Good to see you again. Good to see you too. Well, good morning everyone, and thank you for joining us today. We've got Gordon from Aethon. He's the President and Partner at Aethon Energy. You've got Michael Rose, President, Chairman, and CEO at Tourmaline. And you've got Nick Dell'Osso, President and CEO at Expand Energy, with us here. Thank you for taking the time. Maybe Sam, if you wanna start. Yeah, sure. Hey everybody, and thank you all for joining our panel today. It's really great to have you. So what we're gonna do, we're gonna start with some questions on the macro environment for natural gas markets in the U.S. And then I'm gonna hand it over to Ati, who'll cover more micro-focused questions. And Gordon, I'm gonna start with you. We've had a lot of price volatility over the past 12 months. We're now trading at over $1 above where we averaged last year in prompt. And also a lot of changes in production, and especially in the Haynesville. So I wanted to start with you asking, what is your outlook for Haynesville production path from here, as well as what do you think the growth incentives will be going forward, especially in the first half of this year? Sure. I appreciate y'all having us, and it's great to be here. I think if you think about last year, industry responded pretty rapidly to low pricing, and the market was sending a pretty clear price signal that we didn't need additional gas in the late spring. I think that was obviously Golden Pass created a lot of issues, and the timing around some of the on-stream dates for some of these facilities has been a challenge. Producers probably got out in front of that. So I think from our standpoint, we view this as more of a time to be more cautious about before trying to really grow supply. We being vertically integrated and having our midstream across about 80%-90% of our production, that gives us a margin uplift that allows us to be a little more comfortable in these lower price situations. So, you know, when we think about that, there's really not a huge incentive for us to grow production. You know, in the Haynesville, BP has a position that they haven't been active on developing that certainly could provide some additional swing production, but it's a longer cycle time. And I think that means that it's gonna take longer for the basin to react to pricing. And today, you know, I don't see that pricing indicating significant growth. You know, we'd wanna see triple-digit type returns 'cause otherwise they're gonna be impacting free cash flow. And that's not really our objective. Do you think it's enough at least to pare declines though? I think so. I mean, around $3.50 works pretty well, for most participants, depending on where that inventory is and what, you know, what their margins are. Yeah. That makes sense. And that brings me to you, Nick. I think you guys were very innovative last year in the way you responded to the price incentives, particularly because deferring TILs had never been done in that scale that you announced. So it was very interesting to see because it created a lot of, I think, needed flexibility on how to respond to price incentives, whether with a little bit of shut-ins, deferred TILs, and DUCs. So to the extent that you can comment, how do you see this pace and magnitude of maybe bringing back that inventory of production to the market? Yeah. It's a good question. So we came out in our earnings in Q3, so call it November 1st, and talked about bringing all that activity back on rapidly through the year. And that ties back to what our original strategy was here. When we decided to defer these TILs, we sort of backed into this strategy by realizing that the market was very oversupplied, was gonna stay oversupplied for the year. We weren't really prepared for that level of oversupply when it hit us, and we wanted to make an impact immediately. If you only make that impact through capital, it takes a very long time. And so what we're really trying to do is separate the cycle of capital from how we think about bringing production to market, and we've been able to do that through the year by deferring TILs. We brought production down immediately as a result of that. Things have leveled quite a bit when you think about how capital then has flowed. We brought capital down slowly through the year, which means we were more efficient in how we reduced our costs. We didn't have all the friction and the high well costs that you would experience if you did things very rapidly, so now we can utilize some of that capacity that we created in 2024. We can use it in 2025 to offset declines that are coming from the reduction in capital we have. In other words, we can level out our production, where it is to a good level in 2025, around 7 BCF a day, and that cadence and that timing is exactly what we expect to do throughout the year. We've had a lot of questions at this conference and leading up to it about, hey, it got cold, so are you gonna go faster now? The answer to that is no. Nothing's changed for us. The strip is really largely in line with where we saw it to be at the