

As you've seen, we continue to consolidate the Northeast BC Montney, one of the most profitable gas plays in North America. We're doing that in concert with our Northeast BC infrastructure build-out, and we're doing it ahead of the expected improving natural gas markets, which, to some extent, has already started to happen.

Board of Directors has declared a special dividend of $0.35 per share payable on May 26, 2025. And the company intends to declare a quarterly dividend of $0.50 per share payable on June 30, 2025.

A little on production. March 2025 average production was 645,000 BOEs a day, so higher than the quarterly average. The full year forecast production range remains the same, however, at between 635,000 and 665,000 BOEs per day. And production actually averaged 660,000, so the high end of the range for the first half of April as we finished off our completion activity from the winter and then the volume came down for the second half of the month given weaker prices. We expect second quarter '25 average production in the 615,000 to 625,000 BOE per day range, as we've moved a significant amount of maintenance into Q2, given weaker prices currently and particularly at Station 2.

On financial results. Our first quarter earnings were $213 million or $0.56 per fully diluted share. As mentioned, first quarter EP CapEx was $800 million, so a little less than originally forecast. We expect EP capital spending during Q2 of $560 million as activities are always a little lighter during spring breakup. And that should yield an estimated first half '25 free cash flow in the $430 million range. We do expect commodity prices to improve in the second half of this year with the start-up of the LNG Canada facility on the West Coast. And that should result in higher free cash flow in the second half of '25 relative to the first half.

On the '25 capital program, the full year '25 program remains unchanged at between $2.6 billion and $2.85 billion. Given the weak Station 2 gas prices, we will defer some of the planned Q2 frac activity into the third quarter of this year, and we'll continue to match planned production growth to the anticipated increasing natural gas price curve in the second half.

We will release the updated multiyear EP plan, including the full Northeast BC Montney gas and liquids infrastructure build-out and incorporation of the recent acquisitions. We'll do that in the second half of this year. Inclusive of projects not yet incorporated in that plan and the recent acquisitions, we're looking at very strong production volumes heading into the next decade as high as 850,000 BOEs per day. But you'll see that full plan in the second half of this year.

Just looking at the 2 acquisitions that were announced yesterday. In the North Montney, we've entered into an agreement to acquire the balance of the jointly-owned Laprise-Conroy assets through the acquisition of Saguaro Resources. And in the South Montney, we've entered into an agreement to acquire assets in the Greater Septimus area from a third party. Both transactions are expected to close in June. Our forward guidance and EP plan will reflect these acquisitions in the next update.

In aggregate, the 2 transactions add approximately 20,000 BOEs per day of current production, an estimated 363 million BOEs of current 2P reserves and approximately 410 Tier 1 future net drilling locations. Production and reserves from these assets are expected to experience significant future growth as each asset is systematically developed as part of the Northeast BC Montney build-out. And real Tier 1 inventory is scarce in North America, and we've been systematically ensuring we have decades of Tier 1 inventory, Tier 1A, if you like, secured at Tourmaline.

The Laprise-Conroy asset is the key component of the North Montney Phase 2 project and the Greater Septimus asset is complementary and adjacent to our planned Groundbirch 400 million a day, 20,000 barrels per day 2-phase gas plant development. The South Montney transaction also included land and high-quality inventory in the North Deep Basin. We'll issue a total of approximately 13 million common shares as consideration for the 2 transactions, leaving the balance sheet in a very strong position for potential further acquisitions in our core areas going forward.

Briefly on marketing. Our average realized natural gas price in the first quarter was CAD 4.30 per Mcf, so meaningfully ahead of the AECO 5a benchmark price, which was CAD 2.19 per Mcf. So we continue to benefit from the expanding diversification portfolio and our strategic hedging program.

From Q2 to Q4 '25, Tourmaline will average 2.1 Bcf per day of natural gas sales that are not exposed to floating local market prices at AECO and Station 2. And we have an average of 1.16 Bcf per day hedged in '25 at a weighted average fixed price of CAD 4.95 per Mcf.

