It's my pleasure to introduce your host, Jennifer Martin Samuels, Vice President of Investor Relations and ESG Stewardship. Please go ahead, Jennifer. Thank you, Kevin. Good morning, everyone. I hope you're recovered from a festive Halloween. In today's call, we may reference the earnings release, IR presentation, or prepared remarks, all of which are posted to our website. Thank you for joining us this morning. To answer your questions today, we have our President and CEO, Herb Vogel, our CFO, Wade Pursell, and we are also joined this morning by Beth McDonald, our new Chief Operating Officer. Before we get started, I need to remind you that our discussion today may include forward-looking statements and discussion of non-GAAP measures. I direct you to the accompanying slide deck, earnings release, and risk factors section of our most recently filed 10-K, which describe risks associated with forward-looking statements that could cause actual results to differ. Also, please see the slide deck, appendix, and earnings release for definitions and reconciliations of non-GAAP measures to the most directly comparable GAAP measures and discussion of forward-looking non-GAAP measures. Also, look for our third quarter 10-Q filed this morning. With that, I will turn it over to Herb for brief opening commentary. Herb. Thank you, Jennifer. Good morning, and thank you for joining us. Again, we had an outstanding quarter underscored by excellent operational execution. The fourth quarter presents an exciting step change for SM Energy with the addition of the Uinta Basin. We welcome the Uinta team and community to SM. So with that, let's go ahead and get started with the Q&A. I'll turn it back to Kevin to start taking your questions. Kevin. Thank you. As a reminder, if you'd like to be placed into the question queue, please press star one on your telephone keypad. A confirmation tone will indicate your line is in the question queue. We ask you, please ask one question, one follow-up, then return to the queue. Our first question is coming from Gabe Daoud from TD Cowen, and your line is now live. Hey, thanks. Morning, guys. Thanks for the time. Let's hope that we can maybe start in Utah. Maybe you can help us quantify a couple of things. First is just the delay in volumes you alluded to, given less wells by the seller. Could you maybe quantify the impact to 4Q and then maybe give us a leading edge number as far as what current Utah production might be at this point? Yeah, Gabe, let me just step back a minute just on Utah, just so you guys all kind of level set this for you. So you know we got our basic FTC consent around August 22nd, and at that point, we were able to get full data from the operator. We were restricted before that. That allowed us to understand specific rig and completion plans, status of all the permits, where the facility construction stood, all those details. We've had about two months now to digest all that data and really to figure out how to optimize the forward plan, and that means applying a lot of the tools that we've developed over the many years for the unconventionals, and then how that optimal would juxtapose with the existing permits and plans. Then also, we are looking at how do we optimize with our existing two basin assets with Utah. So we're running a lot of alternate scenarios with different commodity price mixes as just our normal planning process and CapEx allocation. And so when we get to February, we'll be able to lay that out fully. And so I just want to just encourage people. You can understand you guys are forecasting a company performance. So definitely put less emphasis on the quarterly cadence. And I'll get to 4Q in a second. And we're really pleased with the new asset mix because we do see the ability to get even better capital efficiency, and we'll be able to generate more value with the three. So we're really excited about what we can do going forward. As to 4Q in particular, the key thing is that the current operator, XCL, they delayed six wells. Three of them are because of extending laterals from 10,000 to 15,000 feet. So not only does that mean they're turned in line a little bit later because it takes longer to execute, but there's also a longer shut-in of offset wells while you're fracking nearby. So that's really just how that 4Q is impacted. And then I just go back to what I just said for 2025. It'll be all of the above where we're really looking at optimizing the capital program for the year. That's a long-winded answer to your short question there, Oliver. Or Gabe. No, thanks. Thanks, Herb. That's helpful. Appreciate the color there. And then I guess just as a follow-up, you noted quarterly cadence shouldn't really be looked at all that much as you're still kind of finalizing plans for 2025. But if I look at 4 Q, CapEx of $330 million, that would imply about $1.3 billion annualized. And that's still on a higher rig count than what you guys hope to get to. So for 2025 CapEx, is it fair to say directionally you could be $1.3 or lower just given the plans to go from nine to six rigs? And I'll keep it there. Thanks, guys. Yeah, no, I would say, Gabe, we're really looking at what the right capital level is. So I wouldn't use a multiple of the 4Q CapEx as a way to look at that. We'll be looking at what the rig program is throughout the year, how many at each asset. So we've said in that $1.3-$1.4 range for next year, and we'll see what that actually comes down to when we get to February. It'll depend, again, on commodity prices. That's always the starting point for this too. Got it. Thanks, Herb. You bet. Thank you. Next question is coming from Leo Mariani from Roth MKM. Your line is now live. I just wanted to ask on the fourth quarter production guidance here. So, I mean, it looks to me like it's much wider than you guys normally have presented historically. I