Good evening and welcome to Antero Resources and Antero Midstream Corporate Update Call. At this time, all participants are in a listen-only mode. A question-and-answer session will follow the formal presentation. If anyone should require operator assistance during the conference, please press star zero on your telephone keypad. Please note this conference is being recorded. I will now turn the conference over to Justin Agnew, CFO for Antero Midstream. Please proceed. Thank you for joining us for a call to discuss Antero's strategic transactions announced earlier today. We'll start by providing an overview of the transactions, and then we'll open it up for Q&A. I would also like to direct you to the homepage of our website at www.anteroresources.com and www.anteromidstream.com, where we have provided a separate investor presentation that will be reviewed during today's call. Today's call may contain certain non-GAAP financial measures. Please refer to our press release for important disclosures regarding such measures. Joining me on the call today are Michael Kennedy, CEO and President, and Brendan Krueger, CFO of Antero Resources. With that, I'll turn the call over to Mike. Thank you, Justin. Good morning, everyone. I'll start on slide number three titled Strategic Transaction Strength in AR and AM. Earlier this morning, we announced that Antero is acquiring West Virginia Marcellus assets and divesting non-core Ohio Utica assets. On the acquisition, AR will acquire the upstream assets for $2.8 billion, and AM will acquire the midstream assets for $1.1 billion. On the divestiture, AR is divesting the upstream assets for $800 million, and AM is divesting the midstream assets for $400 million. The acquired assets include 385,000 net acres and approximately 850 million a day of production. The assets include over 400 undeveloped locations with high net royalty interest while also benefiting from average lateral lengths of over 20,000 ft. Now let's move on to slide number four titled Acquisition Rationale. Today's acquisition is a hand-in-glove fit with our legacy footprint. The assets add over 400 drilling locations in the Marcellus core that will immediately compete for capital, approximately 75% of which are liquids rich. The existing PDP production provides us with dry gas optionality for local power generation and data centers. Given the significant acreage overlap, we estimate there are approximately $950 million of synergies that are achievable only by Antero. These include tangible D&C cost savings, development planning, and marketing synergies. This transaction also highlights the benefits of the AR-AM structure with AM acquiring the midstream business and providing additional operational benefits. The acquisition reduces our cost structure by approximately $0.25 per Mcfe and increases margins by $0.15-$0.20 per Mcfe. Lastly, this transaction is highly accretive to our operating cash flow, free cash flow, and NAV per share metrics. Now let's move on to slide number five titled Fully Financed Strategic Acquisition, which summarizes the transaction financing for the $2.8 billion purchase price for AR. First, we expect to generate approximately $500 million of free cash flow between now and closing at the start of the second quarter of 2026, taking advantage of near-term winter pricing. The divestiture of our non-core Utica upstream assets for $800 million pre- funds another significant portion of the acquisition. The remaining financing of the acquisition will be a three-year Term Loan A, which we expect to pay off with hedged free cash flow from the acquired assets. We have already locked in NYMEX and basis hedges for substantially all of the acquired production in 2026 and 2027. That results in attractive margins of over $2 per Mcfe and a visible pathway to debt reduction. Importantly, we are essentially funding this acquisition through divestiture proceeds and free cash flow from the acquired business itself. That means all of the expected free cash flow from our base business and potential synergies from this transaction will be available for further debt reduction and return of capital to shareholders. We will continue to be opportunistic on our share buyback strategy, and this transaction enhances this ability with more stable and increased cash flows. Turning to slide number six, let's look at Antero's pro forma production and capital outlook. Starting with the production table at the top of the slide, we began 2025 with a maintenance production program targeting approximately 3.4 Bcfe per day. Following the acquisitions executed during the third quarter of 2025, the production target increased to approximately 3.5 Bcfe per day. Today, after adjusting for the Utica divestiture and the Marcellus acquisition, a 2026 maintenance program would be approximately 4.2 Bcfe per day. This level could increase further if we elect to run the program without a drilling partnership in 2026 and/or if we add any growth capital to our 2026 development plan due to local dry gas demand. As you can see in the far right bar, any increase in capital in 2026 would drive roughly a one-to-one