Okay, we're going to get started with our next presenting company. We've got Expand Energy, which is the largest U.S. natural gas company, one of the few growth stocks in the E&P sector right now. Presenting on behalf of Expand Energy is the COO, Josh Viets. Josh? Yeah, thanks for that introduction. It's great to be with you here today. Today I'm going to provide some insights into our assets and our capital allocation strategy, which, of course, is being informed by a very constructive outlook for the natural gas commodity. And we're doing that while we continue to maintain focus on our consumers and our shareholders. Expand Energy was formed just this past October. It came together through the combination of Southwestern Energy and Chesapeake Energy. Both companies have had long histories across the U.S. shale gas industry, and we also had very complementary assets. And when you put together two companies that have highly complementary assets, that translates to synergies. Through the transaction, in the first year alone, we expect to realize roughly $400 million of annual synergies, which equates to roughly 80% of the total synergy target that we have through the transaction. Together, we have more than 20 years of inventory, which offers durability and longevity to our cash flows. Our portfolio is also differentiated through its market connectivity, which offers access to premium markets that are largely created through U.S. LNG exports. In addition, we maintain an investment-grade balance sheet. Our leverage ratio is expected to be less than one on a net debt-to-EBITDA basis, and we also have a robust capital return framework. As a company, we fundamentally believe that the world is short of energy, and it's especially short of affordable, reliable, and low-carbon energy. We stand ready to address this challenge, meeting the needs of all our stakeholders through the delivery of responsibly sourced, low-carbon intensity natural gas to consumers while delivering differentiated returns to our shareholders. The natural gas markets are quickly evolving. One of the areas that we see this most is within the U.S. LNG exports. In 2024, the U.S. exported roughly 15 Bcf a day. It's expected by the end of 2027 that that will increase by an incremental 11 Bcf a day. And just to put that into perspective, today, as a country, we produce between 100 and 105 Bcf a day, so this represents roughly a 10% increase in demand. We, of course, are well positioned to take advantage of this with our strategic location of our assets. That's primarily the Haynesville Shale. In addition to that, we are also anticipating a material growth story coming from the power demand sector as well. This is largely coming through the expansion of data centers, hyperscalers, as well as just the general society's push for additional electrification. I would say the timing and the absolute quantum of this is a little bit uncertain. I would just say we do expect that we'll continue to see increases in efficiency of processing chips, the models that are running in the background, as well as just the overall growth and penetration of renewable energy sources. So exactly how much natural gas plays into this overall power demand story, I would say, again, remains uncertain. In addition to that, infrastructure is going to be required. And so if you think about generating power, you have to be able to drill wells, you have to be able to connect that gas to markets, you have to have power plants to generate the electricity, and then you have to have transmission systems and transmission in order to get it into the data center. So all of that has regulatory hurdles that have to be overcome. In addition to that, you also have to just think about the general adoption of AI-driven technologies. And so with all that kind of as a backdrop, the range for natural gas-driven demand from power generation remains quite wide at around 3 Bcf-10 Bcf a day. But despite how power demand growth plays out, the combination of LNG exports and power demand creates a really unique opportunity for Expand Energy, and we believe that we're extremely well positioned to capitalize on this. Expand Energy is differentiated by our scaled net production by more than 7 Bcf a day, inventory depth of more than 20 years, and assets located in the three most prominent U.S. shale gas basins. These three assets are highly complementary for each other. They provide us with capital allocation flexibility and provide access to differentiated markets. I would say this is one of the unique advantages that we offer as opposed to some of our pure-play Appalachia or pure-play Haynesville players. Each of the business units that we produce gas from are also, again, highly complementary, but have different production and operational characteristics that we have to take into account. In Northeast Appalachia, so this is located in Northeast Pennsylvania, primarily in Bradford County, I would say this could probably be characterized as the most prolific dry shale gas reservoir that you'll find in North America. It has an incredibly high resource density, so in terms of gas in place per acre. It has high productivity per well. And so it's not uncommon that we'll have wells that come online and over the first 30 days produce over 50 million a day. In fact, after 15 years of production, just in the past six months, we had a well that came on and produced around 87 million cu ft a day in the first 30 days of its life. So again, a lot of great rock still left to develop. It's also on the low end of the cost curve. So to drill and complete wells in this part of the country, it takes around $750 per lateral foot to develop the asset. The reservoir produces essentially 100% methane with very few impurities in the