Hello, and welcome to the Oasis Petroleum Investor Call. All participants will be on the listen-only mode. Should you need assistance, please signal a conference specialist by pressing the star key followed by zero. After today's presentation, there will be an opportunity to ask questions. To ask a question, you may press star, then one on your touch-tone phone. To withdraw your question, please press star, then two. Please note, this event is being recorded. I now turn the conference over to Michael Lou. Please go ahead, sir.
Thank you, Michael. Good evening, everyone. This is Michael Lou. Today, we are excited to announce our entry into the Delaware Basin, and provide a few operational updates. We're delighted to have you on the call today. I'm joined today by Tommy Nusz and Taylor Reid, as well as other members of the team. Please be advised that our remarks on both Oasis Petroleum and Oasis Midstream Partners, including the answers to your questions, include statements that we believe to be forward-looking statements within the meaning of the Private Securities Litigation Reform Act. These forward-looking statements are subject to risks and uncertainties that could cause actual results to be materially different from those currently disclosed in our earnings release and conference call.
Those risks include, among others, matters that we have described in our earnings release, as well as in our filings with the Securities and Exchange Commission, including our annual report on Form 10-K and our quarterly reports on Form 10-Q, and on our Oasis Midstream Partners, Form S-1. We disclaim any obligation to update these forward-looking statements. During this conference call, we may also make references to adjusted EBITDA, which is a non-GAAP financial measure. Reconciliations to adjusted EBITDA to the applicable GAAP measures can be found in our earnings release and on our website. Throughout this call, we will reference the investor presentation about this transaction, which is posted on our website this afternoon. With that, I'll turn the call over to Tommy.
Thanks, Michael, and good evening. I'll start by directing you to page three. It's an exciting day for Oasis, and we're pleased to update you on the acquisition of over 20,000 highly contiguous net acres in the heart of the Delaware Basin oil window. This acquisition brings us 507 net core inventory locations, which more than doubles our current core position, with locations targeting four vertical formations with material upside from other formations that the seller and offset operators have already drilled and delineated. Results from these wells are among the best in the basin, driving a November production rate of 3,500 net BOE per day, with an oil cut in line with the current Oasis Williston production at about 78%. Our purchase price of $946 million will be financed with a mix of stock issued to the sellers, a public equity offering, and draws on our revolving credit facility.
In 2018, we anticipate approximately $500 million of cash proceeds from non-core Williston assets that are attractive, high-return properties, but are at the end of our development schedule. This acquisition is highly accretive to a number of metrics, and the new asset fits very nicely with our oil-weighted Williston assets, our vertical integration strategy, and our deep experience operating in full field development mode. We are now strategically positioned in the core of the two best oil basins in the U.S. On page four, you can further see the location of the asset in the Delaware and begin to understand that we're picking up core of the core acreage, similar to our core position in the Williston Basin. We expect wells to deliver returns of over 75% across the core of both the Williston and the Delaware, and this transaction extends our core inventory life for Oasis.
Due to the strength of our team and our assets, we have already hit our Williston 2017 production exit rate of over 72,000 BOEs per day for the month of November, and as I mentioned previously, the new asset brings production of approximately 3,500 BOEs per day. We expect to continue the 2018 plan that we've been talking about in the Williston Basin, and we'll keep running one rig in the Delaware with the option to add a second rig in the latter half of 2018. On slide five, we have highlights of how this transaction builds on the Oasis strategy. The deal materially expands core inventory as the area has been successfully delineated by the seller and multiple offset operators I mentioned earlier, with the potential for inventory upside based on our conservative booking of inventory.
The purchase price is below or in line with others in the region, driving attractive full-cycle returns through the strength of the asset and the compelling valuation. Our asset is primed for our development expertise, as Oasis has successfully entered full field development in the Williston and has continued to perform at a high level, and we expect to do so in the Delaware as well. It is also extremely helpful that many members of our management team have extensive Permian experience. We can also leverage our unique strategy of vertical integration through our internal frack and midstream businesses to further drive efficient development. The nature of this transaction adds significant core inventory life to our company while maintaining a strong balance sheet and liquidity, allowing us to continue to be free cash flow positive on the upstream basis. Page six.