increase in net production for 2027. So if we invested an incremental $100 million, we would grow net production by roughly $100 million per day. On the capital side, we have stated for the last several years that our maintenance capital target is approximately $700 million. Including our third quarter 2025 acquisitions and the transaction announced today, the pro forma maintenance capital target would increase to approximately $900 million. As depicted on the far right of the slide, we have further flexibility to increase our net production by electing to move forward without a drilling partnership and/or adding growth capital that would bring our total capital anywhere from $1.1-$1.2 billion. Before turning the call over to Brendan for more details on the synergies I mentioned earlier, I wanted to provide one specific example of development plan optimization synergies laid out on slide number seven. We selected this pad as it's already been publicly filed for a pooling application in West Virginia and is slated for development in the 2026/2027 timeframe. The map on the left shows the pad development pre-acquisition for both Antero and HG, while the map on the right shows the pro forma development of the same pad. Instead of capital invested to build two pad sites and drill 10 wells with average lateral lengths of 9,500 ft, this leasehold can now be developed from one pad with five long laterals averaging nearly 20,000 ft. From just this pad alone, the PV-10 value increases $30 million, and the IRR increases from 47%-81%. This is just one example of many all along the southern border of our legacy acreage. This overlapping acreage position provides clear, easily attainable synergies that can only be recognized by Antero. I'll now turn it over to our CFO, Brendan Krueger, for his comments. Thanks, Mike. I'll begin my comments on slide number eight. This slide highlights the identified synergies of approximately $950 million on a PV-10 basis over the next 10 years. On the capital side, there are over $500 million of estimated drilling and completion cost and development optimization synergies. Due to HG's assets directly offsetting Antero's legacy position, there are substantial overlapping leasehold positions that, when combined, result in longer laterals and reduced civil spend from pad and road capital savings. These development plan savings are compounded by a faster and more efficient drilling and completion based on a large, contiguous, and long lateral development program. In addition, we expect significant D&C cost savings from scale, including reduced sand, fuel, and chemical costs, to name a few. Next, we expect to integrate HG's production into AR's firm transportation portfolio. This will allow us to fill legacy unutilized capacity and optimize the FT portfolio to drive better price realizations and lower our net marketing expenses, improving both the top and bottom lines by $140 million on a 10-year cumulative PV-10 basis. Justin will touch on it in a minute, but AR also expects substantial water handling savings as a result of AM investing capital to connect the assets to AM's water system. This is expected to result in a reduction in completion gaps and associated water handling expenses. Lastly, by using the Utica proceeds to immediately purchase another asset, we realize tax benefits structuring it as a like-kind exchange, which, combined with other smaller synergies, results in another $185 million in savings. In total, these result in PV-10 savings of $950 million over 10 years, or over 30% of the total transaction value, highlighting the value creation that this transaction delivers for our shareholders. Now let's move to slide number nine titled Conservative Underwriting with Compelling Valuation. Mike already highlighted that this acquisition is over 30% accretive to operating cash flow, free cash flow, and NAV per share. Looking more closely at the purchase price, the acquisition was completed at less than the combined value of the PDP and the work-in-process wells. This conservative underwriting provides material upside from synergies and undeveloped locations, essentially adding highly economic inventory and no incremental costs. Next, let's discuss the balance sheet on slide 10. As we have proven over the last five years, we are committed to maintaining low absolute debt levels. We expect our investment grade ratings to be reaffirmed by the rating agencies. Based on the current commodity strip, we also expect to be below one times leverage in 2026. To protect our free cash flow outlook, we assumed HG's hedge book and have approximately 90% of HG's production hedged over the next two years. Further, financing the transaction with a three-year term loan highlights the high confidence we have in the acquired asset free cash flow profile over the next several years, which is supported by these hedges. I'll echo Mike's comments from the outset that we are extremely excited about the outlook for the Antero family. The highly accretive nature of these transactions will drive substantial enhancement to our free cash flow outlook and position. Thanks, Brendan. As