mean, you guys present a quarter. So can you kind of provide some color in terms of why the wide range of production in 4Q because the capital range is quite a bit tighter? Yeah, sure, Leo. We just took on the Utah assets. So we're going to be careful about how we forecast for the quarter. We've got it down to, in South Texas and Permian, it's like a fine-tuned piano. And then we added in Utah, and we've obviously got a larger error band on that since we just took over the assets. Okay. No, that makes sense. And then just with respect to the share buybacks, obviously, you guys did not do any in the third quarter. You just had some kind of language there, I guess, in the release and the prepared comments, which maybe suggested maybe these aren't all that likely kind of going forward to get to kind of one-time leverage, if I was sort of reading that right. So could you just kind of provide a little bit more color? Is that generally right? Should we not expect many? And maybe just in times of market weakness, maybe you'll step in as really the free cash flow goes to debt paydown? I think that's actually a pretty good summary. We're clearly prioritizing debt reduction right now and getting back to that 1.0x area. But I will acknowledge what you said as true. We very well may step in at different days and support the stock. We clearly like the stock price. I mean, that's certainly not part of the decision right now. It's just really more we think it's best for all stakeholders right now to get leverage back to that 1.0x area where we have a strong balance sheet, a lot of dry powder, flexibility, all those things. But very well may step in periodically between now and then. And Lee, I'll just remind you, we reloaded that buyback authorization with the board to end of 2027 for $500 million. So it's a healthy buyback that we can do over the three-year period. Yep. Okay. Thank you. Thank you. Thank you. Next question is coming from Scott Hanold from RBC Capital Markets. Your line is now live. Yeah, thanks. Good morning. If we could maybe touch on 2025 right now again, and I appreciate you're still in the planning phase, but could you give us some framework and context on how you think about this given some of the weakness we've seen in oil prices? How do you think about when you look at your asset bases, you obviously have three distinct basins. Which ones do you find most competitive as oil prices come down so there's more incentives to invest there? Yeah, Scott, this is pretty much normal and routine for us in how we go about this. So at this stage, so now in November, we're looking at multiple scenarios, and that means different capital allocation between the assets. We are forecasting and using multiple price scenarios, meaning different gas price decks, different oil price decks. And then we look forward that two to three-year period and we say, "Okay, with these scenarios, which optimizes free cash flow generation over that two to three-year period?" And then when we get to the end of January, we say, "Okay, what do we think the 2025 prices will be?" And then we lock in on that scenario that optimizes the free cash flow for that period of time. We have found this to be extremely effective. We've done it this way for, I think, four years now. So that's really how the process will run. And then when we report the full year 2024 results in February, we'll share that full plan. Yeah, I would just add, you mentioned the pullback in commodity prices. Just a reminder, all three of our assets have a significant amount of inventory at low breakevens. So actually, $70 oil is fantastic, I guess, is what I would say from a standpoint of returns for our assets. Yeah, that's a great point Wade makes because we have driven the portfolio to be able to generate those returns even in below mid-cycle pricing, and we're getting the benefits of that now. Understood. And then my next question is on the Klondike wells. Obviously, we've got some initial rates on those right now. And can you give us some color? You did comment in your prepared remarks that the productivity in the first 30 days seemed to exceed your initial acquisition economic parameters. Can you give us a little context? How do they look compared to some of your legacy Midland activity? Is it more in line with that overall? But just some color there. Thanks. Yeah, sure, Scott. So first of all, we're real pleased because the wells are kind of confirming our geologic model and that there's oil saturation in an area that's more a conventional place. So it's a sandstone. So these are really highly productive wells. And then there's variability in how much water is produced. But overall, the water-oil ratios are coming in as what we thought. And we have the ability to predict, based on where all the vertical wells are, where the high water will be versus lower water. So that allows us to map and steer where we put the wells. So that's turned out quite positive. In terms of productivity, if you compare to a full co-development where you've got one really good well and two wells that are lesser on average, these are very economic wells for us. And so we're happy with the result. And with what we saw in the first two wells and really the first eight wells, we said, "Well, let's put the rig back up there and drill six more." And so we're back up there now drilling those. Because it's one interval that we're doing there and there's no interference from others, there's less interaction with offset wells. So that's a positive as long as we space correctly and we believe we space correctly. Thank you. You bet. Thank you. As a reminder, that's star one to be placed into question queue. Our next question is coming from Neil Dingman from Truist Securities. Your line is now live. Morning, thanks for the time. My question maybe just fell on a little bit on the