Our acquired asset is in the deepest, thickest, and highest-pressure part of the Delaware oil window. Recently drilled wells are already outperforming offset operators, 1.2 million barrel oil equivalent type curves. The asset is highly contiguous with ample takeaway capacity infrastructure to facilitate for full field development. The acreage is largely undedicated for oil and gas gathering, and is completely undedicated for water gathering, providing organic midstream growth opportunities to the company. Most of our wells are expected to be drilled with two-mile laterals, and there is still room for optimization on completions. Lastly, Oasis has extremely reasonable drilling requirements on the acreage and does not have to maintain a high rig count to chase HBP requirements. With that, I'm going to turn it over to Taylor to describe the strength of this asset in more detail.
Thanks, Tommy. I'll now direct you to page seven of the presentation. When you look at both our log and well results on this asset, you can see that we are in the best part of the Delaware. We have identified four core target formations, the Third Bone Spring through the Wolfcamp C, with six target intervals within them. An anticipated spacing program of four to six wells per section results in 34 wells per DSU in our core inventory. Including an additional four to six wells per target in the Avalon through Bone Spring 2, the potential wells for DSU count jumps to 56 plus wells. Keep in mind that the per zone spacing numbers could be higher.
When compared to other operators in the region, our spacing assumptions are either conservative or right in line with how people are characterizing their inventory, highlighting the fact that there is a considerable upside in terms of well inventory. Let's now turn to page eight. The combination of the asset's location in the heart of the overpressure oil window and the blocky acreage allows for longer laterals. The combination has resulted in the outstanding well performance seen in this area and implies best-in-class wells among peer group going forward. The chart on the lower left side of the page highlights two key points about this asset. First, we are in the oiliest part of the basin based on historical production of recent wells. Second, Forge has been drilling some of the longest laterals in the region, which we expect to continue.
On page 10, we offer more detail on well control in the area, demonstrating that we are buying an asset that has been well delineated. Extensive drilling and completion activities in this area over the last year has really de-risked this asset, especially when compared to other transactions in the area over the past few years. As a result, we have minimized downside risk while pulling the trigger on an asset that has continued upside that is not embedded into our acquisition price. We are really excited about Forge and offset operator well performance, as shown on the slide. The strong well results across the column again demonstrate the considerable upside to what we are paying for the asset.
If you now focus on page 10, you can see that the recent completions from this asset are performance leaders in the Delaware, as depicted in the chart on the right-hand side of the page. The remarkable attribute of these wells is that they tend to flow for extended periods of time. For example, the Bighorn well, the first well drilled by the operator on these assets is still flowing after 18 months. As you can see, results have been great. Oasis will continue to optimize completion design on these outstanding wells. Keep in mind that Forge has completed just nine wells of a 600-plus well inventory. We are in the early innings of optimization and performance enhancement opportunities on this asset. One example is proppant loading.
We've generally seen a correlation in increased pounds per foot and well performance, outlining a path for additional upside and well performance on this asset. Let's now turn to page 11. Looking closer at some well results in the region, our wells are at the top of the peer set. On the right-hand chart, you can see that our wells are outperforming one of the closest offset operators, 1.2 million barrels oil equivalent type curve, and still doing so without artificial lift. With that, I'll now turn the call over to Michael.
Thanks, Taylor. If you turn to page 12, Oasis has earned a track record of strong execution in the Williston Basin as we developed a skill set that is highly transferable to the Delaware as well. We've driven extensive improvements in capital and operational efficiency over the past few years while we transitioned to full field development. We've drilled 750 wells since 2010, with lateral lengths averaging about 10,000 feet across multiple zones. We continue to optimize operations through the use of zipper fracs, large pad developments, while decreasing spud to rig release drilling times. Differentials continue to dramatically improve in the Williston, with the fourth quarter average differential to WTI expected to be lower than $1 per BOE. LOE continues to improve, and we expect fourth quarter LOE to range between $7 and $7.50 per BOE.
