Good morning, ladies and gentlemen. Thank you for standing by. Welcome to Ovintiv's Midland Basin Acquisition conference call. As a reminder, today's call is being recorded. At this time, all participants are in a listen-only mode. Following the presentation, we will conduct a question-and-answer session. Members of the investment community will have the opportunity to ask questions and can join the queue at any time by pressing star one. For members of the media attending in a listen-only mode today, you may quote statements made by any of the Ovintiv representatives. However, members of the media who wish to quote others who are speaking on this call today, we advise you to contact those individuals directly to obtain their consent. Please be advised that this conference call may not be recorded or rebroadcast without the expressed consent of Ovintiv. I would now like to turn the conference over to Patti Posadowski from Investor Relations. Please go ahead, Patti. Thank you, and welcome everyone. This call is being webcast, and the slides are available on our website at ovintiv.com. Please take note of the advisory regarding forward-looking statements at the beginning of our slides and in our disclosure documents filed on SEDAR and EDGAR. Following the prepared remarks, we will be available to take your questions. Please limit your time to one question and one follow-up. I will now turn the call over to our President and CEO, Brendan McCracken. Thanks, Patti. Good morning, everybody, and thank you for joining us. We're excited to talk to you today about two compelling transactions that are set to create exceptional value for our shareholders. The combined transaction is immediately accretive by double digits per share on all financial metrics, including a big boost to shareholder cash returns. More on that shortly. We add significant inventory depth, increase our oil mix, and create a big enhancement to our capital efficiency and lower our cash costs. These deals are priced right, and importantly, we maintain our investment grade-rated balance sheet. First off, we have entered into an agreement to acquire the core Midland Basin assets of Piedra Resources, Black Swan Oil and Gas, and Petrolegacy Energy from EnCap Investments in a cash and stock transaction valued at $4.275 billion. Second, we have entered into a separate agreement to sell all our assets in the Bakken to Grayson Mill Bakken, LLC, a portfolio company of EnCap, for $825 million. Collectively, these transactions are highly aligned with our durable return strategy. In conjunction with the transactions this morning, we also announced a 20% per share increase to our base dividend. This is now the second increase to our base dividend in the last 12 months. Our Permian acquisition checks all the boxes with our durable return strategy, which has us focused on delivering superior returns on invested capital and superior cash returns to our shareholders. With shale hitting the middle innings, the asset we are acquiring is a rarity. The blocked up acreage sits in the core of the northern Midland Basin, and importantly, is 85% undeveloped. That is an ideal setup for our team. This transaction will add 1,050 net 10,000 foot equivalent well locations to our Permian inventory and approximately 65,000 net acres. The land position offsets our current acreage in Martin County, and with our deep understanding of the resource here and our ability to leverage our existing operations, we are best positioned to unlock future value. At close, we estimate these assets will be producing about 75,000 BOEs per day, and this will nearly double our existing Permian oil and condensate production. We are acquiring approximately 800 premium return locations and approximately 250 high potential upside locations. We're very excited about the value embedded in the new Midland Basin assets. We remained very disciplined in our approach to evaluating the purchase price, and as a result, it is attractively valued at a 2.8x EBITDA multiple at strip, with a free cash flow yield of nearly 20%. Note that all of the EBITDA and accretion numbers in our documentation this morning, as well as in our discussion, are based on the Friday, March 30th strip price, which on a next 12-month basis was $71 at the time. After the events of the weekend, that strip has bumped up, approximately 10% or up by $7. The transaction is immediately accretive on all key metrics, including cash flow per share, free cash flow per share, shareholder returns, NAV per share, and inventory life. We expect accretion to drive a greater than 25% increase to cash returns per share over the next 12 months following the close of the acquisition, with a greater than 40% increase in 2024. The deal will also enhance our CapEx efficiency and margins. To illustrate the magnitude of the CapEx efficiency gain, consider our recent February guide for 2023, where we expect to produce 170,000 barrels a day of crude and condensate for a midpoint CapEx of about $2.3 billion across the company. In 2024 pro forma, we now expect to produce more than 200,000 barrels of oil and condensate per day for that same $2.3 billion of CapEx at the midpoint. That is an increase of 30,000 barrels of oil and condensate next year for no additional CapEx at the midpoint, a remarkable increase in capital efficiency