We continue to be highly encouraged by the growing demand-driven natural gas price outlook in all of North America, and that includes the Western Canadian gas trading hubs. The company, though, continues to remain disciplined so as to not oversupply these local hubs. And just remind that the natural gas growth that we achieved in '23 and '24 was almost entirely matched up with new export contracts out of the Western Canadian Sedimentary Basin. And for the approximately 200 million a day of gas growth that will occur during calendar '25, 95 million of that or about 50% will actually commence flowing to the Gulf Coast in November of this year.

On E&P, we had very strong EP performance across all of our operated complexes in the quarter, and we set production records in all 3 complexes. In BC, we had a series of pads that are well ahead of performance type curve and they're detailed in the verbiage in that bullet. The strong '24 well performance that we delivered in the Alberta Deep Basin in 2024 continued in the first quarter of '25 with record March average production of 330,000 BOEs per day from the total Deep Basin complex. Notable exploration successes were realized in the South Deep Basin in the Greater Willesden Green area, our first Belly River horizontal tested at 700 barrels per day of oil less than 1% water cut and about 1 million a day of natural gas. And several new wells and pads in the down-dip Glauc play where that inventory continues to expand. And you'll see that well performance unfold over the next few quarters.

And I think that's it for the formal remarks, so we can move into Q&A.

[Operator Instructions] Your first question is from Aaron Bilkoski from TD Cowen.

I guess the spirit of my question is related to capital allocation. Would you be able to talk about the benefits and drawbacks of spending capital on these and maybe future acquisitions relative to allocating that capital to organic growth?

Sure. Yes, thanks, Aaron. Well, we're actually doing both. So the Northeast BC Montney development is underway. We spent $200 million on facilities in '24. There's $300 million in that build-out allocated in 2025, which we're not going to cut. The first plant in that build-out comes on stream in the second half of 2026. That's in Aitken. So we're well into that plan, which ultimately involves 4 plants, a series of regional pipelines and a whole liquids infrastructure build-out associated with the gas build-out as well.

On acquisitions, they're vendor-driven. And so we're not out seeking anything, but we've been tracking, as you know, what fits and what doesn't for years. And over the past couple of years, a number of people have come to us, and it's right in the middle of where we're going to develop, and we know we can grow the volumes, and we know we can improve the efficiencies and drop the costs on those assets. And so we think it's quite prudent of us to consolidate ahead of a, our build-out; and b, much improved pricing, which I think we're all expecting to happen here over the next few years in Western Canada. Does that help?

Yes, that's perfect. Can I ask you a quick follow-up question?

Sure.

This is something that maybe I should already know, but can you remind me what the total incremental production from Groundbirch expansion would be in the North Montney Phase 2 expansion would be?

Sure. In Groundbirch, the acquisition we did actually changes the configuration of the plants a little bit. We've been eyeballing 400 million a day of growth. It will probably be a little bit more than that now. And you'll see that in the release in the second half of the year when we update the plan. I mean buying Saguaro obviously, we bought the first half of Saguaro back during COVID. And ahead of developing Laprise-Conroy, we always wanted to have that at 100%. They finally decided they were ready to sell. So that actually changes the timing on that because that 50%, it sort of sat at the end of the various series of projects we have in the North Montney, all of a sudden, at 100%, it's one of the lowest capital cost wedges of resource we have to develop up there. So it probably moves up as well. But the total production volume from the North Montney growth will be between 100,000 and 150,000 BOEs a day if you extend this out to 2030.

Our next question is from Kalei Akamine from Bank of America.

Mike, Brian, I guess for my first question, it's kind of a follow-up on one of the previous questions. I want to ask about that long-term production outlook. It seems like the new messaging suggests that the new plateau is around 850,000 BOEs by 2030. Just trying to get a sense of what the bridge looks like from 2025, i.e., how much can you grow into current capacity, how much do new projects add and how much new acquisitions add? And when you look that far out, do you see a need for more infrastructure, be it pipeline egress on the crude oil side or more LNG in order to accommodate the growth plan that you've laid out?