other. I'm curious for your sort of future Midland plans. You've had a lot of success, Klondike and other areas, obviously, that Sweetie Peck continues to do super well. I'm just wondering, kind of looking regionally and formationally next year, could we assume, and I know obviously you don't have detailed 2025 guide out yet, but I'm just wondering, would you assume the Midland plan would be relatively similar to this year just when you think about areas and formations you might tackle? Yeah, Neil, great question. I have not seen the specifics of what our Permian team's going to, where they're going to locate specific wells. But you're right, we have a little broader mix of opportunities between Klondike, the Woodford, Permian, obviously Sweetie Peck, and the Rockstar area. So we'll just know we'll be optimizing it. But what we keep in the back of our mind is the competitiveness with the other assets. So it has to be a good program, and it has to be designed as a good program. And that means the spacing selections, completion designs have to give us the good wells to compete with South Texas and Uinta. So it's kind of nice having three assets to compete against each other because it drives those returns. And people know when you get higher returns, you get more capital the following year. Great details. And then just second around the Uinta, maybe specifically around the marketing there. Just wondering if you move forward, you already like the Cube, and you seem to be doing a lot of things to likely boost and improve production there. I'm just wondering, what type of options do you all have when it comes to takeaway in order to maximize pricing going forward? Yeah, Neil, so there's a lot bigger playground than I ever anticipated when we got into this and started looking at it back in April. There's a lot of competitive sensitivities around what you do specifically. So we can't get into the details there, but I would just say that know that we will be optimizing to get the best netback we can through all this. The also surprising thing is just how much more attractive the waxy crude is to the refiners, given what their product slate optimizes. So we'll just be working that over time, and I think we'll get better and better as time goes on. Look forward to it. Thank you. Thanks. Thank you. Next question is coming from Michael Scialla from Stephens. Your line is now live. Thank you. Good morning, everybody. I want to go back to Klondike. You mentioned that some of the wells that are going to be coming on will be constrained due to the water infrastructure there. I guess, what are the plans to expand that, and what might be the timeframe there? Yeah, that's a great question, Mike. Yeah, we build facilities for optimizing over time rather than for peak rates. And what Wade always says is you basically don't build your church for Easter. So it's not efficient to build water handling facilities to peak rates. So the way we do it is we just basically produce the wells off our ESPs at certain rates, and then you bring on a number of wells, and you're going to be constrained a little bit on the production rate. And then you just wind up with a slower decline afterwards. So you don't get quite as high in IP, but you also get a slower decline. And value-wise, it's the right way to go because you spend less capital. So that's the story there. Okay, so there really won't be any. The infrastructure that you need is pretty much in place. We just should look for a little flatter declines, lower peak rates out of these newer wells as you go forward. Is that the bottom line? That's exactly right. Okay. And on the Utah properties, you mentioned you're paying a transition service agreement in the fourth quarter. I guess, how do you expect that to change going forward? And is the fourth quarter run rate for your G&A, is that a good run rate to look forward to for 2025 at this point? Yeah, Mike, so the transition services agreement started when we closed October 1st. And this is really just an agreement where there's a period of time where the XCL team continues to operate, and we get progressively more involved. We're more in the day-to-day decisions, and we would have been September 30th. And there's a pre-agreed what we pay them during that period of time. And then on January 1st, we take their employees who accepted our offers. And I'm pleased to say that 100% of their field employees did take our offers. So that's pretty smooth transition over there. So it's really just we're working together during this period of time. They're a really great team, so it works quite effectively. And then in terms of G&A, just what we will be seeing is we'll be seeing increased G&A as we allocate more people's time of the SM people over to Utah. But the run-rate change won't occur until January when we have it fully staffed up with the people we've hired from XCL. Yeah, Mike, just Wade, we're working the details, obviously, and we'll share that with you in the guidance. But if I were modeling right now, I think that's a pretty good starting point, that fourth quarter number, so. That's helpful. Appreciate it, guys. Thanks. Yeah. Thank you. Next question today is coming from Tim Rezvan from KeyBank Capital Markets. Your line is now live. Hey, good morning, folks. Lots of potential questions here, but I'll start in the Uinta. I thought it was interesting. Your first well results were from the Douglas Creek, which is not one of the three sort of standard de-risk zones. So obviously, maybe it's not 17, but it looks like it's greater than three, the number of productive intervals. So as you go forward in 2025, how do you think about the allocation between sort of development drilling in defined areas and then sort of step out to other areas? Yeah, a great question, Tim. And I really appreciate your recognizing the importance of that