that translates directly to higher returns to our shareholders. We will do it while also reducing company-wide operating and transportation and processing costs by 3%-5% compared to what we were expecting back in February. Following the transactions, we will operate a more streamlined portfolio in four premier basins at scale, with each asset holding more than 125,000 net acres and more than 10 years of premium drilling inventory. Critically, we will retain ample liquidity and will maintain a strong balance sheet. Our pro forma liquidity will total about $3.5 billion, including our unsecured credit facility. Let me provide some additional context around how these transactions allow us to achieve our key financial targets. Using strip pricing, again from Friday, we expect our next 12 months free cash flow per share to increase by more than 30%, with a corresponding 25% increase in expected shareholder returns per share. In 2024, we expect our free cash flow per share to grow by more than 45%, with a corresponding 40% increase to shareholder returns, again on a per share basis. An additional priority for us is maintaining our investment-grade rating. We anticipate all four rating agencies to maintain our investment-grade rating and stable outlook. At close, we expect our pro forma leverage ratio to be approximately 1.4 x. We are reaffirming our mid-cycle leverage target of 1x. With our go-forward business, this translates to approximately $4 billion of debt at mid-cycle prices. We remain committed to our proven shareholder return framework and will continue to distribute at least 50% of post-dividend free cash flow to our shareholders, with the remaining 50% going to the balance sheet. The incremental free cash flow we expect to generate as a result of this transaction will drive deleveraging. I'd now like to describe the assets we've acquired in more detail. The acquisition is highly complementary to what we do best, multi-bench cube development, using a customized pad and well completion approach. The acreage is contiguous and proximate to our existing land position. While the acreage is 85% undeveloped with lots of running room, it is also well delineated across the position, with more than 180 horizontal wells producing on the acreage today. The acquired assets immediately compete for capital across our program, and we expect to run 2 rigs-3 rigs on the acquired acreage. Well performance across the acquired acreage is consistent with our 2021 and 2022 and anticipated 2023 Permian programs pre-transaction. While the performance of the acquired assets stands on its own, we see several potential upsides. We will apply full-scale cube development across the portfolio. We'll be deploying our proven optimization techniques around completion design, simulfrac, stage architecture, artificial lift, and accelerated cycle times. We'll also be optimizing development and logistics across our combined Permian position versus the three separate operating companies that were planning and executing work on each of their individual footprints previously. One significant built-in structural benefit will be reduced offset frac hits, as we significantly reduce activity across the position relative to the prior management. Our confidence in future well performance is borne out in strong offset well results, both our own and other operators. We've zoomed in on this slide to show the Northern Midland Basin portion of the basin and have highlighted our Sugar Loaf pad that we completed in North Martin County early in the first quarter of this year. This was a seven-well pad with wells in the Middle Spraberry Jo Mill, the Upper Lower Spraberry, and the Dean. The results from the Sugar Loaf have been excellent, including an average of 1,500 barrels per day IP30, and our best ever Jo Mill results. The wells have now been on stream for 70 days and have continued to outperform. We expect to see similar results as we develop the acquired acreage. The full industry average performance in the North Midland Basin, which you can see as the star on the right, is just below the Permian well performance we expect from our existing position in 2023. This industry average does not include our proven cube development and optimization techniques. As I mentioned before, these are great wells today, and we see upside from here. Our confidence in Northern Midland is not limited to Sugar Loaf. This slide shows the 19 pad results on and nearby the acquired acreage. The results are a powerful demonstration of the underlying rock quality that we've acquired. The average oil IP30 is more than 1,100 barrels per day on a normalized 10,000 foot lateral, and there are multiple pads in this data set with IP30s above 1,300 barrels a day of oil, including our Sugar Loaf. This is not a small sample set. It includes more than 130 wells across those 19 pads and across multiple different operators. It includes wells we've drilled ourselves, wells we are acquiring as part of the transaction that we've announced today, and wells drilled by others in the industry. It's also important to highlight the strong performance we're seeing in Andrews County. It has perhaps been a bit below the radar for public investors. The well results from Andrews since 2021 are every bit as strong as Martin County. We are excited about putting