Mike mentioned, this acquisition highlights the complementary structure of AM acquiring assets alongside AR that fits a traditional risk and fixed fee return profile of a midstream company. As you can see on the map on slide 11, the acquired midstream assets consist of approximately 50 mi of east-west gathering pipelines in dark green adjacent to Antero Midstream's existing assets. This close proximity allows us to integrate the gathering assets almost immediately. The transaction also includes strategic water pipelines and storage assets that we plan to integrate into AM's water system throughout 2026. In combination, the capital required to integrate the acquired assets with AM's legacy assets is only $25 million. In addition, the trunk lines of the gathering and water systems are fully built out, requiring ongoing capital of only $25 million per year at a maintenance capital level. Moving to synergies and savings on the bottom left, we have identified over $100 million of capital avoidance synergies on a PV-10 basis. This includes approximately 30 mi of avoided gathering pipeline build, 20 mi of water pipeline build, and other savings that correspond to the same land and civil synergies identified at AR. In addition, AM expects to utilize bonus depreciation immediately on the acquired assets, deferring approximately $50 million of cash taxes on a PV-10 basis net of the impact of the Utica divestiture. In summary, today's acquisition provides scale at an attractive 7.5x acquisition multiple over the next three years, significant synergies, low capital intensity, and an increasing EBITDA profile. In tandem with the Utica divestiture, which was divested at a multiple over 11x for a declining asset, today's strategic announcements result in a combined multiple of 6.5x excluding synergies. I'll finish my comments on slide number 12 titled Transaction Strength and Outlook at AM. Today's acquisition high-grades Antero Midstream's asset base and can be debt financed given our strong balance sheet. Looking ahead, we expect leverage to decline below our 3.0x target in 2026. This is a testament to our just-in-time organic growth strategy supplemented by several immediately accretive bolt-on transactions. The peer-leading return on invested capital positions us well for additional debt re duction and return of capital to shareholders. I will now turn the call back to Mike for closing remarks. Thanks, Justin. I'll close on slide number 13 titled HG Acquisition Accelerates Antero's Strategic Initiatives. On our third quarter 2025 conference call, we detailed our key strategic initiatives going forward. Today's transactions make significant progress toward all of the goals we highlighted. It expands our core Marcellus position in West Virginia by adding 385,000 net acres and over 400 drilling locations. This extends our core inventory life by approximately five years, assuming a maintenance capital development plan. The acquired acreage increases our exposure to dry gas, strengthening our position for future dry gas development. We added hedges to lock in attractive free cash flow yields, providing high confidence in our free cash flow outlook over the next several years. In addition, this transaction meaningfully reduces cash costs by approximately 10% and expands margins, lowering our peer-leading break-even price. Lastly, it highlights the benefits of Antero's integrated structure with Antero Midstream. With that, I will now turn the call over to the operator for questions. Thank you. We will now be conducting a question-and-answer session. If you would like to ask a question, please press star one on your telephone keypad. A confirmation tone will indicate your line is in the question queue. You may press star two if you would like to remove your question from the queue, and for participants using speaker equipment, it may be necessary to pick up your handset before pressing the star keys. Our first question is from Kevin MacCurdy with Pickering Energy Partners. Please proceed. Hey, good morning, and congratulations on the deal. I guess I wanted to start off maybe on slide six. You present an option for a growth plan, and I wonder if maybe you can just talk about the puts and takes on that decision and what would make you kind of pursue growth into 2027? Yeah, Kevin, we talked on the third quarter call. We just bought our first dry gas pad over a decade, plan to get a pad and kind of a proof of concept. And really, it generated what we thought were a lot of calls from local demand, gas demand from data centers, from power generators, and kind of opened up a lot of opportunities or just kind of put us in play, more squarely in play for the West Virginia local demand. So if that materializes over this time, you could see us continuing that plan or that rig in that area and further increasing our dry gas there for the local uses. Great. Appreciate that. And maybe can you talk a little bit about the development plan on this asset? You mentioned $200 million of capital in 2026. Are we right to think that's probably like 15-20 wells, and will you be immediately shifting the focus to the wet