gas stream, which helps to keep treating costs low. And so ultimately, when you sum all this up, this translates to low breakevens, healthy margins, and low reinvestment rates that really helps for the company create a level of cash flow durability through cycles. In Southwest Appalachia, so located in the Panhandle of West Virginia and Eastern Ohio, this asset provides us exposure to liquids. We produce just under 100,000 barrels a day of condensate and NGL combined. It also really benefits from the ability to drill incredibly long laterals. So in this part of the country, we're able to drill up to five miles of lateral length, which is just an unbelievable feat, almost 25,000 ft of lateral when you're talking about total well lengths of over 30,000 ft. So if you think about being able to take that type of technology and expand that elsewhere, all of a sudden you start having opportunities to unlock new rock and/or just simply enhance returns of the wells that we're drilling today. In the Haynesville, so this is located in Northwest Louisiana, it's a little bit different in terms of where it sits on the cost curve. It is considered to be the marginal supplier of natural gas, and that's largely driven by its cost structure. It's deep. It's going to be over 10,000 ft of true vertical depth. It's hot. We often are dealing with bottom hole temperatures that are approaching 400 degrees Fahrenheit, which makes for a pretty challenging drilling environment. In addition to that, we also produce small quantities of CO2 and H2S, which adds to treating cost. Well costs here are essentially double what we find in the Appalachia region, somewhere between $1,400-$1,500 per foot. The resource density is high here. It also carries significant overpressure in the reservoir. It's not uncommon to bring wells online that are producing between 20 and 30 million cu ft a day. The initial pressures on these wells at surface is approaching 10,000 psi. And so these wells are able to maintain these production rates for up to about a year in duration, which obviously helps to support the overall economics of the asset. But the real strategic advantage of the Haynesville, of course, is its geographic location. Its proximity to the U.S. Gulf Coast provides a distinct advantage that other assets simply cannot realize. So when I talk about the assets, scale, depth of inventory, access to premium markets, and ability to grow all serve as differentiators for our assets. But we also pride ourselves on having the highest quality acreage positions, so in the sweet spots of the play, while also being the best operator. And what this chart demonstrates is it's showing our capital efficiency. And as we're showing it here, capital efficiency is defined by the well CapEx divided by the first 12 months of cumulative production. And so the data sets that we show across each of the three operating areas is reflecting the average capital efficiency relative to our peers over the last five years. And so what it demonstrates, again, is our peer-leading acreage position with peer-leading operations delivering the most capital-efficient operations and the highest returns of the wells that we're drilling. So access to premium markets where demand is growing is ultimately what will create incremental value from our producing assets. Our contracted transportation offers us flow assurance, diversification, and commercial flexibility. With over 7 Bcf a day of marketed production and proximity to the fastest growing demand source, this, again, serves as a differentiator for our company. 75% of the gas that we'll produce will be flowing into what we consider to be strategically advantaged markets. We have further aspirations to expand the capability of our marketing organization in reaching into new markets both internationally and domestically, with the ultimate goal of enhancing the value of the natural gas that we produce from our wells. You would have seen an announcement just in the last couple of weeks that we had another key hire within our organization, adding Executive Vice President Dan Turco to our team to, again, help lead this transformational effort. When we think about our business, one of the most fundamental questions we have to answer is at what level of production do we want to run the company at? As we think about this question, you have to think about, well, what are we trying to optimize? We think the most simple way at which we think about this question is we simply want to optimize around free cash flow. To help address this and how do we solve this problem, the first thing you have to do is you have to take a view on a mid-cycle price. In order to do this, the way we like to think about it is we're going to look out over the next two to three years. We think this two to three-year look is very appropriate when you think about the cycle time and the payback periods of the investments that we're making. We've taken a view that mid-cycle pricing falls within the range of $3.50-$4. We think that this, again, is a prudent approach. And some might argue, well, gosh, when I look at the forward curve, it's something well above $4 today. And of course, that is true. But one of the things that we do have to remember is when we see gas prices above $4, the belief is that you do start to activate marginal supply of natural gas. So supply will come in and will likely moderate the overall price of the product that we're producing. So with that view of $3.50-$4, what this helps us to do then is to look at different sensitivities of production levels of the company relative to the capital that we invest. And so as we look to optimize our business, again, within the context of this mid-cycle price view, we believe 7.5 Bcf a day at roughly $3 billion in