our innovation and expertise to work on that acreage as well as the new Martin position. We've acquired a unique, largely undeveloped asset in the heart of the play, with proven results that complements our existing asset and is primed for the type of multi-zone cube development that we've been doing in the Permian for nearly a decade. Along with today's announcement, we've updated our 2023 full year guidance, assuming a June 30th close for both transactions. Pro forma, we are guiding to a 12% increase in 2023 full year oil and condensate production compared to our February guide. Next year, we expect to produce more than 200,000 barrels of oil and condensate per day on a capital range of $2.1 billion-$2.5 billion. To put that into context, next year we will spend roughly the same amount of capital at the midpoint as we guided to for 2023 pre-transaction, that capital will produce an additional 30,000 barrels a day of oil and condensate. In addition to increased capital efficiency, the transaction will also drive increased cash cost savings. We are divesting a relatively higher operating and TMP cost asset in the Bakken and adding a relatively lower cost asset in the Permian. As such, we anticipate company level savings of 3%-5% for OpEx and TMP at closing. We will update the market on our progress and expectations with our first quarter results in May. We expect a shift from a pro forma 10-rig program in the Permian to a 5-rig program by the fourth quarter of 2023, with that transition happening in the third quarter and partially dependent on the exact close date. While our focus today is on the Midland acquisition, we also wanted to provide an update on our first quarter pre-transaction performance. We continue to deliver strong operational performance across the portfolio, with preliminary estimated first quarter oil and condensate volumes averaging 165,000 barrels per day and total production of 510,000 BOEs per day. These strong results are underpinned by strong performance from our existing Permian assets. We're also narrowing and lowering the range on our first quarter capital guidance to $610 million-$620 million. We continued to be active in the bolt-on activity during the quarter, adding approximately $200 million of premium oil inventory additions. While we think opportunistic bolt-ons continue to make good business sense, with this acquisition, we have significantly extended our inventory across the company and in the heart of the Permian. We've raised the bar for additional bolt-ons, and we expect minimal spending going forward while we focus on cash returns and debt reduction. To sum it up, the transactions we announced today further advance our durable return strategy. The combination is strongly accretive, boosts shareholder returns, increases our Permian inventory depth, ups our oil mix, delivers a big capital efficiency gain, lowers our cash costs, and maintains our investment grade rated balance sheet strength. At closing, we will retain anchor positions in four basins. The Permian and the Montney, a quick cycle time multi-product option in the Anadarko, and a high margin, high return emerging oil play in the Uinta. Operator, we're now ready to open the line up for Q&A. Thank you, sir. Ladies and gentlemen, we will now begin the question-and-answer session. If you would like to join the question queue, please press star followed by 1 on your telephone keypad. If your question has been answered and you would like to withdraw from the queue, please press star followed by 2. One moment, please, for your first question. Your first question will come from Neal Dingman at Truist Securities. Please go ahead. Monel, congrats, Brendan. Nice timing. My question is more for when you look at sort of your estimates for 2024. I'm just wondering, I know it is early, but is that assuming sort of the same, the rig count, all-allocated rig count for each of the areas, I guess? You know, based on, I guess my question around that would be, once you see the results from obviously this acquisition combined with your existing Permian, does that assume any change in sort of region allocation going into 2024? So far, Neal, we haven't made any of those optimizations. It's obviously early to be precise about 2024, but we felt it was important to give some shape for how we were seeing the year set up with the pro forma asset. There's certainly room for us to look to do that. You know, the Permian capital allocation is gonna be significantly higher than it's been for us. You know, it's gonna be more in the range of up to 60% of capital going into the Permian in 2024, which just reflects the increased scale of the asset there for us now. We'll look to do those. It'll then depend a little bit on the macro setup, 'cause the beauty of our portfolio today is we've got high return options that can target, you know, black oil or gas or NGL or a combination of both. I think that'll probably drive that choice. To this point, Neil, it doesn't reflect a change in the broad capital allocation other than that higher Permian piece. It could see even more upside there. What about just lastly on the net operating cost change for... As you take the Bakken out, I think Bakken may be getting a little bit more pricey sometime to operate with the Permian in. Could you just talk about how you