gas, or does that require some prep work? Yes. It's about 20 wells, a little on the high end, but yes, it's about approximately 0.75 of a rig line. But just think of us now as a three-rig company instead of a two-rig company. And initially, on the dry gas, a little bit more focus just because that's where they're drilling right now and the pads they have ready, but they do have some liquids pads as well, so it'll be a mix of both. Appreciate it. Thank you. Yep. Our next question is from Leo Mariani with Roth Capital Partners. Please proceed. Yeah, good morning. Wanted to ask a bit more about the synergies here. I see you guys have kind of put that in here on sort of a PV basis. Not sure how you're kind of discounting that, but could you give us kind of an annual number? And I know you guys are saying that the deal should close around April 1st. Just in anything on kind of the timeline of the synergies, do you expect those to start to be relatively immediate post-closing? Yeah. I'll use my one example on the slide, and then I'll kick it over to Brendan for a little bit more detail, Leo, but this is the one, the southern and kind of southwest portion of our acreage is overlapped with HG, just basically hand in glove, like the title suggested on that slide, and so there is immediate synergies. We wanted to highlight that one pad. It's the 1223 North pad for HG and our Little Buck pad going south because that was a public pooling application that really showed that the synergies that would come from having one developer of this acreage versus two, so that is immediate, so that was $30 million of capital, at least in the 2026, 2027 timeframe, but that type of example exists throughout the southern portion of our acreage because it borders HG. But with that, I'll kind of kick it over to Brendan for a little more detail. Yeah, thanks, Mike. Yeah. I think, Leo, just to talk about details a little bit more, talking about D&C savings, I think we hit on a few of these from savings. We expect about $10 million-$15 million a year. The chemicals and fuel, same story in that $10 million-$15 million a year. So when you look at overall D&C savings, we expect to be in the $40 million-$50 million a year. Now, we expect all of this to kind of ramp up over time, but on the D&C cost, $40 million-$50 million a year. On the development planning, as we get into the undeveloped portion of this beyond the work-in-process wells, so call it in that 2028, 2029 time period, we expect another call it $50 million-$60 million a year as a result of development planning optimization. And then as we look at more of what I'll call the EBITDAX income synergies, so if you're looking at that page eight on the EBITDAX income related, the marketing is really driven by the ability to flow some of the gas and HG's flowing today into unutilized transport that we have. That's about $15 million a year. So that we would suspect to be able to integrate fairly quickly here. The water handling, that's a result of the flowback water that we have. If you looked at our forecast prior to HG, that flowback water, we would have had to truck some of that to far distances. So that incremental trucking costs will now be reduced because we will be able to reuse with that third rig that Mike mentioned. So that's what's driving the water blending. Then the tax, just due to the like-kind exchange, I think we mentioned in the prepared remarks, that will defer about $85 million of taxes as a result of that like-kind exchange. Then there's a handful of just other smaller synergies in that bucket. If we brought all that together, it's about, call it, $50 million a year, first year, $100 million a year by year two, year three, and then $150 million a year beyond that time period. I know long-winded answer, but hopefully that gives you a little more color around the synergies we see here. No, that was great color for sure. Just wanted to also ask about the buyback. You referenced this in your prepared comments that you guys would continue to be opportunistic. It certainly makes sense. But, as you've also noted, the leverage is going up some in the near term, but a lot of that's going to be hedged free cash flow and pay off debt. So, is there any shift at all in thinking on the buyback where you might be a little bit more conservative as you're paying off debt in the next couple of years? Can you provide a little bit more color around your thinking around that? No, no change to that. We'll continue to be opportunistic. That's how we've always talked about it, Leo, wherever the opportunity is. In fact, I think this probably enhances our ability because we always want to try to be countercyclical on this. So adding this portion of hedged free cash flow and the substantial amount that we added really adds to our kind of stable free cash flow profile on a go-forward basis, whereas in the past, it was always subject to commodity prices. So when the buyback opportunities would be, you'd have low commodity prices and you wouldn't have that free cash flow, whereas now we've kind of locked in these $2+ margins on this 775 million-800 million a day of gas for 