Tourmaline Oil Corp.

Work being recorded on Thursday, May 8th, 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 Turnley's financial and operating results as of March 31, 2025. This has pretty much ended March 31, 2025 and 2024. My name is Scott Kirker. I'm the Chief Legal Officer here at Turnley 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 Termini 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, Termini's President and Chief Executive Officer, Brian Robinson, our Chief Financial Officer, and Jamie Heard, Termini's Vice President of Capital Markets. Let's 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 to questions. Go ahead, Mike.

Thanks, Scott. Good morning, everybody. Thanks for dialing in and being online. So we're pleased to review our first quarter 25 results, update ET activities, and update the outlook. A few of the highlights, first quarter 25 average production was 638,000 DOEs a day, up 8% over first quarter of 24, and quite ahead of our first quarter 25 expected production range. First quarter 25 cash flow was $963 million on total capex of $825 million, each 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 30th of 2025. A little on production. March 2025 average production was $645,000 BUEs a day, so higher than the quarterly average. The whole year forecast production range remains the same, however, at between $635,000 and $665,000. BOE 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. I've mentioned first quarter ET 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 breakups, 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 and $2.85 billion. Given the week's case in two gas prices, We will defer some of the planned Q2 crack activity into the third quarter of this year and will continue to match planned production growth to the anticipated increasing natural gas price curve in the second half. We will release the updated multi-year EP plan, including the full Northeast BC Montney gas and liquid 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 of probably 850,000 UEs per day. And you'll see that full plan the second half of this year. Just looking at the two acquisitions that were announced yesterday, In the North Monteney, we've entered into an agreement to acquire the balance of the jointly-owned Latrice Conroy assets through the acquisition of Seguero Resources. And in the South Monteney, 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 two transactions add approximately 20,000 DOEs per day of current production, an estimated 363 million DOEs of current 2T 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 wanton build-outs. 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 Thermaline. The LaPree Conroy asset is the key component of the North Mountain Phase II project, and the Greater Septimus asset is complementary and adjacent to our planned ground birch project. $400 million a day, 20,000 barrels per day, two-phase gas plant development. The South Mahi 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 two transactions, leaving the balance sheet in a very strong position for potential further acquisition in our core areas going forward. Briefly on marketing, our average realized natural gas price in the first quarter was $4.30 per MCF Canadian, so meaningfully ahead of the 805A benchmark price, which was $2.19 per MCF. So we continue to benefit from the expanding diversification portfolio and our strategic hedging program. From Q2 to Q4, $25 million. Termaline will average 2.1 GCF per day of natural gas sales that are not exposed to floating local market prices at ACO and Station 2. And we have an average of 1.16 GCF per day heads in 25 at a weighted average fixed price of $4.95 per MCF Canadian. 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 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 connect Sloan to the Gulf Coast in November of this year. On E&P, we have very strong E&P performance across all of our operating complexes in the quarter, and we set production records in all three complexes. In D.C., we have a series of tags that are well ahead of performance-type curves, 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 DOE per day from the total deep basin calm price. Notable exploration successes were realized in the South Deep Basin In the greater Williston Green area, our Hearst Valley River horizontal tested at 700 barrels per day of oil, less than 1% water cut and about a million a day of natural gas. And several new wells and pads in the downed GIF block 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. Thank you.

Ladies and gentlemen, we will now begin the questioning after session. Should you have a question, please press the star followed by the number 1 on your touchstone phone. You will hear a prompt that your hand has been raised. Should you wish to decline from the polling process, please press the star followed by the number 2. If you are using a speakerphone, please lift the handset before pressing any keys. One moment please for your first question. Your first question is from Aaron Volkovsky from PD Challenge.

Please go ahead. Good morning. Thanks for taking my question. 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 our tenant group? Sure. Yeah, thanks, Aaron.

Well, we're actually doing both. So the northeast BC Montney development is underway. We spent $200 million on facilities in 2024. 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 four plants, a series of regional pipelines, and a whole liquid 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 any of our build-out and be much improved piping, which I think we're all expecting to happen here over the next few years in Western Canada. Does that help?

Yeah, 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 ground birch expansion would be and what the phase two expansion would be?

Sure. In ground birch, 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'll 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 Seguero, obviously we bought the first pass of Seguero back during COVID. And, you know, ahead of developing LaPree's Conroy, we always wanted to have that at 100%. They finally decided they were ready to sell. So that actually... It changes the timing on that because that 50% is 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 BUEs a day if you extend this out to 2033.

Okay, Mike, I appreciate that. Yeah, you bet. Thanks for the questions. Your next question is from Eli Eckman from Bank of America.