time that we made this decision about what that radical bringing on of that activity would look like in 2025. So really things are playing out as expected, so nothing's changed for us. That's interesting. In particular, when it comes to shut-ins, we like to look at the high-frequency data. I think a lot of people in the room might do as well. And it does point to, I think, a lot more moderate volumes now of shutting production in the region versus several months ago. Is that how you see it too? Yeah. We think about curtailed volumes in a couple of categories. Obviously, you can have base curtailed volumes, then you can have deferred turn-in-lines, then you can have DUCs. Base you can adjust literally on an hourly basis. Deferred turn-in-lines might take a couple of days if you wanted to bring them on. DUCs, you gotta go out and complete the well. So it's sort of a timing of how they can come back. We think most of the curtailed base was back online by mid-December. Probably all of it was back online by mid-December. Gotcha. Now today there's a lot of freeze-offs again. So. Sure. You'll see through the winter volumes go up and down with weather, and when you have no freeze-offs but it's cold, you get that pull in the Northeast. You can see volumes really kinda bump up a bit when you have in-basin demand pulling hard in the Northeast. So you do see some volatility around that, but generally we think that there's no active curtailment of base volumes today. That's great color. Thank you. I wanna shift gears now a little bit to you, Mike, and let's talk politics. We're just about to see change in administration. I bring it up because, of course, there were discussions about potential tariffs on U.S. imports of all Canadian goods, potentially including energy. How do you see, one, the likelihood of that happening, but two, the potential impact on the gas market as a result? How are you guys positioned to deal with that possibility? Sure. The original narrative was President-elect Trump suggested that Canada do a better job on their side of the border, controlling people and drugs, and other things, and if you don't, we're gonna put a 25% tariff on everything, so I think if we actually do a better job on the border, which is certainly what our premier is doing, and even in the federal budget, they put money aside to do a better job, so I think if we live up to that end of the bargain, this whole tariff thing probably tones down a little. Energy is one of the areas that we're quite integrated continentally already, and both countries benefit from the energy trade going both ways. It's why you haven't seen tariffs in the past. When Mr. Trump was president before, there were some tariffs, and it was more on the ag side than the energy side, but on hydro, on natural gas, on heavier grades of oil, you know, we need each other, and we're fully integrated. I'd like to see that integration completely built out and have kind of fortress North America, full energy self-sufficient continent is probably the way to go. Gas specifically, you know, Canada ships. Well, I think we set a record today. It's 9 BCF a day to the U.S., but typically call it eight, eight and a half. It accesses pockets in the U.S. that don't have domestic supply. So that would be our California for Tourmaline. I mean, we're the largest single supplier into California. It's a demand pull market. There's no easy-to-access supply. And so if that gas gets tariffed, it's just gonna get passed on to consumers, and then it kind of violates what we see as what the incoming administration's goal on energy is: affordability, reliability, security. So we just don't think it's low likelihood. That it happens. Yeah. We'd agree with you, by the way. Yeah. I wanna bring you back to Haynesville. Gordon, we talked about how in 2024 the incentives in place were for producer discipline, but looking ahead, there is a decent potential for demand for gas out of the U.S., in particular for LNG exports. So when we think about what the price incentive needed would be to generate that kind of growth, what would you say that is if we're focusing on non-core Haynesville? On Haynesville in particular? Yeah. I think if you look back at the Russian invasion of Ukraine and we saw gas spike to $8-$10, and you saw what the market reaction was. And so obviously we know that's too high. I think we've seen this little story before, and I think our view is we don't wanna get out in front of the demand pull again. I think we need to see some of this materialize. We've seen ramp-ups take longer. We know there's going to be more volatility. And so it's really what does the futures curve look like? What can I hedge into? If you think about I'm hedging, let's say we're pretty aggressive on a hedging perspective. And so we produce about three BCF on a gross basis, and we're trying to hedge about 70% of that when we approve a capital program for the next year or if we were to make changes mid-year. We want to see, like I said, probably triple-digit returns on that 70%, assuming that there is a price, a negative price situation