Recording 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 Tourmaline's financial and operating results as of March 31, 2025, and for the three 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 for 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. Good morning, everybody. Thanks for dialing in and being online. We are pleased to review our Q1 2025 results, update EP activities, and update the outlook. A few of the highlights: first quarter 2025 average production was 638,000 BOEs a day, up 8% over first quarter of 2024, and slightly ahead of our Q1 2025 expected production range. Q1 2025 cash flow was CAD 963 million on total Capex of CAD 825 million. EP spending was about CAD 800 million, and that generated free cash flow of CAD 150 million for the quarter. As you have seen, we continue to consolidate the Northeast BC Montney, one of the most profitable gas plays in North America. We are doing that in concert with our Northeast BC infrastructure build-out, and we are 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 CAD 0.35 per share payable on May 26, 2025, and the company intends to declare a quarterly dividend of CAD 0.50 per share payable on June 30th of 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. 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 2025 average production in the 615,000-625,000 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 CAD 0.213056 per fully diluted share. As mentioned, first quarter EP Capex was CAD 800 million, so a little less than originally forecast. We expect EP capital spending during Q2 of CAD 560 million, as activities are always a little lighter during spring breakup, and that should yield an estimated first half 2025 free cash flow in the CAD 430 million range. We do expect commodity prices to improve in the second half of this year with the startup of the LNG Canada facility on the West Coast, and that should result in higher free cash flow in the second half of 2025 relative to the first half. On the 2025 capital program, the full-year 2025 program remains unchanged at between CAD 2.6 billion and CAD 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 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 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 the second half of this year. Just looking at the two 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. 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 two 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. 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 Two project, and the Greater Septimus asset is complementary and adjacent to our planned Groundbirch 400 million a day, 20,000 barrels per day two-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 two 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 430 per MCF, so meaningfully ahead of the AECO 5A benchmark price, which was CAD 219 per MCF, so we continue to benefit from the expanding diversification portfolio and our strategic hedging program. From Q2 to Q4 2025, 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 2025 at a weighted average fixed price of CAD 495 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 2023 and 2024 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 2025, 95 million of that, or about 50%, will actually commence flowing to the Gulf Coast in November of this year. On EMP, we had very strong EP performance across all of our operated complexes in the quarter, and we set production records in all three 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 2024 well performance that we delivered in the Alberta Deep Basin in 2024 continued in the first quarter of 2025 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 a million a day of natural gas, and several new wells and pads in the Down Dip Glock 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'll now begin the question and answer session. Should you have a question, please press the star followed by the number one on your touch-tone phone. You'll 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 two. 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 Bilkoski from TD Cowen. 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 organic growth? Sure. Yeah. Thanks, Aaron. Well, we're actually doing both. So the Northeast BC Montney development is underway. We spent CAD 200 million on facilities in 2024. There's CAD 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 Aiken. 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 cost 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? 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 Groundbirch expansion would be and the North Montney Phase Two expansion would be? Sure. In Groundbirch, the acquisition we did actually changes the configuration of the plants a little bit. We've been eyeballing CAD 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 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's 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. The total production volume from the North Montney growth will be between 100 and 150,000 BOEs a day if you extend this out to 2030. Perfect. Thanks, Mike. I appreciate that. Yeah, you bet. Thanks for the questions. Your next question is from Eli Echeme 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 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 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? On a basin scale, even filling the two BCF a day of LNG Canada Phase One is probably going to take industry, 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 adding 2030 and 2031 and much elevated production volumes that are associated with Groundbirch and the North Montney Phase Two. You'll see that whole series of projects and plants when we release the full plan in 2025. As I mentioned, the acquisitions actually change 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 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 two 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 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 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 at a pretty modest pace, really, for the past four 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 the opportunities come along on the M&A front, if they make sense and they can improve our free capital yield, which is one of our key screening criteria, then we'll act on them. Great. Thanks, Mike. Your next question is from Jamie Kubik from CIBC. Please go ahead. Yeah. Good morning, and thanks for taking my question. I've got a couple here, but just