On the next page 13, you've seen us drive value through vertical integration with OWS and OMS. That competency also provides future upside as we operate this asset during full field development. Vertical integration leads to cost savings and has greatly reduced our completion costs and our lease operating costs in the Williston since 2014. Our new acreage is largely undedicated for midstream services, allowing the possibility of midstream build-out through OMS and potential future return of capital to Oasis through drop-downs of ownership to OMP. OWS has the possibility to build out a frac crew in the Delaware, bringing top-tier well completion efficiency to this asset. Either way, we can bring supply chain management advantages to the new asset in advance of launching another crew in the Delaware.
On page 14, this slide speaks to the continued strength of our Williston asset and the quality of our Oasis team. We've already achieved our 2017 exit rate in November, with production averaging greater than 72,000 barrels of oil equivalent per day. Our 2018 Williston production exit rate of 83 MBOE per day is unchanged, but total Oasis projected exit rate is now over 88 MBOE per day, with five MBOE per day coming from the Delaware. We plan to achieve these targets by running five rigs in the Williston, completing 100 to 120 operated wells at our current well costs. In the Delaware, we will drill 16 to 20 wells in 2018 by running one rig initially, with the option to add a second rig in the back half of the year.
We plan on spending about $100 million in capital, assuming six to eight wells completed and a minimal outspend at $55 WTI due to EBITDA generated from production. Even with the acquisition, we are expecting to be free cash flow positive for our total upstream business at $55 WTI. On the final page 15, in conclusion, I want to reiterate that Oasis has a premier collection of assets and a highly disciplined management team. We have further expanded our operational scale with assets focused in the top 2 U.S. oil basins. Our positions continue to be large and contiguous, delivering high returns with low risk across various commodity prices. We see clear upside with near-term catalysts. Our midstream segment continues to remain strong, with the MLP giving the company greater flexibility and liquidity.
We've got a strong team that manages capital well, is returns focused, and has the financial and technical ability to deliver above-market shareholder returns. With that, I'll turn the call back over to Keith to open the lines up for questions.
Thank you. We will now begin the question and answer session. To ask a question, please press star then one on your telephone keypad. If you are using a speakerphone, please pick up your handset before pressing the keys. To withdraw your question, please press star then two. At this time, we will pause momentarily to assemble the roster. The first question comes from Neal Dingmann with Truist.
Afternoon there, or evening, guys. Congrats on the deal.
Hey, Neal.
My first question is for you or Michael. I'm just a little surprised. Again, I do agree with you guys, and I think the acreage is great acreage there. Given the all-in price, why run just one rig initially or for the early part of the year, given the number of core locations? If we're running a DCF, what you're running at time zero to try to obviously recoup that cash out the door?
Yeah. Neal, as you've heard us talk before, we try to approach things from one direction. This is a move into a new basin, and we want to be diligent and prudent about that. Along with integration, to run out there and pick up another rig right away, we don't think is the best idea. We're going to run one. Our plan is to add a second. We've got a run rate of two in the second half of the year. Now, that doesn't mean that we don't, in the first half of the year, maybe pick one up for one or two wells, but depending on how our integration activity is going. Initial phase is the integration of the project and having a solid plan in place makes more sense to us than going out and picking up a bunch of rigs.
Yeah.
Now-
One thing I'd add to that is, if you just look back at Wild Basin, for example, when we did that acquisition in 2013, we had a similar approach, and we took the time to do the testing, understand productivity on the wells and what they look like in spacing, and then get out far enough in front to get all the infrastructure in place so that we can efficiently produce the asset.
I guess just two last questions. One, just on the non-core. You mentioned, I think, the release about $500 million potential sale, what area that might be?
There's a couple of things there, Neal. It's mainly Fairway acreage. Some of those blocks that are out in that Fairway position, as well as potentially some non-op production as well.
Tom, does this mean now, because given that certainly core acres that you're picking up Does this mean Alger and some of the Northern Painted Woods and some of these others, you won't necessarily go after as soon? I'm just trying to get a sense of your plotting plan, with five rigs, is that going to remain the same or will that change now a bit given having this other acreage?
Our Williston plan doesn't change, Neal. It's still going to be the same. We're running five rigs, and we'll stay on the same path that we have been there, and then this is in addition to.
Got it. All right. Thanks so much, guys.
Bye, Neal. Thanks.
The next question comes from Drew Venker with Morgan Stanley.
Good evening, everyone.
Good evening.