Please go ahead.

Hey, good morning, guys. 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 DOEs by 2030s. 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 do 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, you know, I...

Even filling the two GCF a day of LNG Canada Phase 1 is probably going to take industry, you know, just based on the pace of how quickly new volumes can be brought on stream into the infrastructure. It's probably going to take three years plus. You'll see all the elements of that full development and, you know, adding 2030 and 2031 and much higher production volumes that are associated with with ground birch and the North Mountain phase 2. You'll see that whole series of projects and plans when we release the full plan in 2025. And as I mentioned, the acquisitions actually changed the cadence and the cost and the volumes in that whole plan.

Thanks, Mike. 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've built a business over the last 20 years with kind of the sustained commitment to picking up good assets and geologic setups that you do believe in. In any case, the two acquisitions, I think, have strong industrial logic. It's on your leaf line in an area that you plan to grow. 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, or be more of a step out from areas that you currently consider core? Yeah, 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 Thermaline'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. FOD was a great example. The New Zealand mothership, Hippie Flight, approached us in the fall and said, you know, we're ready to sell the Canadian portion of our operations. Well, we own the other half, and that was their liquid-rich Q1 rock that just made sense to buy. So similarly with Aguero, I mean, we're obviously very friendly with them. We've been jointly developing. at a pretty modest pace, really, for the past four years. And then now, you know, we can accelerate that into what I think, you know, hopefully we're all right, but we also expect a much improved Canadian natural gas pricing environment. So as I, you know, responded to Aaron's question, we're doing both. We're building the infrastructure, and we're very excited about it. And as the 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 ask them.

Great. Thanks, Mike. Our next question is from Gene Kubik from CRDC.

Please go ahead.

Yeah, good morning, and thanks for taking my question. I've got a couple here, but I'm just curious on the liquid volumes in Q1. These were a bit lower than the range it certainly 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?

Thanks. Hi, Danny. It's Danny here.

We actually have seen liquid continue to push higher through the quarter. This quarter had a feature where we started You know, at basically the base, the team came in on an accident in 2024, and then volume steadily ramped quickly higher into March, and then we hit that 660 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 Nick's determine is our storage assets. So we obviously sell gas out of storage in the winter. and then injects in the summer. And I think sometimes that catches people a little bit off guard, adds some natural gas to the winter period. But from our perspective and how we see the rest of the year, we see no deviations from our original thoughts on how liquids are trained. And I think you're going to see great liquid rates through Q2, Q4, and 2025.

Okay, thanks. And then maybe just circling back to the capital allocation question, slide six of your presentation does show most of the free cash flow expected on Strip for 2025 is largely spoken for through the PACE and PACE 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? Thank you.

Sure. Well, the five-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, you know, we're happy to report that if you ran it today, 25 and 26 free cash flow were both up a couple hundred million dollars or more already. So we've got a little bit more of that capital to allocate. But, you know, as it stands right now, maintenance is about $1.9 billion. Growth is in the sort of $600 to $800 million range. this year, and then the balance is going to the base, which, remember, we increased the base and reduced the size of the vessel with our March release, and we'll continue with that program through the balance of 2025. Anyone else?

Does that help, David? Yeah, you bet. And then the last one from me, 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 Rocky's LNG, how that project is progressing in the background and things of that nature?

Thank you. 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. I think all the participants on the supply side are expecting, you know, perhaps in the first half of 2026. So we're excited about that one. There is the opportunity to make it 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, you know, there's Canadian momentum to start approving these projects because I think we're aligned on our thinking on just how important LNG is to Canada because it's great for the Economy is the entire country. It reduces emissions in the global atmosphere, and it's a great opportunity for improving indigenous prosperity.

Okay, thank you. That's it for me. I'll hand it back. Your next question is from Josh Silverstein from UBS.

Please go ahead. Good morning, guys. Sort of an M&A question as well. I was curious about the financing of this transaction. You mentioned stock for this. Why stock versus cash, given what 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 read the current script, cash flow is a couple hundred million dollars higher. So I'm just curious why you stopped again for this, for ground birds versus, you know, a cash transaction to further kind of leverage, you know, the potential for rising natural gas prices.

Well, both vendors for these transactions wanted stocks, so that's probably... the simplest answer. And yes, there may be other opportunities that arise. You know, 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 it won't be large, sorry, because you said saving it for a large You know, our MO over the decades is we don't do anything extremely large. I mean, the largest we do is sort of $1 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 merger of equal style deals. That's just not what we want to do.