sensitivity we're going to run. That's why I think there needs to be quite a bit higher pricing. Ultimately, there's not a whole lot of spare capacity in the Haynesville. I mean, today we're running about eight rigs. We were running, at one point, close to 16. Certainly, there's been rig efficiency gains, but, you know, it's not something we're not here to balance the natural gas market. We're here to respond accordingly and also meet our shareholder obligations. So, I think there's yeah, it's a difficult situation because the future, you're talking about a lot of potential demand coming on. And we know that that's going to necessitate higher pricing. But until we see that materialize, it's not something we wanna get out in front of. Would it take north of $4 in a minute to you, you reckon? I think, yeah, it probably starts with a $5. To bring significant development on. Interesting. Otherwise, I mean, what? So I'm increasing, you know, the cycle time is quite long. Nine to 12 months. We did a similar strategy to expand and deferred TILs. You know, that's a unique thing that the Haynesville can do because you don't impact just the way flowback works. You're able to do that without impacting well performance. That kinda acts like a storage medium. That's another strategy we've thought about doing. The curve doesn't suggest that we should be doing that into, you know, winter 2025, 2026. Again, I just, you're gonna need to see a significant price to necessitate that type of activity level. Yeah. Yeah. I think that makes sense. And related question to you, Nick, because we've been in this transition from very low demand growth for gas out of the U.S. into the promised land of a lot of LNG export growth. And this keeps being a little pushed back. In fact, all of the upcoming LNG export projects being built right now across the Americas that were supposed to come online over the next 12 months were all of them delayed to one extent or another. So when it comes to the timing, like, when do we need to grow production again, you reckon? Yeah. I think it's a really good question. I mean, if you look at the market 2025 to 2026, you're gonna see, by the end of 2026, you're gonna see an incremental 5.6 BCF a day of export capacity online. That's Plaquemines, that's Corpus Christi Phase III, that's Golden Pass. And, you know, all of that comes online. The Plaquemines and Corpus Christi are coming online now, but, you know, gradually and somewhat slowly. Golden Pass is a 2026 event. So by the end of 2026, you should have full run rate. All of that's online. 5.6 BCF a day is actually quite a bit for us to grow. Yeah. We're back as of this week around where we were a year ago, 103-105 BCF a day. Growing from here is going to be it's gonna take some time. It's gonna be expensive. So I think you do need to see some volume growth, and I think you are just seeing prices that might encourage some volume growth. We think about the Haynesville as being the marginal supplier in the U.S. when we're around this low 100 BCF a day market. The marginal breakeven in the Haynesville is probably 350. And the need for growth is gonna have to come from those volumes. So therefore you're gonna have to price something, I think, again, materially higher than 350. You guys all have models to look at this yourselves. You know how sensitive Haynesville wells are to commodity price. The difference in the return profile on a Haynesville well at $3.30 from $3.50 to $3.70 is really, really significant. It's a very steep curve as you go right through that marginal breakeven. There's plenty of wells in the Haynesville that make money at $2.50. But again, if you're gonna grow volumes, you're gonna need to capture the growth from areas that require a higher price. I think the need is now, but I also think the volumes are here that we're supporting what we have today. The curve is telling you it's really not concerned about growth much beyond where we are today. You have to think about how long you're gonna need those volumes for. That 5.6 BCF a day comes online by the end of 2026. By 2027 to 2028, you will have a lot more LNG competing, supply around the world, and you may see some of those facilities not run at full capacity. And so, so what do we really need out of supply growth in the U.S. and for how long? I think we likely have a very tight market until you see Qatar bring on incremental trains, which is probably the 2027 to, end of 2027, beginning of 2028 timeframe, and you're gonna see really then a question about what does domestic demand for gas look like as, as pulling on that, same source or, has international demand grown fast enough that you need all of that supply at once. And so I think it's a bit of an unknown as to how long we're gonna need that growth. I think understanding how long we're gonna need that is really the biggest thing we're trying to understand when we think about whether or not volumes should be grown materially out of the US. You don't wanna grow for a season. You wanna grow for something that is durable over several years. What do you need to see in the