After today's presentation, there will be an opportunity to ask Please note this event is being recorded. I now will turn the conference over to Michael Liu. Please go ahead, sir.
Thank you, Keith. Good evening, everyone. This is Michael Liu. 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 ks and our quarterly reports on Form 10 Q and on our Oasis Midstream Partners Form 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 3. 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 50 7 net core inventory locations, which more than doubles our current core position with locations targeting 4 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 BOEs per day with an oil cut in line with the current Oasis Williston production at about 78%.
Our purchase price of $946,000,000 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 $500,000,000 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 2 best oil basins in the United States. On Page 4, 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 20 17 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 1 rig in the Delaware with the option to add a second rig in the latter half of
twenty eighteen.
On Slide 5, 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 frac 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 6, our acquired asset is in the deepest, thickest and highest pressure part of the Delaware oil window, where recently drilled wells are already outperforming offset operators 1,200,000 barrel of oil equivalent type curves and the asset is highly contiguous with ample takeaway capacity, infrastructure to facilitate 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 2 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 7 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 4 core target formations, the Third Bone Spring through the Wolfcamp C with 6 target intervals within them. An anticipated spacing program of 4 to 6 wells per section results in 34 wells per DSU in our core inventory.
Including an additional 4 to 6 wells per target in the Avalon through Bone Spring 2, the potential wells per 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 8. The combination of the assets location in the heart of the overpressure oil window in 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 2 key points about this asset. We are in the oiliest part of the basin based on historical production of recent wells and second, Forge has been drilling some of the longest laterals in the region, which we expect to continue. Now 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. The extensive drilling and completion activities in this area over the last year has really derisked 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 Forage and offset operator well performance as shown on the slide. The strong well results across the column again demonstrates a considerable upside of 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 Forages completed just 9 wells of a 600 plus well inventory. So we are in the early innings of optimization and performance enhancement opportunities on this asset.
One example is profit loading. We've generally seen a correlation in increased pounds per foot and well performance outlining a path for additional upside in 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. Set.
On the right hand chart, you can see that our wells are outperforming 1 of the closest offset operators, 1,200,000 barrel 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 lanes 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 4th quarter average differential to WTI expected to be lower than $1 per BOE. LOE continues to improve and we expect 4th quarter LOE to range between $7.50 per BOE. On the next page, Page 13, you've seen us drive value through vertical integration with OWS and OMS. And 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, The total Oasis projected exit rate is now over 88 MBOE per day with 5 MBOE per day coming from the Delaware. We plan to achieve these targets by running 5 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 1 rig initially with the option to add a second rig in the back half of the year. We plan on spending about $100,000,000 in capital assuming 6 to 8 wells completed and a minimal out spend 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, 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.
And 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. And we've got a team, a strong team that is 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. And the first question comes from Neal Dingmann with SunTrust.
Good afternoon or evening guys. Congrats on the deal. Hey, Neil. 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 a great acreage there. But given the all in place, why run just one rig initially or for the early part of the year given the number of core locations? And for running a DCF, kind of what you're running at time 0 to try to recoup that cash out the door?
Yes. 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. And along with integration to run out there and pick up another rig right away, we don't think is the best idea. So, we're going to run 1, our plan is to add a second.
So we've got a run rate of 2 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 1 up for 1 or 2 wells, but depending on how our integration activity is going. But 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. Yes. 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.
That is and I guess just two last questions. One, just on the non core, you talked about you mentioned, I think the release about $500,000,000 potential sale, what area that might be?
Yes. So there's a couple of things there, Neil. 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.
Okay. And is Thomas, does this mean now because given that certainly core acres that you're picking up, does this mean Elegard and some of the Northern, Painted Woods, some of these others, you won't necessarily go after as soon? And then I'm just trying to get a sense of your Bakken plan with 5 rigs. Is that going to remain the same? Or will that change now a bit given having this other acreage?
Yes. Our Williston plan doesn't change, Neil. It's still going to be the same. We're running 5 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.
Hi, Neal. Thanks.