2026 and 2027 hedged back to the basis as well. We'll feel a lot more confident to be countercyclical and opportunistic on the buybacks. We'll just continue and be, like I mentioned, opportunistic on what's best, either to reduce debt or buyback shares over the next couple of years. Okay. Thank you. Yep. Our next question is from Jacob Roberts with TPH. Please proceed. Morning, guys. Morning. I was wondering if you could speak to the base decline assumptions on the acquired assets, and not sure if I missed it. If you could break down the hydrocarbon mix of that asset and where you see that mix corporately in 2026, please. It's fairly similar to AR, but I believe it's 10,000-12,000 barrels today of NGLs, and the rest is dry gas. So you can see on our hedge profile, we hedged of the 850, we hedged 775 over the next two years. So remaining is liquids, and then it goes a bit higher after that as you begin to develop the more liquids acreage of HG. And then the decline is similar to ours. They face a lot more back pressure right now than we do. So there's a lot of ability for compression optimization that we should be able to manage that. But our decline rate's in the mid to low 20s%. Great. Thank you. And maybe pulling on that thread a little bit, looking at slide 17 on the GP&T cost reductions, is that predicated on a certain dry gas percentage? And to your point, if you ship more liquids weighted in maybe a 2027+ timeframe, is that number moving higher? It wouldn't move a tad higher, but it's not material. This is pretty indicative of where it'll be for the next five years. Perfect. Appreciate the time, guys. Yep. Our next question is from Josh Silverstein with UBS. Please proceed. Hey, David. Thanks. Good morning, guys. Can you just talk about how the added production may help you in potential power or some sort of industrial supply discussions you may be having from the basin? Yeah. We didn't highlight this in this slide, but now I think we produce over half the total production in West Virginia, which is getting a lot of investment or a lot of looks for investment based on their microgrid bill and their kind of push to get more and more natural gas demand locally in the state. So I think we are the number one operator by far, around 35%-40% of the total state. HG was number four. In combination, now we'll be more than half of the total production of the West Virginia state. So if there's any investment there, we will be definitely a strong counterparty for that. Got it, and then I was just curious on the $0.15-$0.20 margin reduction. This is mostly on the GP&T side. Can you just talk about how much of this is HG selling in- basin versus having capacity charges? And I know you mentioned there's maybe some shift towards more dry gas drilling, which reduces some of the, I guess, processing fees there. Yeah. No, it's all in basin. But the way to think about it, we were kind of going off a $4 strip. We hedged the basis $0.80 back. You're at $3.20, but then you're at 1,100 BTU gas. That gets you in the $3.50 range, and then the liquids uplift gets you to $4. So you get $4 kind of realization all in and a $1.50 all-in cost. So you got a $2.50 margin on these HG volumes, and that's how you get that $0.15-$0.20 margin improvement. Got it. Thanks, guys. Yep. Our next question is from Kalei Akamine with Bank of America. Please proceed. Hey, good morning, guys. My question is on acreage delineation. And kind of looking at the well results, HG's activity is concentrated into one pocket of a large 385 net acre position that you guys call out. What is the expiration risk that you associate with the 400 drilling locations here? And is the acreage all held? Yeah. Over 90% HBP, but they also have two wells, the Riddle well and the Goodnight well on the far western portion of their acreage, which shows, I think, they're 1.3 Bcf per thousand without the liquids, and it's 1,300+ BTU. So those are terrific wells. And that's far out on their western portion of their acreage position. So the delineation is there along with our 1,500 wells. So feel really good about their acreage position and delineation of the wells, and it's all HBP. Thank you, Mike. For my follow-up, can you simply talk about their working interest and whether that changes throughout the position and what the royalty rates are? Yeah. That's another attractive profile. Very high working interest, but the NRIs, because it was a storage pool, is 85%-86% over the next five years while we're drilling from HG. So creative there. Sounds great. Thank you. Yep. Our next question is from Neil Mehta with Goldman Sachs. Please proceed. Yeah. Thank you. As part of this, Mike and team, you guys announced the divesting of some non-core Utica. And can you just talk about, are there other opportunities for non-core portfolio monetization as we think about you continuing to move south from the portfolio? Yeah. No, Neil, this is pretty much it. The Utica, like we mentioned in the material, is only at three wells in the next five years planned, and that's right now the English pad. So to divest a non-core asset that you weren't developing and to redeploy