all are thinking about net operating costs? I can get Greg to talk about that a little bit here too, but you're right. The 3%-5% that we've steered you to here today is just that's just the structural unplugging of the Bakken, which is a little higher TMP and LOE, and then plugging in the new barrels from the acquired assets. That doesn't reflect any real optimization beyond that, which, you know, I think we would expect because we're gonna be able to run that now almost 180,000 acres through things like our centralized control room and automation. Greg, I don't know if there's anything you wanna add there. No, I think the only thing I'd add is, you know, these assets that we're acquiring are really well plumbed. All the oil and water is on pipe, which allows us to have a very efficient operation, not unlike our existing Permian assets. We feel like we're just taking a Bakken asset that was very well run, but with just a little higher cost structure and replacing it with a lower cost Permian asset, which will bring down the total company. Thank you, guys. Nice job. Thanks, Neil. Your next question comes from Arun Jayaram at JP Morgan. Please go ahead. Good morning. Brendan, I wanted to maybe go through the updated guide. In order to hit, call it the midpoint of your 2023 guide, assuming the asset closes, transaction closes at midyear, we estimate that your crude and condensate production would need to average around 215,000 BOE/day, and you're pointing to a 2024 production outlook just over 200,000 BOE/day. Can you walk us through some of the puts and takes on that volume guide? Arun. Glad you took us there. The prior management teams there, the three operating companies, have collectively been running seven rigs. Oil production has been on a ramp through the first half of 2023, and that ramp will be continuing as we complete out those pads that have already been drilled. Then, of course, we'll be pulling the rigs back from just if I talk just the rigs on the acquired assets from seven down to five total for us, effectively pro forma from 10 to five. Really what you're seeing there is there'll be a peaking of production in the third and fourth quarter this year, we're gonna run it at a more stable rate for free cash flow and returns going forward. That's what we built into the case here is sort of allowing that steeper decline to occur, and that's all baked into the valuation and baked into the guidance that we're providing and the accretion numbers that we're providing today. But we're not gonna try and, you know, hold it at that peak level. We'll let some of that steam come out of the growth there. Super helpful. My second question is, at the midpoint, you know, you are guiding to call it a 16% decline in year-over-year CapEx. It sounds like some of the CapEx decline will be just by running, you know, fewer rigs in the Permian. I wanted to ask a little bit about infrastructure spend on acquired assets, mostly undeveloped, as well as maybe some updated thoughts on cash tax guidance, Corey, for 2024 with the acquisition and the divestiture of the Bakken assets. Yeah. Corey's excited to take the tax one. Let's do the infrastructure one first here. You know, Greg will have some detailed thoughts, but I would just say the, you know, one of the things that we're impressed with by the EnCap teams is they were very thoughtful about the infrastructure build-out. I mean, they've got some pretty sophisticated stuff there. They've got a sand mine. They've got great water infrastructure. So a lot of that capital has been invested already, so we're able to come in and not have to allocate dollars into that build-out. Greg, why don't you just expand a little bit on the plumbing that exists there today? Yeah. As I mentioned before, you know, all of these wells are already plumbed for water disposal. I really wouldn't see a significantly different infrastructure spend than what we're gonna see on our existing assets. You know, we will have that third quarter of this year and into the fourth quarter as we kind of ramp down the program. You'll see spending being higher, but I would expect that our go-forward costs out here are gonna be similar to what we have been seeing historically on our asset. There's also an opportunity for us to reduce those costs further through some of the synergies we're gonna have by having a larger footprint. We'll be running five rigs and two spreads out here over the 180,000 acres that we'll then be operating. A great opportunity for us to actually reduce overall spend as we optimize the asset. Corey, do you wanna take the tax one? Yeah, sure. Arun, just on the tax piece. I think you're asking about 2024, but just a reminder, I guess, for everybody on 2023, there'll be no impact to our cash tax estimate for 2023 on this, for the transaction. All of that is driven by the gas realizations in Canada. Again, as we watch that'll drive our 2023 number. We'll give a more precise 2024 forecast here, but we'll still be subject to the AMT in 2024, so there's really nothing shifting that profile from this transaction. Great. Thanks a lot, gentlemen. Yeah. Thanks, Arun. Your next question comes from Gabe Daoud at TD Cowen. Please go ahead. Hi, guys. This is Frank Dion for Gabe. What spacing assumptions underpin the location that you disclosed as part of the