curious on the liquid 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? Thanks. Hi, Jamie. It's Jamie 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 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 the 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 off guard that I'll 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 are trending. And I think you're going to see great liquid rates through Q2, through Q4 in 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 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? Thank you. Sure. Well, the five-year plan update that we released yesterday. We're consistent with our methodology. So we picked a 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, 2025 and 2026 free cash flow were both up CAD 200 million 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 CAD 1.9 billion. Growth is in the sort of CAD 600-CAD 800 million this year. And then the balance is going to the base, which, remember, we increased the base and reduced the size of special with our March release. And we'll continue with that program through the balance of 2025. Anything you want to add, guys? That helps, Jamie? Yeah, you bet. And then last one from 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? Thanks. Sure. Well, the leader of the project, Western, did secure a significant amount of capital to do the full engineering, so CAD 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, where 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 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. 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. 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. Hey, Ben. Good morning, guys. Sort of an M&A question as well. I was curious about the financing of the transaction. You used 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 you also just mentioned if you ran the current strip, cash flow is CAD 200 million higher. So I'm just curious why, if you used 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. 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. Maybe just a quick question. 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 CAD 1-CAD 1.3 billion. And we're not looking at anything of that size right now either. So just so you know, when we don't do merger of equal style deals, that's just not what we want to do. Yeah. And then maybe just like a follow-up financing question on that. You guys already have decades of inventory. Why not maybe sell some of the non-core 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 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, when we acquired Bonavista, we quickly sold the Duvernay. So if there ever is a straggling asset, we're quick to get the position back to where we're going to be core and 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 CAD 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? Thanks. No. I mean, the main reason that free cash flow drops in the out years and the five-year plans is strip backwardation. And what we also haven't put in that plan is as we execute the Northeast BC infrastructure buildout, it will drop our opex 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 2027 through 2029 timeframe as this wedge of lower opex cost production comes into the base. And even it'll be at least CAD 0.50 per BOE OPEX reduction. We haven't put that in the plan yet. That's at least CAD 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 resultant free cash flow will realize increases as well. The other thing that we fully burden the plan with there, Josh, is taxes. 2026 forward, cash taxes are towards CAD 400 million a year. But of course, in reality, as we execute acquisitions on an annual basis here, there, that often has a tax benefit. And so this year's cash tax will be much lower than that, towards CAD 100 million, depending on the strip we're running. And so we don't forecast acquisitions, 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, Jamie. Thanks, Mike. You bet. Your next question is from Fai Lee from Odlum Brown. Please go ahead. Hi. Hi, from Odlum Brown. Mike, I just want to get your thoughts if you want to share them on long-term natural gas prices. Like you mentioned, the strip and backwardation. It looks like in the out years, next gas prices 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 at the data centers, LNG export terminals? Just if you have any thoughts about that long-term gas prices and where you think you might sell in that, I'd appreciate it. Thanks. Sure. We expect them to go up because we do agree with, I think, where you're going by that there's a bit of a disconnect there. That being said, we'll continue to ensure that our base business makes money at CAD 1.50-CAD 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 CAD 0.50 for 2026, and Jamie has it for 2027 as well. It's coming up there. Yeah, 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 by big picture, just speaking about what we've seen over the last three 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 outlook thin in a slightly lower oil deck, especially with the comments offered by some of our peers in the United States. It 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, three to four, sometimes five billion cubic feet per day of demand annually gross. And that also echoes 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 costs under CAD 2 here at CAD 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. Oh, great. Let me ask a follow-up, if you may. It sounds like reading between the lines here that 350 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. Oh, not the whole existence. We're pretty much always wrong on our price predictions, I think, quite consistently. But we expect AECO next year, particularly in the winter, to be CAD 4-CAD 5. How's that? Because it's almost there now. If the dip comes in from CAD 1.80-CAD 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 Cook from Tourmaline. Please go ahead. Hey, Mike. I was just curious, any thoughts on the impact of this tariff 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 gas you sell into 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. 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 aren't 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 again. Yeah. We're with you. 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 quarter. Ladies and gentlemen, this concludes your conference call for today. We thank you for participating and ask that you please disconnect your lines.