those proceeds into this asset where you'll actually run one rig and drill 20 wells per year, it's terrific. So that's pretty much all we got. We're now solely a West Virginia company with a highly contiguous, over 800,000 acres position running three rigs and producing 4.2 BCF a day. Thank you. Then can you just spend some time on slide seven? It does seem effectively you're doubling your lateral length here in the pro forma development profile. So just if you can unpack that for us and what it means for the business and any risks associated with approaching the pads this way too? No, our legacy program, we're able to do 13,000-14,000 ft. HG had the ability to basically have one row of midstream and drill north and south and perfectly optimize it to 20,000 ft going both north and south across that storage pool and their acreage in that southern acreage position. So we'll continue to do that. So we'll have one rig being able to obtain 20,000 ft laterals for our program, and the other two will be 13,000-14,000 ft laterals. Perfect. Thanks, team. Yep. Our next question is from [Subash Chandra with StoneX]. Please proceed. Yeah. Hi, guys. Does this acquisition change your C3+ production profile at all? A little bit. Yeah. I mean, we were at total liquids of 200,000 barrels a day and about 2.3 of gas. So it made up the 3.5. Now we'll be 215 of the liquids of the 4.2. So it goes from 35-ish% to 30%. Okay. Yeah. And I guess the BTU levels of the HG acreage, you're comparable? They are. BTU, yeah. The curves go across their acreages like it does ours. Okay. Got it. And just to clarify on the OPEX number, we will see a $0.15-$0.20 benefit to cash costs in the income statement? No, that's the margin enhancement. Actually, we have a slide out there with slide seven and then Page 17. Page 17 outlines that they're at $1.50. So in combination, we go down $0.25 on the cost structure from $2.68 to $2.43. And most of that's all in that GP&T. Okay. Yeah. I see it now. Okay. Yeah. Thank you. Thanks for that. Sure. Okay. Yeah. And I guess one last one. So I don't know if you want to comment on this, but what do you attribute to that variance in the multiple on the asset you sold, especially? Oh, I think they're going to grow it. I mean, it was a built-to-grow asset for them. We weren't going to develop it. We were focused on the Marcellus, but everything was there, the acreage, the infrastructure, and their Utica focus. So you had a company that was going to focus on the Utica and grow that asset, whereas we were focused on the Marcellus and we were going to grow that asset. Okay. Got it. All right. Congrats, guys. Sure. Our next question is from Betty Jiang with Barclays. Please proceed. Good morning. I have a broader question. Sorry about that. Maybe just on the M&A strategy in general. With this deal, it's one of the largest in recent memory for Antero. And before that is the PDP acquisition, which I understand is different, but certainly the company is getting more active on the M&A side. So do we see this as a strategy to lean more into M&A and seeing AR as a consolidator going forward? And where do you see opportunities around your acreage from here? No, but I think we just were capitalizing on opportunities that presented to us at the time. We are the liquids developer in the Marcellus. We are kind of the West Virginia oil and gas company as well. So when you look at a map of West Virginia with the liquids acreage, we should be developing that with the platform that we have. So we just took advantage of that. If there are further opportunities on that map in and around our West Virginia acreage position, we'll take a look at them. But I think these just came about at these times. Got it. Thanks. And then question on DrillCo or drilling JV decision into next year. I'm surprised you have not made that decision yet, just given the higher gas price. And it seems strategic to forgo that JV at this point. Just what's your rationale and the decision point around that? No, exactly that. I think it really speaks to the high quality of our asset, and there's no variability in our wells. So if someone looks at a drilling JV, they have high confidence in what it's going to deliver. So those decisions can be made on a very timely basis and very quick. It just speaks to the high-quality nature of our asset. We obviously can wait and hold that optionality for ourselves. And obviously, with today's transactions, I would assume we probably are not going to do one just with how strong we are and how strong the commodity prices are and the returns and our profile. I think you'll see us right now, all things else being equal, that we'll probably not pursue a drilling JV. Got it. That makes sense. Thanks. Yep. Our next question is from Ned Baramov with Wells Fargo. Please proceed. Hi, good morning, guys, and thanks for taking the questions. I guess, could you talk about how the gathering and compression fees for the HG acreage compare to those fees on the legacy acreage and whether there is a potential optimization angle for AR in its future development plans if there is a gathering and compression fee advantage