S&D before you make that decision to add rigs? Yeah. You need to see that supply demand is separate for a long enough period of time to support your cycle of capital. Again, if we make the decision to add a rig today, you're really seeing the run rate, full level of the incremental production of that rig at least 12 months later, right? So, and then you need a period of time to earn a return on that. So how long do you need to see that incremental demand is there and the supply that you're gonna bring to market answers that incremental demand? How long does that have to be in place before you're willing to put your own capital into that equation? It needs to be durable. Thank you. Thank you for that. I wanna bring you back to Canadian production, Mike, because there are a lot of questions we get about how much Canadian production can grow. We have LNG Canada about to start up over the course of this year, and there are questions as to whether Canadian production growth can meet that easily so that it won't impact Canadian exports to the U.S., so I'm curious, what is your outlook on the Canadian production path from here for natural gas? Sure. It's a big year for Canada because we finally do have another export point, and we are actually gonna have another market that we can access other than the U.S. 2 BCF a day on our current markets about an 11% demand growth, so comparable to the initial tranche of Gulf Coast LNG on the demand uplift on overall U.S. supply. So we think that is a structural long-term improvement in AECO and Station 2 pricing, because the 2 BCF a day exist in the system now. They're gonna get pulled west. How long does it take to fill that sink, if you like? We look at 2022 as an instructive year. Prices were good, and the small caps and mid caps had room in their plans 'cause they let production slide during COVID, so it was easy, capital-efficient production to add. We added half a BCF. That's it. And that was in the best possible year. So it's gonna permanently improve our local pricing. We're fortunate just the style of resource we have, and certainly what Tourmaline has is, it's much lower capital costs. So our breakeven prices are $1.50. You often get the question, well, you know, why do Canadians keep drilling and deliver into these prices? Well, that's part of it, because the breakeven costs are so low. And then, of course, we're a diversified marketer. I mean, we ship 1.27 BCF to premium markets in the US. Our average realized price is, it's over $3 low. It was $3.19 during 2024 in the worst possible pricing. Where can Canada go from an LNG context on the West Coast? LNG Canada Phase 2 is an easy one. I think that becomes simpler with the new government that we're gonna get, hopefully sooner rather than later because it's very supportive of nat gas and LNG growth and emissions reduction in Asia. That whole equation kind of goes together very, very nicely. Rockies LNG is a project that we're helping push along, which is the old Petronas pipeline route, which is another 1.7 BCF a day. So we could very quickly go from 2 to 6.5 BCF a day on the West Coast. We also think in the long term, given that our two big gas resource plays, the Montney and the Alberta Deep Basin, are much earlier in development life, and so in the next decade, we think there's gonna be a draw on Canadian gas to get more gas south to service that 25-30 BCF a day complex that's gonna be on the Gulf Coast. So yeah, it's an exciting time. I've never seen it better. I've been doing this for a very long time. I've been predicting high gas prices for a very long time, but the 2025-2030 outlook, really, before you even get into electrify everything and data centers and so forth, it's very exciting. Fair enough. I'm gonna hand it over to Ati now. Thank you, Sam. Nick, maybe I'll start with you, on your marketing strategy. You've got a bunch of heads of agreements. If you can spend a few minutes talking about how you're thinking about that piece, and do you still require a little bit more international exposure? How does that marketing strategy play out this year? Yeah. We're excited about what we're doing from a marketing perspective. And primarily what that's focused on is getting access to more markets for our gas. When you think about what's going on with the U.S. market, we've gone from zero exports in 2016 to about 15 BCF a day growing north of 20 here very soon, which will be, you know, effectively, almost 20% of our market. And so the dynamics of demand internationally are pulling hard on the supply of the U.S. We should absolutely have pricing exposure to those end markets that are pulling on our supply. And if we don't, then we just have a mismatch. So we really need to gain that exposure and create some diversification around where we sell our product and the customers that we're connected to. So far we have one supply agreement. So we have a long way to go. I had previously said a few years ago that 15%-20% would be a good target for us, with how much gas we would like to see priced on an international index or in international markets. I still