Wanted to follow up on Neal's question. I do definitely agree that the acreage looks like high-quality stuff. Bit curious as to why now, because you guys have participated in M&A within the Williston for quite some time, and I guess until now had not found anything interesting or attractive enough to enter. If there's anything incremental versus your prepared remarks, would like to hear that.
Yeah. Found anything incremental as in outside of the basin? Outside of the Williston?
Tommy, I just meant incremental from your prepared remarks about why you would want to leave just the Williston Basin, as of now relative to, from inception, really not moving outside the basin.
Yeah. You look at the growth that we've had in the Williston, from our initial acquisition of 175,000 acres to expanding to the east side of the basin. When we IPO'd in 2010, we had about 300,000 acres. Since then, we did the Rosie acquisition at the end of 2013 that included Wild Basin, Painted Woods, and Foreman Butte. Then, last year, you saw us do a bolt-on with the SM position that was right in and around all of our consolidated blocks, made a lot of sense to us. We'll continue to look for opportunities in the Williston.
We viewed this, though, as a complement to consolidation of core positions where we take some of that asset that's out in the fairway, that's further out in the development plan, that we can enhance the value with through putting it in somebody else's hands, and use that to continue to build core inventory that's resilient to very low oil prices. Hopefully we won't see that like we've seen over the last couple of years, but if we do, we've got an opportunity set here in doubling our core inventory to really be resilient to low oil prices. Whether it's low or high oil prices, strive to have peer-leading margins.
Thanks for that color, Tommy. Over time, do you have a good sense of how many rigs you could run in this acreage before you run into infrastructure challenges or other logistical issues?
Yeah. As Tommy said, we're going to start out with one, picking up a second later next year. As you get into full field development, you could run 5 to 6 rigs, something in that range. We'll probably be executing on this asset similar to what we do in Williston, where you've got multiple rigs on a single spacing unit just to bring the cycle times down. In doing that, you could run, as I said, 5 or 6 rigs or something in that range. We'll step into that over time.
Thanks for the color.
You bet.
Thank you. The next question comes from Brad Heffern with RBC Capital Markets.
Evening, everyone.
Hey, Brad.
I was wondering if you could delve into the services side of things a little bit more. Are you happy with the spec of the rig that you're inheriting there? Then I wasn't really clear on whether you have a frack crew going right now or not. I know in 2018, you're planning to complete a lot fewer wells than you're expecting to drill. Is there a period of time there where you're not having a crew and you're building a DUC backlog?
First, with respect to the drilling rigs, we'll inherit a rig that it's got all the specs current, kind of the high-spec rig that we would like to have. We're happy with that, and we'll keep that rig. With respect to the frack services, it ends up being backloaded just by nature of getting the stuff drilled and then getting a little bit of a backlog before we start completing. We don't have enough frack activity early time here to justify a frack crew by itself. We'll be aggregating probably a few wells and then getting spot
Services on the frac side, but we don't think that'll be a problem. It's just going to take advanced planning, over time, as we pick up the activity more and get enough inventory, we'll have the option to get a full-time frac crew, and at that time, could even consider either bringing them on or going frac crews down or putting another one in service in this area.
Okay. Got it. Obviously this is a nice size acquisition. I'm sure people are immediately going to think, is this large enough or are you done here? Are there bolt-on targets nearby that you guys are thinking about? Or is this a big enough size to attack for now?
There are some additional bolt-on opportunities just in and around this asset. Not huge or overpowering, ones that will allow us to continue to block up the position and add to this asset. Definitely interested on that front. As it gets to the size of the deal, while it's 20,000 acres, relative to the large Williston position, as we all know here, you got a lot of stacked pays, a bunch of inventory, and we're doubling our core inventory. We don't have a need to go do a bunch more deals. We're going to be focused on really executing on this asset. If the right thing comes along, we'll certainly look at it. We're not in a position where we need really got to go do something else on top other than really kind of coring up this position.
All right. Thanks all.
Thanks.
Thank you. The next question comes from Eli Kantor with DIR Advisors.
Hey, good evening, guys.
Good evening.
Can you talk about the overall midstream CapEx requirement for the asset and any kind of outlook you have on potentially capturing third-party volumes, with OMS?