in developing one acreage versus the other? No, they're the same. The only difference is HG has on-pad compression versus centralized compression for AR. So that's the only difference. You saw that in the 8-K. We did amend the agreements to allow for on-pad compression, but that's just for HG pads over the next couple of years. Got it. And then maybe can you share a bit more on the key sources of midstream annual synergies similar to how you laid out the upstream synergies in response to an earlier question? Yep. Ned, this is Justin. It's about 30 mi of avoided gathering pipeline and 20 mi of water pipeline. Essentially, shorter geographic builds either connecting future areas of development to their system versus ours or in specific areas where you have significant acreage overlap that might kind of touch down. You're essentially building one row of pads versus kind of two rows of pads drilling towards each other. So it's really all identifiable capital avoidance based on specific pipeline mileage. Understood. Thank you. Mm-hmm. Our next question is from David Deckelbaum with TD Cowen. Please proceed. Thanks for taking my questions. Congrats on the deal, guys. Thank you too. Mike, I'm curious. I know I'm hopping on a little late. I'm curious how this deal sort of impacts your outlook for land spend over the next several years. We should be at the same sort of absolute level, or you anticipate that there's going to be a lot more kind of leasing opportunities your way now with a substantially larger? No, I had it lower, David. This obviously adds significant acreage in that liquids area, which is the future liquids development of our company. And so now that we've acquired that, it should result in lower going forward in that area. We may still be active in maybe other areas, maybe a little more in the dry gas areas. So that $100 million kind of placeholder that we have each year is probably still a good number, but it's just a bigger enterprise. I appreciate that. And then maybe just on the marketing synergies, I know you all identified $140 million of 10-year savings related to marketing. I guess, is that included in there? Should we think about that as reallocating some of the acquired volumes from in basin? End End markets looks like they're at M2 and down south to some of the firm transportation portfolio that you have. Is that sort of the calculated arb that you have now? Yeah. There's a bit of that. So we had some just due to how we had structured our firm transport portfolio over the years. We had portions of our capacity that was unmatched, essentially, is what we call it. And so by integrating some of the production from HG that was just being sold locally, we can move it into that unutilized portion. And so number one, you won't have that unutilized portion, but you'll also get a pickup in price relative to what HG was selling at before. So that's essentially what it is, David. Thank you, guys. Thank you. Our next question is from Carlos Escalante with Wolfe Research. Please proceed. Hey, good morning, guys. So, incorporating the 90% of the hedging from HG into your 2026 portfolio, wondering how you plan to move forward with hedging as a whole on the gas side, considering now you have that moving part in your overall realizations. And if that should be something we consider you do more of in 2027 and beyond. Yeah. Good question, Carlos. Obviously, we've got a lot hedged in 2026, so I think we're pretty good there. 2027, when you look at that 3 BCF of gas we talked about, there's 775 plus the previous 100 we had. We have 875 kind of swapped in that $4 level. We've talked before about being 25% swaps and then 25% wide collars. So we're done probably with swaps for 2027, but you could see us add maybe 20% wide collars now like we did in 2026. Got it. Makes sense. And then as a quick follow-up, just looking at the type curves, comparing yours to HG's, you have much better productivity, but the yields look to be the same from an NGL and liquids perspective. Maybe you got a little more of that. Just wondering, what is the key difference in your completion style that you plan to implement outside of just lengthening and making your laterals longer? Yeah. The longer laterals really help the economics off of the NRIs. The net royalty interest we're talking about being in that 85%-86% versus our 82%-83% really kind of evens it out. And then when we look at their EURs, we're in the 1.8-1.9 BCF per thousand for them, HG, and we're more in the 2.0, so it's not terribly different. And then NRI and the longer laterals evens that out. So from an economic standpoint, very comparable. And that's why we mentioned it will compete heavily for capital in our development plan going forward. Thank you, guys. Yep. Thank you. There are no further questions at this time. I would like to turn the conference back over to management for closing remarks. Thank you, everybody, for joining today's conference call. Please feel free to reach out with any other follow-up questions. Thank you. This will conclude today's conference. You may disconnect at this time, and thank you for your participation.