transaction? Yeah. Greg, why don't you take that one? Yeah, for sure. I guess I'd start with, you know, we have a long history of development in this part of the Northern Midland Basin. We've been operating out here for almost a decade. We've got, you know, an extensive public data set as well as our private data set from our wells that we've drilled, as well as what we've traded for. And then of course, the data set provided by the seller. We use that information along with core data. They did a great job of acquiring information on their assets, core data engineering studies. We used all of that to come up with a very specific well-by-well development plan. Maybe just to summarize that at a high level, the way we were thinking about it is, really if you take the 65,000 acres, that's 85% undeveloped, you take that remaining acreage, we're highly confident that we'll be able to develop three benches in each of the areas. If you think about that, three benches at six wells per DSU or roughly 880 acre spacing, that'll get you to our base number of premium locations. You know, where will those wells be? It'll vary across the position, but think about it as likely a Wolfcamp A, a Lower Spraberry or Dean, and then a Jo Mill layer in each of the areas. When we take it up to the upside case, you know, as we say in the material or noted in the materials, you know, up to six zones have been co-developed out here. We'll have the three base zones that we'll expect. You know, we're assuming that 1 more zone could work across the entire position, and that'll vary again by where we're located. Think of that as a Wolfcamp B, a Wolfcamp C. The Klein is doing very well in the area, as well as the Middle Spraberry up more shallow. We have a lot of different ways we can get to the upside. I would even say that we probably got upside on top of the upside as we get in and really start developing the acreage to its fullest extent. Just to kind of recap that. Three zones need to work at six wells per DSU or roughly 880 spacing for the base case, and then one more zone for the upside case is what we're underwriting. Great, thanks. As a follow-up, how do you guys anticipate the transaction changing your corporate PDP decline rate? Yeah, Brian. It'll bump up just a bit in the near term here because, you know, as I mentioned earlier, the ramp that the assets have been on do imply a higher decline than we currently have in our Permian and in the rest of the company. We've kinda today see our corporate decline pre-transaction in the low thirties, and we think it'll bump up into the mid-thirties pro forma. As we hold the asset at a lower growth or flat, then that'll moderate back in line with the rest of our Permian and the rest of the company. You know, a little bit higher in the short term, but not a huge step change. Great. Thanks. Thank you. Your next question comes from Doug Leggate of Bank of America. Please go ahead. Thanks. Good morning, everyone. Brendan, I think you might have just answered my question, but the moving from 7 rigs - 2 rigs in the acquired assets, what does that do to the production profile? Is the intent to hold it flat? Yeah. Doug, that's how we've modeled it here. You know, obviously, we're making projections now 2024 and beyond. You know, lots of water to come under the bridge to decide what's the right value choice for the asset that far out. The way we've modeled it for the purposes of the accretion math and the guidance here is to just hold it flat, which is consistent with how we've been running the portfolio pre-transaction as well. Just to be clear, that's flat at the current production number, or do you expect it to decline into a sort of, you know, lower, stable case? Yeah. What we've done for now, and remember, we're just at announcement today, so there's some time to give you some more detailed guidance once we get to close. For now, the way we've approached it is that greater than 200 level. Right. We've got options. We certainly could hold it flat at a higher level than that, which would then, you know, maybe push that capital a little higher in the range that we've provided. You know, early days on nailing down some of those details, but we've got some options we can work with. We won't hold it. I don't anticipate that we would try and hold it at the level that it will be at at closing. But we certainly can hold it a little. Yeah. Yeah. Right. Right. Okay. Thank you. Then I guess just for a little bit of color, I'm always curious when these things get announced. Can you offer a little bit of background as to how the transaction came about? Was this a beauty contest or was that the right negotiation? Any color you can offer, I'll leave it there. Thanks. Yeah. You know, Doug, like, won't comment on EnCap's process. You know, that's their decision to decide if they wanna talk about it or not. I mean, we ran a fulsome process on the Bakken. I can tell you that. And their bid was the best bid to go with there. You know, this is. You know, we've been very active in the Midland Basin. You know, we did over 90 transactions, albeit at a much smaller scale in 2022. We know the market very well. We certainly have a great understanding of the resource in the basin and in particular in this area. And, you know, I think in a lot of ways, are the operator best suited to