Thank you. And the next question comes from Drew Venker with Morgan Stanley.
Good evening, everyone. Good evening. I wanted to follow-up on Neil's question. I do definitely agree that the acreage looks like high quality stuff. But curious as to why now because you guys have participated in M and A within the Williston for quite some time and I guess until now had not found anything interesting or attractive enough to enter.
So just is there anything incremental versus your prepared remarks, I would like to hear that?
Yes.
Found anything incremental as in outside of the basin, outside of the Williston.
Tom, me, I just went 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 out to the basin?
Yes,
you kind of 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 ed in 2010, we had about 300,000 Acres and since then, you know, we did the Rosie acquisition at the end of 2013 that included Wild Basin, Painted Woods and Foreman Butte. And 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. And so we'll continue to look for opportunities in the Williston. We view 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 don't 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 and doubling our core inventory to really be resilient to low oil prices and then whether it's low or high oil prices strive to have peer leading margins.
Thanks for that color, Tommy. And 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?
Yes. So, as Tommy said, we're going to start out with 1 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. And 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. And so, in doing that, you could run, as I said, 5 or 6 rigs or something in that range, but that's going to be we'll step into that over time.
Thanks for the color.
You bet.
Thank you. And the next question comes from Brad Heffern with RBC Capital Markets.
Good evening, everyone. Good evening. I was wondering if you could hey, 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? And then I wasn't really clear on whether you have a frac crew going right now or not.
I know in 18, you're planning to complete a lot fewer wells than you're expecting to drill. So is there like a period of time there where you're not having a crew and you're building a DUC backlog?
So, first, with respect to the drilling rigs, we'll inherit a rig that it's got all the specs current kind of high spec rig that we would like to have. So, we're happy with that and we'll keep that rig. With respect to the frac 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're going to we don't have enough frac activity early time here to justify a frac crew by itself. So, we'll be kind of aggregating probably a few wells and then getting spot services on the frac side, but we don't think that will be a problem.
It's just going to take advanced planning and then over time as we get enough 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 can even consider either bring them on or bring frac crews down or put another one in service in this area.
Okay, got it. And then, obviously, this is a nice size acquisition, but I'm sure people are immediately going to think, is this large enough or are you done here? So, is there are there bolt on targets nearby that you guys are thinking about or is this a big enough size to attack for now?
So there's there are some additional bolt on opportunities just in and around this asset, not huge or overpowering, but ones that will allow us to continue to block up the position and add to this asset. So 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 stack pays and so 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, but not we're not in a position where we need really got to go do something else on top of other than really kind of coring up this position.
All right. Thanks, all.
Thanks.
Thank you. And the next question comes from Eli Kantor with DIR Advisors.
Hey, good evening guys.
Good evening.
Can you talk about the overall midstream CapEx requirements for the asset and any kind of outlook you have on potentially capturing 3rd party volumes with LMS?
Yes. We're not there yet, Eli, on all of that. So, what we know is that the asset has no long term marketing arrangements on the water side, freshwater or produced and only has a little bit on the gas and oil side. So 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 OMSOMP has a role to play, but we don't know exactly what that is yet. So 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. It looks like your wells are largely outperforming the peers using a less intense completion technique. But you also mentioned a preference towards potentially increasing the proppant loading there. So just trying to understand about how you're thinking about future completion design in the Delaware?
Yes. So, that's on Page 10 that you're talking about. And you can see on really 1011 that the 4s well to have really outperformed the competitors and there's a large data set there that you can look at. The part of that we think is positioned 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.
And 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. So, 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 EURs and productivity go up. So, that's a lever we'll look at and we'll continue to work on optimizing the completions.
Keep in mind, this is the 9th well or they've done 9 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. So, we're super excited to continue to dig in and work with the forge guys
and try to really improve these well results. Yes. Keep in mind that it's I think it's 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. So the whole lateral science thing that we talked about in the Williston that we have a tremendous amount of experience with.
So it will 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 on if you can give any additional color on timing there.