CapEx is what's optimal for us going forward. Now, we also know that these views on mid-cycle price can shift, and we know that it will shift, and so we'll continue to be responsive to the underlying fundamentals as we see consumers' needs start to deviate and economic trends change, so volatility, I think, across the natural gas industry and really just the E&P business is pretty well documented. The volatility that we've seen just in the last two years, I think, demonstrates this quite well. If we go back to the late summer of 2022, we were looking at gas prices that were over $8 an Mcf. We lived through a pretty tough year in 2024, where oftentimes through the course of the year, we saw gas prices well below $2. So I would say despite the constructive outlook in the macro, we do anticipate this volatility will remain in the markets both domestically and internationally going forward. And this is largely due to the fact that the U.S. markets and the international markets are simply only becoming more interconnected. So we do believe that the ability to flex volumes and capital will continue to play a role in how we run the business. But ultimately, what the question is, how much do we want to flex our production around some targeted level of volume? Traditionally, what we've seen in our industry is when we see strong dislocations within the market, an operator will simply go out and stop drilling wells. And though that is an option, and again, many operators have done that through the past, we don't think that's what makes sense for us going forward. One of the problems that you run into is the simple fact that as you drop rigs, you're effectively destroying productive capacity, and when you think about the time period it takes to plan, manage logistics, drill the wells, bring them online, that overall cycle time could be 12-18 months, and so if you think about the typical commodity price cycles that we have, by the time you start adding your rigs back and restoring production, you're likely peaking your production activity at the peak, and that may be even at the end of a constructive commodity price cycle, so the goal that we have is to better align our production with price, and the way we think about that is through the management of productive capacity. So in 2024, one of the things that we did in order to, again, better align price and production is we simply stopped turning in-line wells. So we continued to run a relatively modest amount of rigs. In this case, it was 14-15 rigs throughout 2024. And during that time, we would drill, sometimes we would complete, and we'd simply not turn in-line wells. So throughout the course of 2024, we built up a productive capacity of roughly a Bcf a day. This included roughly 80 deferred turn-in-lines. In addition to that, we didn't complete all our wells either. So we exited the year with between 50 and 60 drilled but not completed wells, oftentimes referred to as DUCs. And as we got into the end of the year, we started to see market fundamentals improve. We saw more weather-induced demand. We started to see stronger pulls from U.S. LNG, and we started to see stronger prices. So between December of this past year and March, we will introduce roughly 600 million cu ft a day into the markets to better align with the markets when it's very clear that gas is needed. Now, to do this, it does take financial strength. And what's one of the things as a company that we offer? Our balance sheet is simply in a great spot for us today. And we are absolutely committed to maintaining a solid financial framework based on discipline and ensuring this balance sheet remains strong through cycles. Again, shortly after the merger closed, we were upgraded to investment-grade status by two of the three agencies, and we're already benefiting from this IG status with a very successful bond offering at the end of last year. Post-merger closed, we had established a target of around $1.1 billion in debt reduction, and I would say we're well on our way to achieving that target. Each year, as part of our capital return framework, we'll establish a net reduction target to further strengthen our balance sheet going forward. So when we talk about our capital return framework, we'd like to talk about it as being fairly formulaic. But one of the things that we do like about this program is that it offers some flexibility to us about how we return equity to shareholders. So the framework is broken down into three tranches. A base dividend remains our top priority and is considered sacrosanct, paying out at $2.30 per share. And next is our net debt reduction target, which for 2025 is pegged at $500 million. And it will be reset each year based upon kind of our financial outlook as well as the macro outlook for the commodity. In tranche three, 25% of this will be returned as net debt, with the remaining 75% provided to shareholders in either the form of a variable dividend or a share repurchase, where we currently carry a $1 billion authorization for buybacks. So historically, the upstream oil and gas industry has done a pretty poor job of allocating capital. We're focused on production growth over free cash flow generation and shareholder returns. Now, there's been a pretty clear shift in this over the last four years, with the industry returning roughly $400 billion of free cash flow during this period of time. I would just say that the leadership team at Expand Energy definitely backs this strategic shift, demonstrating our financial results and maintaining a rigid capital return framework. Over the last four years, we've generated around $4 billion of free cash flow, returning roughly 90% of this to shareholders. In 2025, it is expected that we'll generate around $1.6 billion in free cash flow, which