Expand Energy Corporation (EXE) Earnings Call Transcript & Summary

Yes. I think it's a really good question. I mean if you look at the market, '25 to '26, you're going to see -- by the end of '26, you're going to see an incremental 5.6 Bcf a day of export capacity online. That's Plaquemines, that's Corpus Christi Phase 3, that's Golden Pass, and all of that comes online. Plaquemines and Corpus Christi are coming online now, but ratably and somewhat slowly. Golden Pass is a '26 event. So by the end of '26, you should have full run rate. All of that is online. 5.6 Bcf a day actually quite a bit for us to grow. We're back as of this week around where we were a year ago, 103 to 105 Bcf a day. Growing from here is going to be -- it's going to take some time. It's going to 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 going to have to come from those volumes. So therefore, you're going to 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. And the difference in the return profile on a Haynesville well at 330 from 350 to 370 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 250. But again, if you're going to grow volumes, you're going to need to capture the growth from areas that require a higher price. So 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. And then you have to think about how long you're going to need those volumes for. So that 5.6 Bcf a day comes online by the end by 2026. By '27 to '28, 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 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 '27 to -- end of '27, beginning of '28 time frame. And you're going to see really then a question about, what does domestic demand for gas look like 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 going to need that growth. And I think understanding how long we're going to 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 U.S. You don't want to grow for a season, you want to grow for something that is durable over several years.

So what do you need to see in the S&D before you make that decision to add rigs?

Yes. You need to see that, 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, that incremental demand is there and the supply that you're going to 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.

I want to 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 actually are going to have another market that we can access other than the U.S. 2 Bs a day on our current market is 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 Bs a day exist in the system now they're going to 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 plants because they let production slide during COVID. So it was easy capital-efficient production to add. We added 0.5 B. That's it. And that was in the best possible year. So it's going to 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 cost. So our breakeven prices are $1.50. You often get the question, "Well, 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 shipped 1.27 Bs premium markets in the U.S. So our average realized price is over $3 or almost $3.19 during '24 and the worst possible pricing. Where can Canada go from an LNG complex on the West Coast? Well, LNG Canada Phase 2 is an easy one. I think that becomes simpler with the new government that we're going to 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 is a project that we're helping push along, which is the old PETRONAS pipeline route, which is another 1.7 Bs a day. So we could very quickly go from 2 to 6.5 Bs a day on the West Coast. We also think, in the long term, given that our 2 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 going to be a draw on Canadian gas to get more gas out to service that 25 to 30 Bcf a day complex that's going to be on the Gulf Coast. So yes, 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 to 2030 outlook really before you even get in to electrify everything and data centers and so forth, it's very exciting.

Fair enough. I'm going to hand it over to Ati now.

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?

Yes. 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 0 exports in 2016 to about 15 Bcf a day, growing north of 20 here very soon, which will be 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% to 20% would be a good target for us with how much gas we would like to see price at 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 going to 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 of 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. 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. And just to think about how we position ourselves for that growth, but then also the volatility that's going to come along with that growth, is something that we really spend most of our strategic planning efforts around 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 market that'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. We're certainly cooler. At the ASO, which is our grid, there's 9 projects that are in the queue that would equate to about 1 Bcf a day. So a decent amount of demand growth. And then there's a whole series of behind-the-fence projects that could happen as well. We can provide a good offering as we 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 4 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 the golden age of gas, if you like, is finally upon us. I found that slide. I make lots of slides. So I found when I made called the golden age of gas and thought, "Wow, this looks good." Unfortunately, I made it 9 years ago.

You were ahead of your time.

Yes. Maybe we're finally here.

Maybe, Gordon, 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?

So the Western Haynesville, we started looking at that play in '18, '19 and leased up what we felt like was a really core position that was going to be the most opportunistic to develop. It is exploration, so you have to be thoughtful about how you approach that. And we have a partnership with Black Stone Minerals. And so we've been drilling deeper, high-pressure temperature wells. We've drilled about 450 wells in the Haynesville today. So we have a lot of experience. So we've drilled 10 wells there. It's about 16.5 total vertical depth, and pressure is around 11,000 pounds. And what we're seeing is the wells are not declining. They haven't turned over yet. And so these are 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 in the subsurface and make sure we optimize that development accordingly. 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 want to be thoughtful and prudent. We've got a significant amount of inventory. And so we're able to allocate a reasonable amount of capital over there and do that in 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?

Well, you're always understanding assets, right? We're still understanding every asset we have and continuing to refine and optimize. And that's what industry has shown to be very good at. And so I think we're very excited and confident in the asset. But again, we don't want to go fast forward 3 years and say, "Oh my gosh, why did we put 4 rigs on that asset?" And the way we developed it was not as well as we would have today. And then we're always going to have that look back and say, "Hey, I would have done something different." But these are expensive wells worth $23 million to $25 million. So it's a lot of capital, and you want to be thoughtful about the way you approach that.

Got it. Mike, maybe if I can come back to you on your infrastructure -- your 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?

Yes. We love infrastructure, and we've built and owned our own infrastructure through -- all 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 $1.50 breakeven. 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 kind of feed on each other. And it's -- it just allows you to optimize free cash flow and make that much more money and then enhance your shareholder return proposition. So it's -- yes, multiple whole myriad of benefits that come from owning and operating your own infrastructure. And it will last for 60 years if you maintain it properly.

Right.

And this business will still be around in 60 years.

Right. Makes sense. Nick, maybe if I can come to you on -- 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?

Yes, 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. If you think about the synergies, it breaks down between drilling and completions relative to G&A now with that incremental $100 million 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 want to go out and get more. The incremental $100 million that we announced 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 brought 2 companies together. We've got 2 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 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 out of time. So thank you so much for taking the time and appreciate all the answers.

Thank you.