because a lot of people have not counted inventory from all the intervals in the Uinta. So we haven't laid out the specific 2025 plan yet, but just know that just like we do in other places, we'll have a blend of known intervals, known spacings in the known where everyone has done things. And then we'll have a mix in there of ones that have been partly delineated, and then we'll have some completely new tests. I will give XCL credit for having done more than a typical PE in terms of looking at some of those intervals. And that gave us more confidence when we were putting our bid together in May and June. Okay, that's great. And then if I could follow up with Wade on the repurchase topic, you mentioned waiting on leverage back to kind of one times, but it's pretty easy to see that in the relatively near future, counting the legacy EBITDA you acquired. So based on, I know you haven't given 2025 guidance, but do you see that coming possibly by mid-2025 or sooner if oil holds at $70, your ability to hit the parameters to start repurchases again? Yeah, you could definitely see that if the commodity prices hang in there. I would agree with that. Okay. All right. Thank you. Yeah. Thanks, Tim. Thank you. As a reminder, that's star one to be placed into question queue. Our next question is coming from Oliver Huang from Tudor, Pickering, Holt & Co. Your line is now live. Good morning, Herb, Wade, and team, and thanks for taking the questions. Wanted to kind of try and get a better understanding around the moving pieces on the Q4 pro forma guide for LOE. Are there any one-offs that we should be aware of that's expected to kind of drive the legacy Texas side of things higher quarter over quarter for LOE? And then when we're kind of thinking about the Uinta, how are you all thinking about this line item trending for Q4? And just given how there's lower volumes from fewer completions and the offset frac shut-ins occurring, I do want to be careful about just extrapolating this forward, given potential efficiencies as the operator and rebound in volumes that might impact certain costs that are more fixed in nature. So just trying to think if there's a good proxy in terms of how to think about it for 2025. Okay. Yeah, let me start on this one, Oliver, that I think you pretty well understand on the oilier assets have higher LOE, the gasier assets have lower LOE. So as we transition over time to being an oilier company and getting over 50% oil, you expect LOE to go up somewhat, and the margins are obviously higher on the oil side, and during the third quarter, we saw some optimizations in Midland, and that brought LOE down. That's just basically the constructive environment from a deflationary perspective and the team optimizing things like chemicals and other things, then you have another component when you look forward with Utah that the vertical well LOE per BOE is relatively high just because the rates are lower in the vertical wells. And as we get a greater percentage of horizontal wells in the mix, those are lower LOE per BOE because of the higher rates coming out of the horizontals. So if we think about a model for it, you expect the LOE to be dropping over time intrinsically because of that change in mix of verticals to horizontals. And then just overall, you expect Utah to run somewhat higher with that oil percentage and just the operating environment there. You expect it to run higher, but again, the margins are quite strong just because of the oily nature of it on a per BOE basis. So that's really the way I'd look at it. Did that answer your question, Oliver? Yeah, that's helpful color for sure. And maybe for a second follow-up question, just on the Uinta, with keys now in hand, any sort of color you're able to speak to in terms of what your current DUC backlog might look like out of the basin, exiting the year, just kind of how that might compare to a normalized run rate in terms of how you all are thinking about it, just trying to think through the possible efficiencies that you all might be able to capture on this front moving to the 2025 program? Yeah, that's a great question, Oliver. And just this is the observation is because of the stacked pay nature of the Uinta, which is even more than the Permian in some ways, the pads are larger. So we'll typically drill more wells on a pad at a time before completing. And this is just conceptually, I would expect the DUC count to be higher than, say, the Permian, than South Texas definitely, and in some cases, much of the Permian. So we don't have an official DUC forecast. We actually don't manage the DUC. Knowing how we're running and how efficient it is, the impressive thing in Utah is the integrated nature of the sand mine next to an E-frac, which is natural gas turbine for electric power. And then XCL started fracking as far as two and a half, three miles from that site. So the frac spread doesn't need to move. This is highly, highly efficient, probably the most efficient operation I've ever seen. And by having a lot of wells on a pad, that helps on those efficiencies. So that's the way I look at it. So that's a long-winded answer to a DUC question, but it just kind of gives you a picture of how effective it can be there. But it all starts with the stacked pay and contiguous acreage, which is the type of thing we like and drives us because that's what gives us higher capital efficiency and better returns. Okay, perfect. Thanks for the time. You bet, Oliver. Thank you. We've reached the end of our question and answer session. I'd like to turn the floor back over for any further closing comments. Okay, well, thank you, everyone, for joining us today. And happy November. Take care. Thank you. That does conclude today's teleconference webcast. You may disconnect your line at this time and have a wonderful day. We thank you for your participation today.