Well, on a basin scale, even filling the 2 Bcf a day of LNG Canada Phase 1 is probably going to take industry just based on the pace of how quickly new volumes can be brought on stream into the infrastructure is probably going to take 3 years plus. You'll see all the elements of that full development and adding 2030 and 2031 and the much elevated production volumes that are associated with Groundbirch and the North Montney Phase 2. You'll see that whole series of projects and plants when we release the full plan in '25. And as I mentioned, the acquisition has actually changed the cadence and the costs and the volumes in that whole plan.

For my second question, I want to go back to M&A. And look, I don't know if that's what the market is responding to today, but this is how you built the business over the last 20 years. With kind of the sustained commitment to picking up good assets and geologic setup that you do believe in. In any case, the 2 acquisitions, I think, have strong industrial logic. It's on your lease line in an area that you plan to grow. Just can you kind of help us understand whether these are unique situations? Or if there are other opportunities to do similar deals under the same context? Or if M&A does take place, it would be more of a step out from areas that you're currently -- that you currently consider core?

Yes, no, thanks for that question. We don't plan to step out from our existing core geography and never have really for the full 17 years of Tourmaline's corporate existence. So we know what fits and what doesn't. We learn as we drill more wells. We figure out how to make more money off these assets. And as I mentioned, almost all of these deals are vendor-driven. They come to us. Todd was a great example. The New Zealand mothership, if you like, approached us in the fall and said, we're ready to sell the Canadian portion of our operations. Well, we own the other half and that was very liquid-rich Tier 1 rock that just made sense to buy.

So similarly, with Saguaro, I mean, we're obviously very friendly with them. We've been jointly developing Laprise-Conroy at a pretty modest pace, really, for the past 4 years. And then now we can accelerate that into what I think, hopefully, we're all right, but we all expect a much improved Canadian natural gas pricing environment. So as I responded to Aaron's question, we're doing both. We're building the infrastructure, and we're very excited about it. And as these opportunities come along on the M&A front, if they make sense and they can improve our free cash flow yield, which is one of our key screening criteria, then we'll act on them.

Your next question is from Jamie Kubik from CIBC.

I've got a couple here, but just curious on the liquids volumes in Q1. These were a bit lower than the range that Tourmaline provided with its Q4. Can you just comment on some of the nuances in the quarter that drove that and how you expect these to recover in the coming quarters?

Jamie, it's Jamie Heard here. We actually have seen liquids continue to push higher through the quarter. This quarter had a feature where we started at basically the base we communicated on exit in 2024. And then volumes steadily ramp quickly higher into March and then hit that 660,000 in April. And in April, we were doing well over 150,000 barrels of liquids and really happy with where liquids are today.

One of the other things that accentuates mix at Tourmaline is our storage assets. So we obviously sell gas out of storage in the winter and then inject in the summer. And I think sometimes that catches people a little bit offguard that add some natural gas to winter periods. But from our perspective and how we see the rest of the year, we see no deviation to our original thoughts on how liquids would trend. And I think you're going to see great liquids rates through Q2, through Q4 and 2025.

Okay. And then maybe just circling back to the capital allocation question. Slide 6 of your presentation does show most of the free cash flow expected on strip for 2025 is largely spoken for through the base and base dividend and special. Can you just talk about how you're thinking about capital allocation for the balance of the year with respect to that?

Sure. Well, the 5-year plan update that we released yesterday, we're consistent with our methodology. So we picked the strip on the 15th of the month prior to the release of the quarter. That was a particularly bad strip to use. So we're happy to report that if you ran it today, '25 and '26 free cash flow were both up a couple of hundred million dollars or more already. So we've got a little bit more of that capital to allocate. But as it stands right now, maintenance is about $1.9 billion. Growth is in the sort of $600 million to $800 million this year. And then the balance is going to the base, which, remember, we increased the base and reduce the size of the special with our March release, and we'll continue with that program through the balance of 2025.

Anything you want to add, guys?

That's good.

Does that help, Jamie?

Yes, you bet. And then last one for me. Just there's been obviously a lot of commentary on LNG projects in North America throughout the news. Can you talk a little bit about your part in Rockies LNG, how that project is progressing in the background and things of that nature?

