Gabriel Daoud

I was hoping 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 [TILs] by the seller. Could you maybe quantify the impact of 4Q? And then maybe give us a leading edge number as far as what current Utah production might be at this point?

Herbert Vogel

Yeah, Dave, 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 22. 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 those, that optimal would juxtapose with the existing permits and plans.
And 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, it's just our normal planning process and CapEx allocation. And so when we get to February, we'll have -- be able to lay that out fully.
And so I just want to just encourage people, you can understand, you guys are forecasting 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 the 4Q is impacted.
And then I'll just go back to what I just said for 2025, it will 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, Gabriel.

Gabriel Daoud

No. 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 '25. But if I look at 4Q 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 '25 CapEx, is it fair to say directionally, you could be $1.3 billion or lower, just given the plans to go from nine to six rigs? And I'll keep it there.

Herbert Vogel

Yeah. No, I would say, Gabriel, 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 will depend, again, on commodity prices, that's always the starting point for this, too.

Operator

Leo Mariani, ROTH MKM.

Leo Mariani

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 (inaudible).

Herbert Vogel

Yeah. Sure, Leo. We just took on the Utah asset. 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've added in Utah, and we've obviously got a larger air band on that since we just took over the assets.

Leo Mariani

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 like maybe these aren't all that likely kind of going forward to get to kind of 1 times net 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 like material weakness, maybe you'll step in as really the free cash flow goes to debt [paydown]?

A. Wade Pursell

I think that's actually a pretty good summary. We're clearly prioritizing debt reduction right now and getting back to that 1 times 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 times 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.

Herbert Vogel

And Leo, I'll just remind you, we reloaded that buyback authorization with our Board to end of '27 for $500 million. So it's a healthy buyback that we can do over the three-year period.

Operator

Scott Hanold, RBC Capital Markets.

Scott Hanold

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 like when you look at your asset base, 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?

Herbert Vogel

Yeah, Scott, this is pretty much normal and routine for us and 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 optimize 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 we'll -- when we report the full year '24 results in February, we'll share that full plan.

A. Wade Pursell

Yeah. I would just add, you mentioned the pullback in commodity prices. Just a reminder, all three of our assets have significant amount of inventory at low breakevens. So we actually -- $70 oil is fantastic, I guess, is what I would say, from a standpoint of returns for our assets.

Herbert Vogel

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 that's -- we're getting the benefit of that now.

Scott Hanold

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 seem to exceed your initial acquisition economic parameters.
Can you give us a little context? Like 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.

Herbert Vogel

Yeah. Sure, Scott. So first of all, we're really 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 play. 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 full co-development where you've got one really good well in two wells that are lesser on average, these are very economic wells for us, and so we're happy with the results. And with what we saw in the first two wells and really the first 8 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 you space correctly, and we believe we spaced correctly.

Operator

(Operator Instructions) Neal Dingmann, Truist Securities.

Neal Dingmann

My question, maybe just follow 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 '25 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?

Herbert Vogel

Yeah, Neal, great question. I have not seen the specifics of what our Permian team is 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.
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 asset. So it has to be a good program and it has to be designed as a good program, and that means 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.

Neal Dingmann

Great details. And then just second around the Uinta, and maybe specifically around the marketing there. Just wonder 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?

Herbert Vogel

Yeah, Neal, 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 -- what optimizes their product slate. So we'll just be working that over time, and I think we'll get better and better as time goes on.

Operator

Michael Scialla, Stephens.

Michael Scialla

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 time frame there?

Herbert Vogel

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 the Easter. So it's not efficient to build water handling facilities at 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 an IP, but you also get a slower decline. And value-wise, it's the right way to go because we spend less capital. So that's the story there.

Michael Scialla

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?

Herbert Vogel

That's exactly right.

Michael Scialla

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?

Herbert Vogel

Yeah, Mike. So we -- the transition services agreement started with when we closed October 1. 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 in -- more in the day-to-day decisions than we would have been September 30. And there's a pre-agreed what we pay them during that period of time.
And then on January 1, 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 are a really great team, so it works quite effectively.
And then in terms of G&A, it's 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 running change won't occur until January, when we have it fully staffed up with the people we've hired from XCL.

A. Wade Pursell

Yeah, Mike, this way -- 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.

Operator

Tim Rezvan, KeyBanc Capital Markets.

Timothy Rezvan

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 derisked zones. So obviously, maybe it's not [17], but it looks like it's greater than three of 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 outs to other areas?

Herbert Vogel

Yeah. Great question, Tim. And I really appreciate you recognizing the importance of that, because a lot of people have not counted inventory in the -- 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 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.

Timothy Rezvan

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 1 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?

A. Wade Pursell

Yeah, you could definitely see that if the commodity prices hang in there. I would agree with that.

Operator

(Operator Instructions) Oliver Huang, Tudor, Pickering, Holt.

Oliver Huang

Herb, Wade, 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 a 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?

Herbert Vogel

Okay. Yeah, let me start on this one, Oliver, that I think you pretty well understand on the oilier assets have higher LOE, the gassier 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 we -- during the third quarter, we saw some optimization 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. Does that get -- answer your question, Oliver?

Oliver Huang

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, and 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 take it through the possible efficiencies that you all might be able to capture on this front moving to the 2025, program.

Herbert Vogel

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, just -- 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 DUCs. It's just 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 run off a gas turbine for electric power. And then we -- XCL started fracking as far as 2.5, 3 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's -- 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 drive us because that's what gives us higher capital efficiency and better returns.

Operator

We reached the end of our question-and-answer session. I'd like to turn the floor back over for any further or closing comments.

Herbert Vogel

Okay. Well, thank you, everyone, for joining us today, and Happy November. Take care.

Operator

Thank you. That does conclude today's teleconference webcast. You may disconnect your lines at this time, and have a wonderful day. We thank you for your participation today.