think that's a great number. I would just note that post our merger, that's a really big number. And it just will take us a long time to ever achieve that quantum of gas that's marketed internationally. So I think we'll be pretty prudent about how we do it. We're just as focused on gaining access to more markets domestically as we are internationally, though. When you think about really historically how we've sold our gas in the U.S., it's pretty close to the gathering system. We have some FT that takes us a little bit further from market. We're gaining access to the Gillis delivery point here over the next year out of Louisiana, which is going to put us directly in contact with the LNG export facilities. That's a great evolution for us. We need to gain more access to the east, for end users of our product, throughout the southeast and mid-Atlantic where you see a lot of gas demand growing. We need to bring more demand closer to our wellhead. We talk a lot about data centers and AI across the industry over the last 18 months. It's consumed a lot of our time, and we think the best answer for all of that incremental growth is gonna be to bring those projects closer to the wellhead so that you reduce the infrastructure needed to deliver the ultimate, valuable product, which is the data that you're trying to create. You need to reduce down the pipeline to deliver the fuel to the power plant. You need to reduce the transmission line to deliver the power to the data center. You bring it closer to the wellhead and you do that, so we think those opportunities are pretty significant and represent a growth opportunity for how and where we sell our gas domestically as well. You know, what Mike said a few minutes ago, which is that, we've all thought a lot of years about how demand for gas should be growing. It is so much more tangible today than it has been in my career. It's a pretty exciting time. Just to think about how we position ourselves for that growth, but then also the volatility that's gonna come along with that growth is something that we really spend most of our strategic planning efforts around. It's how do we position for a higher market, but also a more volatile market? And how we market our gas has to play a huge role in how we can ensure that we deliver as much product as we can to the markets it's needed when it's needed. Right. Well, on that note, Mike, maybe if you can spend a few minutes talking about the gas demand from power generation in Canada, and how you are seeing the market play out, what's the opportunity set for you? Sure. I think Alberta is a good jurisdiction for it. It's got, from a Canadian perspective, the best and cleanest regulatory processes. We've got a premier who's all in on attracting. We've got a good climate, 'cause we're certainly cooler. At the AESO, which is our grid, there's nine projects that are in the queue that would equate to about a BCF a day. So, you know, decent amount of demand growth. And then there's a whole series of, you know, behind-the-fence projects that could happen as well. We can provide a good offering as we, you know, own a number of plant sites. We have water, we have power, we have lots of gas, and it's not very expensive right now. And we also have the CCUS angle because we control the disposal rights. Actually, we bought them four years ago, in the Alberta Deep Basin. So it's another whole layer of potential demand in the system. And so, it just adds to, you know, the golden age of gas, if you like, is finally upon us. I found that slide. I make lots of slides. So I found one I made, called the golden age of gas and thought, wow, this looks good. Unfortunately, I made it nine years ago, so maybe we're at. You were You were ahead of your time. Yeah. Yeah. Maybe we're finally here. Maybe Gordon, on that, on that topic in terms of gas production opportunities, you've been spending a lot of time on the Western Haynesville. Sure. Can you talk about what you're seeing there, the type curves, and obviously it's a deeper asset? Just talk to us about what that asset looks like, how that plays into your strategy overall. The Western Haynesville, we started looking at the play in 2018 and 2019 and leased up what we felt like was a really core position that was gonna be the most opportunistic to develop. You know, it is exploration, so you have to be thoughtful about how you approach that. We have a partnership with Black Stone Minerals, and so we've been drilling deeper, high-pressure, high-temperature wells. We've drilled about 450 wells in the Haynesville today, so we have a lot of experience. We've drilled 10 wells there. It's about 16.5 total vertical depth, and you know, pressure's around 11,000 pounds. What we're seeing is the wells are not declining. They haven't turned over yet. These are very, very, very strong wells. We're trying to be methodical and thoughtful in the way that we approach that. And so we're not just throwing a bunch of rigs at it. We're being good engineers and trying to be disciplined about it and make sure we understand exactly what's going on on the