Yeah, and maybe just like a follow-up financing question on that. You guys already have decades of inventory, right? Why not maybe sell some of the non-core stuff to finance to further migrate 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 VC money right now. But, I mean, you know, the M&A we're doing right now is really ensuring we have a third decade of tier one and You know, I do point to what's happening in North America, particularly south of the border. You know, there's less tier one available than there used to be. And, you know, 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, energy industry on the 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 one of us, we quickly sold to Duvernay. So if there ever is a struggling asset, we're quick to, you know, get the position back to where we're doing core and drilling it.

Got it. Okay. And then my separate question was just on the launch and outlet that you guys put out there, you know, volumes are up 100,000 BUE per day. Your spending drops, you know, $25 million and yet the free cash flow outlet just goes down. Is there anything that, and obviously, like, You know, the script price is changing there. But is there anything else that we should be thinking about in the forward outlook that has lower free capital to it? Is there some costs that go up at a certain time or anything like that that we should be thinking about?

Thanks. No. I mean, the main reason that free capital dropped in the out years and the five-year plans is script aggregation. 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, you know, all of Termaline's operating metrics are going to improve in that sort of 27 through 29 timeframe as this wedge of lower off-cost production comes into the base. And, you know, even at, it'll be at least 50 cents per DOE off-ex 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 we make it a large... 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 burden the plan with there, Josh, is taxes. You know, 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. So this year's cash tax will be much lower than that, you know, $400 to $100 million, depending on the stripper running. And so we don't forecast acquiring pools, but that is something that will probably result in additional cash flow and free cash flow in each annum as we're in it.

Got it. Thanks, Remy. Thanks, Mike. You bet.

Your next question is from Faye Lee from Autumn Brown. Please go ahead.

Hi, it's a fire from Arlen Brown. Mike, I just want to get your thoughts if you want to share them on long-term natural gas prices. As you mentioned, the SIPs indoctrination, it looks like in the older years, you know, 9x gas prices around $3.50 implied by the SIP somewhere in that range. How do you view that kind of price level in the context of, you know, rising demand in the data centers, LNG export terminals, Just, you know, if you have any thoughts about that long-term job crisis and where you think you might sell in on that, I'd appreciate it. Thanks.

Sure.

Well, we expect them to go up because we do agree with, I think, where you're going, Si, that there's a bit of a disconnect there. That being said, you know, we'll continue to ensure that our base business makes money, you know, at $1.50 to $1.75. And I think, you know, consistently that's been our messaging. Strips are improving, you know, quite rapidly, actually. Even Aco, which is surprising, but it's put on 50 cents for 26, and Jamie has it for 27 as well. It's coming up. Yeah, it's coming up. So it's starting to improve kind of right now, and we think that's an advance of first volumes showing up on Coastal GasLink. And I'd like to try a big picture, just thinking about what we've seen over the last three months. You've seen allergy plants continue to announce FID. We saw the wood-sized plants in Louisiana. And that was actually a bit of a surprise to everyone. You've also seen production outlook thin, you know, in a slightly lower oil jack, especially with the comments offered by some of our peers in that case. It looks as though associated gas production might be smaller than previously anticipated. And yet, the expectations for power, LNG, and industrial gas demand is as stable as ever, and looks to be something that will, you know, markedly outpace some of the years prior. We're going to be in that 3 to 4, sometimes 5 billion cubic feet per day of demand annually, gross. 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 to terminate. Because, as Mike mentioned, our supply costs 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 at work, that means more free cash flow for us.

Oh, great. Can I ask a follow-up, if you may? It sounds like, reading between the lines here, that $350,000 in your mind is probably too low as a longer-term price. If you had to put a tag, like a number on what that price might do, given the dynamics, where would you put it? Yeah.

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

Okay, that helps. Thank you.

Okay, thanks.

Ladies and gentlemen, as a reminder, should you have any questions, please press the star key followed by the number one. Your next question is from Peter Cooks from Tour Money. Please go ahead.

Hey, Mike. I'm just curious, any thoughts on the impact of Harris in the U.S. on you guys? And with all the political going on, it's been sort of a bit of a mess. But I was curious what impact that might have on Dad's You sell in the U.S. market and so on.

Yeah, well, we don't, Peter. I mean, there aren't tariffs on Canadian energy at the current time, so there's no impact there. You know, 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 sands. on our fracking business but nothing material at this point and I will re-emphasize there are tariffs on energy which makes nothing but sense given how intertwined the energy systems in the two 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 friends.

Thanks, Peter.

Okay. Ladies and gentlemen, as a reminder, should you have any questions, please press the star key followed by the number one.

We'll pause a moment for further questions. 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 course.

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