create value on the acreage. Terrific. Thanks, guys. Yeah. Thanks, Doug. Your next question comes from Neil Mehta at Goldman Sachs. Please go ahead. Yeah. Good morning, team. Brendan, I wanted to kick off on slide 18, the return of capital framework. If you could just provide your perspective and update on how we should think about the cadence of cash coming back to shareholders and what this all does for both the buyback and the dividend. Yeah, no, thanks for taking us there, Neil. You know, we're committed to maintaining the capital allocation framework that we've now been following for almost two years. That is very much still in place. What we really like about the transaction here is that it's a big boost to the per share cash returns that'll be coming back to investors in that framework. To date, you know, as you're well aware, but I think everybody else probably is too, we've been operating in that 50/50 mode, where we've been returning 50% of our free cash flow post dividend to shareholders and then retaining the other 50%. Probably the piece that pivots in the near term here is that our focus on that retained free cash flow is gonna shift to debt reduction. We'll certainly be also focused on maintaining that, 50% that is going to shareholders. Again, our view of this has always been that's a minimum. We've got the option to increase that, as we go forward in time here. Really the way we look at that every quarter is as a value-based decision. What's the right capital allocation choice there to create value for our shareholders? Is it gonna be more debt reduction, or is it gonna be more buybacks? That'll be something we revisit as we go through the quarters. You know, today, you know, for the coming quarter, you should expect it to stay at the 50/50. Just to be clear, while you are taking that debt back to the $4 billion, you'll still be able to execute the buyback program at the least 50% level? That's right, Neil. you know, really the way I've been describing it is, you know, I don't think it's the choice of that buyback level is not linked necessarily to a debt number or to a leverage number. It's a value choice that we should make every quarter as we go. Okay. The follow-up, Brendan, is just as we think about scale, this clearly gets you bigger in the Permian. Should we think about the company continuing to grow through M&A as we look into 2024? Or is this the transaction that kinda fills the gaps that you were looking to fill? Well, Neil, you know, look, this is one of these never say never moments, so I have to be a little cautious there. You know, look, we've made incredible progress on increasing the inventory that we have in the company, and that's been a key priority for us with this durable return strategy. You know, if you think about what drives durable returns in our business, you know, it's really three big things. It's access to premium resource. It's the ability to convert that resource really efficiently to free cash flow and returns. It's capital discipline to make sure capital's not leaking away into unproductive uses. You know, this really is a demonstration of all three of those pieces. You know, if we focus at the moment here just on the inventory piece, this combined with the bolt-on work that we did through 2022 really is a game changer for us and solidly, you know, concretes our position with a deep premium inventory to drive durable returns for a long time. You know, I, I think it's, you know, a big accomplishment and, you know, look, never say never, but I think we're gonna be pretty focused on execution and debt reduction and cash returns in the near term. Okay. Thank you. Your next question comes from Nitin Kumar at Mizuho. Please go ahead. Hi. Good morning, everyone, and thanks for taking the question. Maybe following up a little bit on the capital efficiency questions earlier. Right now, the oil mix is about 80% in the new assets, but what is your long-term assumption for that, especially as you reduce activity in the new assets? Yeah, no, it's a great point, Nitin. Glad you made it. Because of the growth ramp and because of the resource in place there, it's a really high oil cut, so quite a bit higher than our existing Permian position. You know, as that base position matures and of course, as we slow growth and flatten it out, we do expect that GOR is gonna climb. That's just the nature of the Permian everywhere, but inclusive of the Northern Midland Basin. That'll rise. We haven't provided any specific guidance on, you know, how that percentage will evolve, it won't be snap acting. It'll erode, you know, by several% a year type of thing over the next several years. Great. And then maybe following on Neil's question, is there any blackout period for buybacks associated with the transaction? And if so, I mean, for your share buyback program. If so, do you focus on variable dividends in the short term on that 50% return? Yeah. I'll let Corey talk about the blackouts here. We're in our customary blackout period right now for our quarter. Once we release that, we'll be through that. Obviously we'll have to prepare our pro forma. The sooner we can do that, we'll be clear of the blackout, which will be kinda early May, is our current expectation. I think the short answer, Nitin, is we think we can work around those blackouts and