Yes. So we actually have one project that's in process, but it's relatively small in the tens of millions, not hundreds of millions. And it will it should close next week. But 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. So I would expect it to feather in over the course of the year.
And it's when you look at the spread, if you go back and look at the fairway positions, it's from east side to west side. And so 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. So, I would expect it to be spread throughout 2018, but I wouldn't probably wouldn't expect anything in the Q1.
Great. Thanks. More
like mid year, yes.
Thank you. And the next question comes from Michael Hall with Heikkinen Energy Advisors.
Thanks. Good evening. Hey, Michael. Some of them might have been addressed. I guess one kind of big picture one, if you kind of 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 kind of 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 and it's all in our presentation, I wouldn't expect it to be wildly different than what we did in the Williston. You kind of you continue to evaluate things, you pick your spot, you hang around the hoop and it's as much about timing and execution as it is about deals. But you can look at what we did in the Williston and it kind of provides you a map to how we think about things. Now that being said, when you start looking at 3,800 feet of section versus 300 feet of section, the that looks the footprint looks a little bit different. Sure.
So and it's not what you're seeing with some of the players in the Permian where, I mean, they've captured enough to where you start I mean having a lot of inventory is a good thing, but if it's out 60 or 70 years from now then it's you can't pay a whole lot of money for it. So, I think we'll continue to look for opportunities to build on this And like I said, I would kind of leave the Williston as a roadmap.
That's helpful color. Thanks. Excuse me. And then I guess, I was curious as you highlight in the deck being free cash flow positive in the Williston with a minimal deficit spend in the Delaware of 55. How are you treating interest expense in that and any other corporate overhead?
I'm kind of trying to get to the aggregate, I guess, from those comments.
Yes. Michael, we're just the interest in the G and A is included in the Williston side of it. I mean, it's kind of our call it, pre standalone model, if you will. There is some additional G and A that will incur, we think, with the new asset, but it's pretty minimal and we associated that with the new asset.
Okay. And then, to what extent, I mean, as you think about minimal deficit spending in the Delaware, is that 20% out spend or I'm just trying
to So, yes, so 20
percent out spend, I'm trying
to Well, the D and C for the 1st year for 'eighteen will be about, call it, around $100,000,000 We'll have about $50,000,000 of cash flow off the assets. It will be about $50,000,000 but that $50,000,000 will be covered in the total E and P cash flow. So really covered out of the Williston asset at $50 to $5 oil price will be kind of balanced through the whole program.
Okay, perfect. And then exactly what I was looking for. And I guess last on my end is just and sorry if I missed this in the deck, but what's the assumed kind of drilling and completion cost in the model right now for your Delaware asset?
So, D and C cost is, as we've modeled it, as we come into the front part, it's around $11,500,000 And over time, we think we'll work that down. So within the next year and a half, we're assuming we'll get to around $10,000,000 And just for comparison, if you look at some of the other operators that have the luxury of bigger programs than what Ford just had and they've been doing it for a while, they're in that $10,000,000 range or even a little bit below that. So, we think there's a path and we demonstrated the same thing in the Williston. You've got learning curve and you drilled enough wells in the program, we think we'll continue to drive that cost down.
And Michael, that'd be for a 10,000 foot lateral, £2,000 per foot type completion.
You're right by my Michael. Thank you. That's perfect guys. Appreciate the color.
Thanks.
Thank you. And the next question comes from Ron Mills with Johnson Rice.
Good evening, guys. Hey, Ron. Just a bit of follow-up on an earlier question. You addressed the proppant in terms of completion optimizations. Can you talk a little bit about targeting as far as you've been able to evaluate it?
The lateral targeting from forged, is it where you would have liked the wells to be targeted? And I guess, as you think about that, do you have or did they have seismic over it to help identify the better lateral targets?
So,
there is they view some seismic, I don't there's not a huge 3 d 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. So, we'll be working with those guys and 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.
And 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 9 wells, but in terms of derisking north to south, it looks like you have most of your acreage is derisked, but how about within all of those benches?