subsurface and make sure we optimize that development accordingly. You know, we're looking out for things like crushing, other issues you could have when you move to these deeper wells and trying to understand, our subsurface team is looking at the modeling to make sure we develop that accordingly. So we're really excited about it, but we wanna be thoughtful and prudent. We've got a significant amount of inventory, and so we're able to allocate, you know, a reasonable amount of capital over there and do that in a what I think is a prudent way. At what point do you think it starts becoming a little bit more integral to the strategy overall? Like, is it? It sounds like there's still a little bit more work to do to understand that asset completely. Are we very close to it? Is it a little far away? You're always understanding assets, right? We're still understanding every asset we have and continuing to refine and optimize. And that's, you know, an industry has shown to be very good at. And so, you know, I think we're very excited and confident in the asset. But again, we don't wanna go fast forward three years and say, oh my gosh, why did we put four rigs on that asset? And the way we developed it was not as well as we would have today. And then, you know, you're always gonna have that look back and say, hey, I would've done something different. But you know, these are expensive wells. $23 million-$25 million. So, you know, it's a lot of capital, and you wanna be thoughtful about the way you approach that. Got it. Mike, maybe if I can come back to you on your infrastructure approach to infrastructure development within having your own midstream assets. Can you talk to us about that thought process as opposed to the wide majority of the U.S. companies have taken a different approach? Yeah. We love infrastructure, and we've, you know, built and owned our own infrastructure through E&Ps that Brian and I have been at. Brian Robinson, our CFO, and Jamie Heard, our VP, Capital Markets, are also here and there in the back. It is one of the key components driving that $50 break-even. So your OPEX is lower, your on times are better. You control the pace of development. It actually accelerates the ability to become investment grade, which we are. And then being investment grade has allowed us to enter into these marketing arrangements and the diversification on that whole gas strategy that we started over 10 years ago. So they kinda feed on each other. And it just allows you to optimize free cash flow and make that much more money and then enhance your shareholder return proposition. Multiple whole myriad of benefits that come from owning and operating your own infrastructure. It'll last for 60 years if you maintain it properly. Right. This business will still be around in 60 years, so. Right. Makes sense. Nick, maybe if I can come to you on, your, you've mentioned drilling and, completion cost savings in the Haynesville as you go through the integration of the acquisition. Where are we right now? How do you see that evolving? Are there additional opportunities showing up? Yeah. There are additional opportunities showing up. We added $100 million to our synergy estimate, at the time of our Q3 earnings. So that was a 25% increase in the initially announced synergies. And if you think about the synergies, it breaks down between drilling completions relative to G&A now with that incremental 100 at about 50/50. So it's a pretty big number that we can save annually in how we drill and complete wells. That's one of the biggest drivers of why we did this merger, right? We're trying to make sure that we can reduce our cost structure so that we can position our assets to be in the money more through these cycles and through the volatility that we expect. We expect to continue to look for opportunities to drive costs lower and increase revenue out of these assets. We've been pretty careful about how we've defined our synergies. We really only want to underwrite in this merger what we know we can deliver, and then we wanna go out and get more. The incremental $100 million that we announced is a, is good evidence of that. The first part of our capital synergies was really around drilling. The incremental $100 million that we announced is primarily around completions. We'll continue to look for more, and we expect to continue to deliver more over time. Now, what we start to call, just ongoing capital improvements versus synergies related to the merger will get fuzzy over time as we deliver more and more cost savings because we've brought two companies together. We've got two teams working together to improve upon this business every day. We found that the appetite within the combined organization to make the business more competitive, more competitive is really tremendous, and it's encouraging. We see a lot of really good opportunities showing up. We expect our business to improve quite a bit over the next couple of years. All right. Makes sense. Well, we're at our time, so thank you so much for taking the time and appreciate all the answers. Yep. Thank you. Thank you.