Sure. Well, the leader of the project, Western, did secure a significant amount of capital to do the full engineering, $150 million. So they're proceeding with that. They continue to seek landed deals to put them in a position to FID. I mean you'll have to check with them when they really think that FID is going to come. We're -- I think all the participants on the supply side are expecting perhaps in the first half of 2026.

So we're excited about that one. There is the opportunity to make a larger -- I'd say the credit quality of the producer group has steadily improved. So there's multiple large producers lined up on the supply side, and we have more than enough supply. And hopefully, there's Canadian momentum to start approving these projects because I think we're aligned on our thinking, Jamie, on just how important LNG is to Canada because it's great for the economy of the entire country, it reduces emissions in the global atmosphere, and it's a great opportunity for improving indigenous prosperity.

Your next question is from Josh Silverstein from UBS.

So an M&A question as well. I was curious about the financing of the transaction. You issued stock for this. Why stock versus cash given where the balance sheet is? You mentioned, Mike, that you want to leave a strong balance sheet for further acquisitions. So do you have appetite for a large acquisition here? And like you also just mentioned if you ran the current strip, cash flow was a couple of hundred million dollars higher. So I'm just curious why issue stock again for this, you did it for Groundbirch versus a cash transaction to further kind of leverage the potential for rising natural gas prices.

Well, both vendors for these transactions wanted stock. So that's probably the simplest answer. And yes, there may be other opportunities that arise. It is a busy market out there. Obviously, it's got to fit, and we talked about our screening criteria already. So we are preserving that pristine balance sheet for potential other opportunities that might come along.

All right. And maybe just...

And they won't be large, sorry, because you said saving it for a large -- our MO over the decades is we don't do anything extremely large. I mean the largest we do is sort of $1 billion to $1.3 billion, and we're not looking at anything of that size right now either. So just so you know, we don't do a merger of equal style deals. That's just not what we want to do.

Yes. And then maybe just, I guess, a follow-up financing question on that. You guys already have decades of inventory. Why not maybe sell some of the noncore stuff to finance this to further high-grade the portfolio?

We don't really have much that doesn't fit in the long term. So I mean the Deep Basin produces about the same as the BC Montney right now. But I mean, the M&A we're doing right now is really ensuring we have a third decade of Tier 1. And I do point to what's happening in North America, particularly south of the border, there's less Tier 1 available than there used to be. And we see the Western Canadian Sedimentary Basin becoming much more important for supplying the whole North American gas complex, including the Gulf Coast in the U.S. and a growing, hopefully, LNG industry on Canadian West Coast. And so securing Tier 1A is really the name of the game right now for longevity and profitability. And we take a very long-term look at Tourmaline and the overall natural gas business. So it's hard to break out something and sell it because it actually all fits in the long run.

And when it didn't, we did. Like if you recall, after we acquired Bonavista, we quickly sold the Duvernay. So if there ever is a struggling asset, we are quick to get the position back to where we're going to be core in drilling it.

Got it. Okay. And then my separate question was just on the long-term outlook that you guys put out there, volumes are up 100,000 BOE per day, your spending drops $425 million and yet the free cash flow outlook goes down. Is there anything that -- and obviously, the strip price is changing there. But is there anything else that we should be thinking about in the forward outlook that has lower free cash flow to it? Is there some costs that go up at a certain time or anything like that, that we should be thinking about?

No. I mean the main reason that free cash flow drops in the out years and the 5-year plan is strip backwardation. And what we also haven't put in that plan is as we execute the Northeast BC infrastructure build-out, it will drop our op costs. And just that wedge of sediment that we're developing in Northeast BC, it is our lowest cost, both capital and operating and the most liquid rich. And so all of Tourmaline's operating metrics are going to improve in that sort of '27 through '29 timeframe as this wedge of lower op cost production comes into the base. And even at it will be at least $0.50 per BOE OpEx reduction. We haven't put that in the plan yet. That's at least $150 million of free cash flow per year in the back half of the plan. And if we make it larger, the overall Northeast BC development, that operating cost reduction and the result in free cash flow will realize increases as well.