Yeah, we're not there yet, Eli, on all of that. What we know is that the asset has no long-term marketing arrangements on the water side, fresh water, or produce, and only has a little bit on the gas and oil side. There's a lot of big infrastructure out in this area that you can attach to. We're going to look at opportunities and what's the best for the asset. We certainly think OMS/OMP has a role to play, but we don't know exactly what that is yet. We'll continue to work that over the coming months and let you know as we get to more of an answer.
Fair enough. I wanted to touch on the well results you laid out in the presentation. Looks like your wells are largely outperforming the peers using a less intense completion technique. You also mentioned a preference towards potentially increasing the proppant loading there. Just trying to understand about how you're thinking about future completion design in the Delaware.
Yeah. That's on page 10 that you're talking about, and you can see on really 10 and 11 that the Forge wells have really outperformed the competitors, and there's a large data set there that you can look at. Part of that we think is position in the basin. Deep part of the basin, higher pressured, very oily. Oiliest part, over 85% production early time on these wells is all oil. As you noted, the intensity on the fracs are less than what you've seen for some other operators. You can see that on the graph on page 10. We'll be looking at increasing the loads. There's generally been correlations in a lot of these basins between proppant loads increasing and seeing the EURs and productivity go up. That's a lever we'll look at, and we'll continue to work on optimizing the completions.
Keep in mind, this is the ninth well, or they've done nine wells so far with an inventory, as we talked about, of over 600 wells. It's really early days in terms of the completion techniques being employed on this asset. We're super excited to continue to dig in and work with the Forge guys and try to really improve these well results.
Keep in mind that I think optimization is the key word here, and just more sand isn't necessarily the magic fix. It's what's the sand volume, what's the fluid volume, and then how it's efficiently placed. The whole lateral science thing that we talk about in the Williston that we have a tremendous amount of experience with. It'll be a combination of all those things as Taylor and the guys look to optimize these completions.
Just one more from me. Can you give us a sense of where you are with the Williston asset sale process? Is there a data room open? I'm not trying to pin you down on a date, but just curious if you can give any additional color on timing there.
Yeah. We actually have one project that's in process, but it's relatively small, in the $tens of millions, not $hundreds of millions. It should close next week.
As far as really ramping up on the remainder of it, we've done a little bit of work on it, but still some work to do. I would expect it to feather in over the course of the year. When you look at the spread, if you go back and look at the fairway positions, it's from east side to west side. I think it's unlikely, not out of the question, but unlikely that you have a single buyer for big chunks of that. It's probably going to be more targeted, given some of the experience that we've had up there. I would expect it to be spread throughout 2018, but I probably wouldn't expect anything in the first quarter.
Great. Thanks, guys.
More like mid-year, yeah.
Thank you. The next question comes from Michael Hall with Heikkinen Energy Advisors.
Thanks. Good evening.
Hey, Mike.
Some of them have been addressed. I guess one big picture one, if you step back and look out a few years, how do you guys envision Oasis in the Delaware Basin? Just trying to get a sense for how big you plan to get and how big of a component of the overall corporate profile you really see this being over a decent timeframe.
What I would say, Michael, is that if you're looking for the roadmap, look at the last 10 years. It's all in our presentation. I wouldn't expect it to be wildly different than what we did in the Williston. You continue to evaluate things. You pick your spots, you hang around the hoop, and it's as much about timing and execution as it is about deals. You can look at what we did in the Williston, and it provides you a map to how we think about things. That being said, when you start looking at 3,800 feet a section versus 300 feet a section, the footprint looks a little bit different.
Sure.
It's not what you've seen with some of the players in the Permian where they've captured enough to where having a lot of inventory is a good thing, but if it's out 60 or 70 years from now, then you can't pay a whole lot of money for it. I think we'll continue to look for opportunities to build on this, and like I said, I would look at the Williston as a roadmap.
That's helpful color. Thanks. Excuse me. Then, I guess, I was curious, as you've highlighted in the deck, being free cash flow positive in the Williston with a minimal deficit spend in the Delaware at 55. How are we treating interest expense in that and any other corporate overhead? I'm trying to get to the aggregate, I guess, from those comments.
Yeah. Michael, the interest in the G&A is included in the Williston side of it.