equates to around a 6.5% yield at last week's share price. So we believe that the world will continue to demand low carbon energy, and we remain committed to ensuring that the needs for all of our stakeholders are met. We take great pride in the stewardship of our assets. Protecting our employees, contractors, the environment, while supporting our communities is simply considered a license to operate. Our safety results, measured by a total recordable incident rate, are peer-leading over the last three years. We've spent more than $30 million on pneumatic device replacement since 2021, and we'll continue to make every effort to abate operational emissions through more robust engineering and operational practices. Our methane intensity is on the leading edge of the industry at less than 0.02%, which is a full order of magnitude lower than the international oil and gas producers. Our responsibly sourced gas certification is absolutely a priority for us, and we remain committed to reaching our net zero target by 2035, so just in closing, I would just say the world is short of energy, and the call on natural gas from the U.S. LNG exports and growth in the U.S. power demand is evidence of this. We believe our connected portfolio with access to premium markets, our flexible operations supported by a strong balance sheet, along with our commitment to shareholders and the communities that we serve, clearly puts us in a position to thrive in the years to come. Thank you. Well, I mean, first of all, I would just reiterate that where we see the most material near-term demand growth is in LNG, of course. But we do see the power markets definitely developing. I would say historically, power producers have been a little bit reluctant to sign up to any type of fixed-term agreement. It's just a simple fact that there's so much gas on the grid. Why take on that type of a liability? And so we think that dynamic will likely change in the coming years, I think, as there's more and more demand, especially as you think about the southeastern part of the United States, where you have such a large demand pool coming from one physical location along the U.S. Gulf Coast, so we think it will happen. I think it's going to be hard, and I think it's going to take a little bit of time for the counterparty in terms of whether it's an IPP or a utility to really wrap their heads around what does a long-term fixed-price agreement mean to them. I think my answer would be, I hope so. But I'm not sure how optimistic I am. And what you have to, it will, yeah. And so what you have to remember is you have a regulatory process that could be managed at a county or a parish level, or at a state level, or at a federal level. So all of those bodies of government have to be taken into consideration and have to be working in concert with one another. Also, in certain parts of the country, landowner rights are a real issue that have to be dealt with. But you also have to. Landowner rights, yeah. Landowner basically says, "I have the right. You don't have the right to build a pipeline across my land. I don't own minerals, and I just simply don't want to deal with you." So that has to be consideration. The other point is just the judicial system. So it's one thing to be able to have regulatory rules, and then it's the next thing for those to be maybe showing up in a court of law to be challenged by others. So I still think there are hurdles to overcome. But I would just say I think there's some positive momentum behind this, where I think as Americans, if we get priced out of something, our behaviors start to change and become a little bit more tolerant. Well, I think that's why we love owning the Haynesville asset, is it's industry-friendly. We can build new pipes. In fact, we have over a Bcf a day of new infrastructure coming in place to get down into the Gillis Hub just in the next six to eight months. And so we think owning assets that are diversified and in areas that, in this case, can grow is a real strategic advantage for the company. And it's just going to be different from the pure-play Appalachia players who will have a harder time getting infrastructure built out. There's a lot of talk with the Constitution Pipeline right now up in the Northeast that has some real hurdles to overcome. But we're going to remain optimistic, and we want to be a part of that conversation, and we want to see it happen. Yeah. I think the most likely path is in basin demand is going to create the greatest potential source that would allow the basin to grow in some level. Moving gas across state lines is just incredibly challenging because of the regulatory and the judicial system that we operate in. But if you can build a demand source proximal to your asset, that has some real merits. And I know that's definitely something that we talk a lot about, but again, I think is the most likely direction that you would originate new demand. Yeah, yeah, for sure. And so we're going to spend roughly $3 billion this year. When we rolled out our plan last week, what we talked about is a base plan of around $2.7 billion with an incremental $300 million that we're referring to in this productive capacity that will help support our 2026 outlook. That incremental $300 million is back half-weighted. And we think that makes sense and to just simply create some option value for us heading into 2026, which, if the market doesn't show up, we've proven the ability to be disciplined and sit on that volume if we need to. But we also think it's setting us up in a pretty constructive environment to be able to take advantage of strong pricing, but more importantly, simply providing gas when the markets say gas is needed. Please join me in thanking Josh. He'll be available in the breakout room.