maintain the buyback program. Great. Maybe quickly, did you add any hedges associated with this? Yeah. Nitin, the way to think about that is, you know, our hedging philosophy is intact here, continuing to view hedging as an insurance policy and a way to protect free cash flow after the base dividend at low prices. Obviously pro forma, we'd be adding considerable additional volumes here, you should expect us to be adding hedges to top up for that volume and probably even go a little higher than the 25% level that we had previously anchored on for 2023. Great. Thanks, guys. Yeah. No, thank you. Your next question comes from Roger Read at Wells Fargo. Please go ahead. Yeah, thanks. Good morning. Congrats on the transaction here. Just to kind of following up some of the other questions. You mentioned the current operators had some well interference issues, and obviously you're looking to overcome those as you cut the rigs and so forth. I was just curious how comfortable you are with the due diligence on that you have a real good grasp of exactly what's been going on for them and how you'll approach it, you know, once you have the properties under your wing. Roger, no, appreciate the question. The due diligence has been extensive here. Our ability to interact with the three management teams and to have access to the private data has been robust and thorough and has been ongoing. We feel real comfortable with our understanding, not only of offset frac interference, but also just every aspect of the well performance and the geology and resource that we're working with. The offset frac interference is just structural. If you're running seven r igs on a 65,000 foot footprint and you're managing it in three separate management teams, it just is really hard to stay out of your own way. That is just gonna naturally be a lot easier for us going forward. It's a pretty robust, high confidence interpretation. No, it makes sense. Thanks. Then just two kinda quick follow-ups. One, your thoughts on the timing and potential interest rates of the debt that you're gonna issue. Then I just have one other. Sure. I'll let Corey take the interest rate piece. Hey, Roger. Corey here. For the takeout financing, the way to look at this is just to remember that, you know, the new run rate for our mid-cycle EBITDA has gone from effectively $3 billion- $4 billion with the acquisition, less the Bakken transaction. When we think about financing that net cash remainder, you know, there'll be a portion of that we see as kind of a longer term debt, whether that's 10 years or 10+ years. The remainder we'll structure inside that and try and give ourselves optionality for repayment, without big upfront cost. If you look at kind of the way we're trading today, it's relatively flat across the curve. Just from a timing perspective, once we're out with our Q1 and we can get the pro formas done, that'll be our window to start to do more permanent takeout financing. Okay, great. I would be surprised if there isn't a fixed agreement here, but I was just curious with this move in crude you mentioned at the beginning. There's no way to any of the terms change with crude moving up, down, sideways, whatever, no caps, collars, et cetera? That's right, Roger. There's none of those features in the deal. Okay, great. Thank you. Thank you. Your next question comes from Harry Mateer at Barclays. Please go ahead. Hi, good morning. You know, wonder if you can talk a little bit about the debt reduction pace that you're anticipating, 'cause it looks like at closing your gross debt goes up to, you know, around $6 billion or maybe just a shade under, which implies about $2 billion of debt reduction to get down to that $4 billion run rate that Corey was just talking about. You know, I guess if I look at the financing mix pie chart on slide seven, you know, looks like long-term debt around $1 billion or so, temporary debt at, you know, call it one and a quarter billion dollars. I mean, how do I bridge that $2 billion debt reduction number to what looks like a temporary debt slice of the financing mix that's quite a bit less than that? Yeah. I'll let Corey cover that one. Harry, just if you think about the $1 billion that we've got in kind of that long-term tranche there, part of the permanent takeout is, you know, as you're well aware, we don't have an on the run 10. We're pretty illiquid, part of doing this is we'd have to set a new benchmark as part of all that. You know, when we look at repaying debt, you know, we would consider our existing debt stock as well as having some new shorter term set up. We do have a smallish CP balance currently as well. We'll combine all of that just to give ourselves the flexibility to repay it. If you think about, just rule of thumb, if you take an $80 WTI price and whether you run $3 or $4 into the gas, that'll take us around two years to get down to that $4 billion level. Great. That's very helpful. Thank you. Thanks, sir. At this time, we have completed the question and answer session, so I will turn the conference back to Ms. Posadowski. Please go ahead. Thank you everyone for joining us today. The call is now complete. Ladies and gentlemen, this does conclude the conference call for this morning. We would like to thank you all for participating and ask you to please disconnect your lines.