Okay
call it pre-standalone model, if you will. There is some additional G&A that we'll incur, we think, with the new asset, but it's pretty minimal, and we associated that with the new asset.
To what extent, as you think about "minimal deficit spending" in the Delaware, is that 20% outspend, or? I'm just trying to-
Yeah.
10% outspend? I'm trying to
Well, the D&C for the first year for 2018 will be about, call it around $100 million. We'll have about $50 million of cash flow off the asset. It'll be about $50 million, but that $50 million will be covered in the total E&P cash flow. Really covered out of the Williston asset at a $55 oil price. We'll be balanced through the whole program.
Okay, perfect. That's exactly what I was looking for. Then I guess last on my end is just, and sorry if I missed this in the deck, but what's the assumed drilling and completion cost in the model right now for your Delaware asset?
D&C cost as we've modeled it, if we come into the front part, it's around $11.5 million. Over time, we think we'll work that down. Within the next year and a half, we're assuming we'll get to around $10 million. Just for comparison, if you look at some of the other operators that have the luxury of bigger programs than what Forge has had, have been doing it for a while. They're in that $10 million range or even a little bit below that. We think there's a path, and we demonstrated the same thing in the Williston. You've got a learning curve, and you drill enough wells in a program, we think we'll continue to drive that cost down.
And Michael, that'd be for a 10,000-foot lateral, 2,000 pounds per foot type completion.
You read my mind, Michael. Thank you. That's perfect, guys.
Okay.
Appreciate the color.
Thanks.
Thank you. The next question comes from Ron Mills with Johnson Rice.
Evening, guys.
Hey, Ron.
Just a bit of follow-up on an earlier question. You addressed the proppant in terms of completion optimizations. Talk a little bit about targeting, as far as you've been able to evaluate it, the lateral targeting from FORGE, is it where you would've liked the wells to be targeted? I guess adjacent to that, do you have, or did they have seismic over it to help identify the better lateral targets?
They've used some seismic. There's not a huge 3D shoot, but they've utilized seismic as they've developed their prospects and to help them pick. In terms of targeting, we think they've done a good job. I think the well results speak for good zone selection. We'll be working with those guys in transition as we are picking wells going forward and just making sure that we understand everything that they've done, and it's consistent with the data we've been gathering in the area.
To understand the core inventory across the four zones, and including the upper and lower potential in both the A and the B, I know they've only drilled nine wells, in terms of de-risking north to south, it looks like most of your acreage is de-risked. How about within all of those stitches?
If you look on page nine, I'm sure that's one of the things you're talking about. You can see that Stein wells drilled the first four wells that are shown here. This is for 180 days of production. Those are all in the A. They've got wells in the additional five that are located in the other intervals, in some of the other intervals. The thing, though, that goes along with that is all the other activity in the area. You can see that you've got coverage in really all the interval formations that we talked about, from Third Bone Spring to Wolfcamp C. When you take the FORGE data plus the other data, we're getting pretty comfortable with what we would expect to see in the other zones.
The A and the B have the most wells drilled at this point, definitely an update in the others to give us a view, we'll continue to improve on that.
Yeah. Right now, of the nine, there's five in the A, three in the B, and one in the lower Second Bone Spring. There's a couple of others that are nine producing wells. There's a couple that aren't producing as yet. I think one of those is of A, and the other one's also a lower Second Bone Spring well.
Okay. Tommy, maybe for you, can you provide a little bit of context in terms of deal history? I see their backers were the same couple of the backers that were in Oasis historically. It looks like from a management standpoint, there's probably been quite a bit of overlap between whether the Burlington days and/or Conoco, amongst other members of your team. Just a little bit of history on that.
This is not much unlike a lot of things that we do. We figure out where we want to be and pick our spots, as I mentioned earlier, actually, if you look back, whether it's the Rosie deal, the SM deal, these projects, we work anywhere from 12-24 months before we come into the right window where there's an opportunity that we think we can execute on it. This is one that we knew a lot about. As you mentioned, the EnCap guys were our capital sponsors, which is something that I think plays into the whole story here, in that I think they did well with us once, and I think they've got a lot of trust in the management team. On the Forge team, Ron, you hit on it. The original founders were Burlington guys.