So, if you look on Page 9, I'm sure you that's one of the things you're talking about. You can see that there's 9 wells drilled in the first four wells that are shown here. This is for 180 days production. Those are all in the VA. They've got wells in the additional 5 that are located in the other intervals.
And so in some of the other intervals. And the thing though that goes along with that is all the other activity in the area. So, you can see that you've got coverage in really all the formations that we talked about from Third Bone Spring to Wolfcamp C. So 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, but definitely an update in the others to give us a view and we'll continue to improve on that.
Right now, the 9, there's 5 in the A, 3 in the B and 1 in the lower second Bone Springs. And then there's a couple of others that are those are 9 producing wells. There's a couple that aren't producing as yet. I think one of those is an A and the other one is also a lower second Bone Spring as well.
Okay. And then Tommy maybe for you, you provide a little bit of context in terms of deal history. I see their backers were 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 teams or members of your team, just a little bit of history on that?
Yes. So this is not much unlike a lot of things that we do. We kind of figure out where we want to be and pick our spots, as I mentioned earlier. And actually, if you look back, whether it's the Rosie deal, the SM deal, these projects we order from anywhere from 12 months to 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 NCAP guys were our capital sponsors and which is something that I think plays into the whole story here and that you know, 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. It's a bunch of the original founders were Burlington guys. Barry and I worked together when I came out of college in Midland. And then I worked in a number of places with Danny and Arnold and Farmington and Gulf Coast.
And so 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, you know, it helps not just getting to a transaction, but I think that will help us also in transition. You know, we've known some of these guys for 30 years. So, I think it helps it be a lot more efficient. Great.
And then one last one, just you talk on Slide 5 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, comes to about 38,000 per acre. Just curious, the other transactions that you're comparing to for that comment?
Yes, 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 3 sub basins for lack of a better term. And 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. And 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 go pasture and really look great on surface metrics, but really doesn't do a whole lot for us.
So the great thing about this is that it's all in a big contiguous block right in the heart and I think we when we do our calculations and come up with that 38% to 39%, we think that it's that's very attractive relative to similar type transactions, but you're not going to you obviously, you wouldn't see it that way if you just did a cheese spread of every transaction over the last 2 years, but that's not how we look at it.
Great. I appreciate the color and congrats on the transaction.
You bet. Thanks. All right. Thanks.
Thank you. And the next question comes from Gail Nicholson with KLR Group.
Good evening, everyone. Just from the standpoint of the expense structure, you said you're going to be picking up a little more G and A. When you look at the LOE, how does LOE on this asset compared to your Williston? And where do you think you can drive LOE down to as infrastructure to get fully built out?
So the LOE here is relative to Williston is a little bit lower. It's probably early time as these wells are flowing, it's going to it'll be pretty low. It's in the $3 range. And 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. So you may consider it to be $3, $4 or in that range.
So it'll be yes, just it'll be additive to what we have in Williston.
And then you talked about $11,500,000 well cost in the beginning. There's a lot of there's been a push lately in the Delaware as well as Midland to use locally sourced sand. Does that assume using locally sourced sand, is that something that you guys are planning to test or thoughts around that?
Yes, that $11,500,000 I don't think really incorporates lower costs for local source sand. And so 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 frac crew, we'll contemplate whether it makes sense for us to use our own services and help to drive down costs further that way.
And then if you guys did choose out maybe source a brand new fleet for OWS, what would that run you?
Yes, our fleets in the past have generally been kind of $20,000,000 to $25,000,000 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 $30,000,000 but we'll look at that as we go.
Okay, great. Thank you.
Thank you. And as that was the last question, I would like to return the call to Tommy News for any closing comments.
Thanks. We're really excited about this asset position and then an entry into the Permian, But I 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 and 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 kind of tends to go to the end of our inventory. And so 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 that those things in the divestiture bucket assets that we think are meaningfully undervalued in our current stock price. So that repositioning should be very accretive to us.
So this expands our platform as we build scale with core to core inventory and that inventory is going to be resilient as I 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 is a little bit late today and so I appreciate you guys hanging with us and have a good evening.
Thank you. The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.