The other thing that we fully burdened the plan with there, Josh, is taxes. 2026 forward cash taxes are towards $400 million a year. But of course, in reality, as we execute acquisitions on an annual basis here or there, that often has a tax benefit. And so this year's cash tax will be much lower than that, towards $100 million depending on the strip we're running. And so we don't forecast acquiring tools, but that is something that will probably result in additional cash flow and free cash flow in each annum as we're in it.

Your next question is from Fai Lee from Odlum Brown.

It's Fai from Odlum Brown. Mike, I just want to get your thoughts, if you want to share, I hope you share them, on long-term natural gas prices, as you mentioned, the strip and backwardation, it looks like in the outer years, NYMEX gas price is around $3.50 implied by the strip, somewhere in that range. How do you view that kind of price level in the context of rising demand in data centers, LNG export terminals. Just do you have any thoughts about long-term gas prices and where you think you might sell in that, I'd appreciate it.

Sure. Well, we expect them to go up because we do agree with, I think, where you're going, Fai, that there's a bit of a disconnect there. That being said, we'll continue to ensure that our base business makes money at $1.50 to $1.75 Mcf. And I think, consistently, that's been our messaging. Strips are improving quite rapidly, actually, even AECO, which is surprising, but it's put on $0.50 for '26, and Jamie, has it for '27 as well?

It's coming up.

It's coming up. So it's starting to improve kind of right now, and we think that's in advance of first volumes showing up on Coastal GasLink.

And like, Fai, big picture, just thinking about what we've seen over the last 3 months, you've seen LNG plants continue to announce FID. We saw the Woodside plant in Louisiana. And that was actually a bit of a surprise to everyone. You've also seen production outlooks thin in a slightly lower oil deck, especially with the comments offered by some of our peers in the United States looks as though associated gas production might be smaller than previously anticipated. And yet the expectation for power, LNG and industrial gas demand is as stable as ever. And looks to be something that will markedly outpace some of the years prior. We're going to be in the, call it, 3 to 4, sometimes 5 billion cubic feet per day of demand annually growth.

And that also is echoed up here in Canada with LNG Canada and our own domestic demand story. So we do see a ton of demand coming into market. And then all of a sudden, a much more reluctant supply dispatch curve in the United States on the associated gas side, but also on the dry gas side. They want ever more higher prices to grow their basins, and that's going to create margin expansion for us at Tourmaline because as Mike mentioned, our supply cost under $2 here at $1.50, those are stable and they're not going up. And so if realized prices can navigate themselves higher on this S&D outlook, that means more free cash flow for us.

Great. If I may ask a follow-up, if you may. Like it sounds like reading between the lines here that $3.50 in your mind is probably too low as a longer-term price. If you had to put a peg like a specific number on what that price might be given the dynamics, where would you put it?

Well, I think, you followed us for our whole existence, Fai. You know we're pretty much -- we're always wrong on our price predictions I think, quite consistently. But we expect AECO next year, particularly in the winter to be $4 to $5. How is that? Because it's almost there now. If the dip comes in from $1.80 to $1.20, then you're there.

[Operator Instructions] Your next question is from Peter Cook from Tourmaline.

Mike, I was just curious on -- any thoughts on the impact of the tariffs in the U.S. on you guys? And with all the politicals going on, it's been sort of a bit of a mess. But I was curious what impact that might have on gas you sell into the U.S. market and so on.

Yes. Well, we don't -- Peter, I mean there aren't tariffs on Canadian energy at the current time. So there's no impact there. Perhaps a little bit of cost inflation on steel, Tourmaline in particular, we don't source very much of our tubulars from the U.S. might be a modest impact on sand on our fracking business, but nothing material at this point. And I will reemphasize there are tariffs on energy, which makes nothing but sense, given how intertwined the energy systems in the 2 countries are they really don't make sense. And we should be working together to grow the North American energy complex.

That's for sure. Anyway, hopefully, they get this whole thing squared away at some point soon. We're all friendly.

We're with you.

[Operator Instructions] There are no further questions at this time. Please proceed with closing remarks.

Thanks, everybody, for attending. We look forward to chatting with you in the next quarter.

Ladies and gentlemen, this concludes your conference call for today. We thank you for participating and ask that you please disconnect your lines.