Barry and I worked together when I came out of college in Midland. I worked in a number of places with Danny and Arnold in Farmington and Gulf Coast, we've got a lot of history with these guys, which makes a process like this a lot smoother across the board. There's a lot of trust there, and I think it helps not just getting to a transaction, but I think that will help us also in transition.
We've known some of these guys for 30 years. I think it helps it be a lot more efficient.
Great. Then one last one. You talk on slide five about the relative valuation with other transactions. Can you just provide a little bit more color? It looks like if you use the PDP value for the acquired production, it comes to about $38,000 per acre.
Right.
Just curious, the other transactions that you're comparing to for that comment.
Yeah. I think, as we look at it, we try to do relative comparisons with other transactions that look the same. The Permian is a big combination of three subbasins, for lack of a better term. Even when you look at the Delaware in isolation, depending on where you are in the Delaware, things can change a lot on a number of fronts, whether it's rock properties, fluid properties with different GORs and all kinds of other things. Whether acreage positions are consolidated or whether it's a scattershot. When we do these kinds of comparisons, we try to look at transactions that are similar to the ones that we're entering into. We can go out and do a deal that's got half goat pasture and really look great on surface metrics, but really doesn't do a whole lot for us.
The great thing about this is that it's all in a big contiguous block right in the heart. I think when we do our calculations and come up with that 38-39, we think that that's very attractive relative to similar type transactions. Obviously you wouldn't see it that way if you just did a cheese spread of every transaction over the last two years. That's not how we look at it.
Great. I appreciate the color.
The value difference.
I appreciate the color, and congrats on the transaction.
You bet, thanks.
All right, thanks.
Thank you. The next question comes from Gail Nicholson with KLR Group.
Good evening, everyone. Just about a standpoint of the expense structure, you said you're going to be picking up a little more G&A. When you look at the LOE, how does LOE on this asset compare to your Williston, and where do you think you can drive LOE down to as infrastructure gets fully built out?
The LOE here is relative to Williston is a little bit lower. Early time as these wells are flowing, it'll be pretty low. It's in the $3 range. As you get into artificial lift and more wells and all those things, it's going to trend up a bit for a period of time. You may consider it to be $3, $4 or in that range.
Sorry.
Yeah, just it'll be additive to what we have in Williston.
Then you talked about $11.5 million anticipated well cost in the beginning. There's been a push lately in the Delaware as well as Midland to use locally sourced sand. Using locally sourced sand, is that something that you guys are planning to test or thoughts around that?
Yeah, that $11.5 million I don't think really incorporates lower cost for local sourced sand. That is one of the things that we'll optimize around, see if we can reduce the sand cost, and try to do that across all the service components. Like we talked about, as we get into a full suite of completions where we can justify a whole frack crew, we'll contemplate whether it makes sense for us to use our own services and help to drive down costs further that way.
Then if you guys did choose out to maybe source a brand new fleet for OWS, what would that run you?
Yeah, our fleets in the past have generally been $20 million-$25 million range for the equipment. If we have a coming into a new basin and having a service point and doing all those things, there's going to be incremental money to that, and don't have a great figure on that at the moment. When we originally did Williston all in, it was more around $30 million, but we'll look at that as we go.
Okay, great. Thank you.
Thank you. As that was the last question, I would like to return the call to Thomas Nusz for any closing comments.
Thanks. We're really excited about this asset position and entry into the Permian. Want to be clear that this is for us not a repositioning, but a complement to a tremendous Williston position that we've already got in place. This capitalizes on our operational competencies in full field development and also gives us the opportunity to redeploy capital tied up in a very attractive Williston asset base out in the fairway that with this transaction, tends to go to the end of our inventory. We feel like we can accelerate some value there and redeploy that capital and something also that we're not, at least in our minds, for those things in the divestiture bucket assets that we think are meaningfully undervalued in our current stock price. That repositioning should be very accretive to us.
This expands our platform as we build scale with the core inventory, and that inventory is going to be resilient, as I talked about earlier, to very low oil prices and will provide us what we think across the board will be peer leading margins. I know the call's a little bit late today, and so I appreciate you guys hanging with us. Have a good evening.
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