Good morning. My name is Ginger, and I will be your conference operator today. At this time, I'd like to welcome everyone to the Oasis Petroleum Investor Call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question and answer session.
I will now turn the call over to Michael Liu, Oasis' CFO to begin the conference. Thank you. Mr. Liu, you may begin your conference.
Thank you, Ginger. Good morning, everyone. This is Michael Liu. Today, we announced 4 great transactions that make a ton of sense for Oasis and its shareholders. We're glad to have you on the call to discuss these opportunities in more detail.
A presentation is available on the website that we will reference directly. You can access and download these slides from the main page on our website at www.oasispetroleum.com. Please Please be advised that our remarks, 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.
We disclaim any obligation to update these forward looking statements. During this conference call, we could 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 releases or on our website. I would also encourage everyone to be mindful of the fact that while we have executed agreements on transactions that we fully intend to close, they're not closed yet, which may limit some of what we can tell you in Q and A and subsequent IR discussions. I will now turn the call over to Tommy.
Thank you all for joining us on short notice to run through the transactions we just announced. We will start on slide 3 of the presentation. These acquisitions, which will add a total of 161,000 net acres to our existing position, clearly make Oasis one of the top operators the Williston Basin and clearly the top pure play in the Bakken. On a pro form a basis, we now have 492,000 net acres with recent production of approximately 43,000 net barrels of oil equivalent per day. Combined, we have 216,000,000 barrels equivalent of proved reserves with a PV-ten value of $4,900,000,000 We also will have controlled control 399 operated drill blocks with over 16 years of drilling inventory at our current rig pace, which combined will be 13 rigs.
On slide 4, you can see our existing footprint in gold and the acquired acreage in light blue. It is clear that the combined position is in line with our acquisition strategy we've been discussing since our 2010 IPO. We've always said we want to build large contiguous blocks where we can drive operations and efficiencies of scale. We look for assets like our own with high working interest and operatorship. These four acquisitions fall in line with our strategy and we now have an incredible opportunity to drive value across a premier position in the basin.
Additionally, the bulk of the acreage is already held by production. So we have a lot of flexibility on how we develop the combined position. We've outlined new project area boundaries to account for the acquired acreage and have provided the breakout of that acreage. Our West Williston acquisition adds approximately 136,000 net acres. Now I'll point out for clarity that 91,000 of those acres have rights to all depths.
The remaining 45,000 net acres are subject to some type of depth segregation. The acquisition increases our West Williston position by 65% and our North Dakota only acres in West Williston by approximately 130%. We will grow our Indian Hills position meaningfully and this area is in the deepest part of the basin where we have EURs in the upper half of our type curve range. Painted Woods and Foreman Butte fill an open area in the middle of our large blocks and unify our operated position with highly economic acreage. Our East Nesson acquisitions add approximately 25,000 net acres in North Cottonwood.
As Taylor will touch on in a minute, we've been able to make this area extremely economic over the last year through improving completion styles and lower well costs. This competitive advantage coupled with our existing infrastructure makes this an exciting core block for us with very attractive economics. Slide 5 highlights the main value drivers of the acquisitions. When we put the business development team together about a year ago, we highlighted 4 items here as critical components to securing a deal. 1st, we wanted acreage that is highly operated and contiguous.
These attributes enable us to drive operations, develop efficiencies of scale and put us in control of our own destiny. Our pro form a acreage is 91% operated and is largely held by production. Similar to our standalone position substantially all of the acquired position will be in pad development mode next year. 2nd, we're looking for ways to add inventory and upside optionality. These assets increase our gross operated locations by 42% in the heart of the basin.
With the infill density and lower bench 3 Forged catalysts on the horizon, we believe there's a significant amount of upside potential as well. The 3rd component is scale. The post transaction position builds on our ability to optimize price realizations, LOE, well costs and corporate costs as we have done already with our existing position. Finally, the 4th component to a successful deal would be adding incremental net asset value. We're all shareholders at Oasis and we believe these acquisitions are highly accretive.
Operationally, we are adding a significant amount of high margin production, inventory and reserves. As we've mentioned in previous calls, our business development team has been spending most of its time in the basin over the last year working to capture packages like the ones we're presenting today. On the heels of this, they will now turn their attention in the near term to how to best optimize the roughly 500,000 net acres we will hold post close. I'll now turn the call over to Taylor to discuss in a bit more detail how the asset fits with our overall asset position. Thanks, Tommy.
I'd like
to first walk you through the table on slide 6 highlighting a few components. As Tommy discussed, we are adding approximately 116,000 net acres that are prospective for the Bakken and all benches of the Three Forks, increasing our current position by 35%. There is an additional 33,000 net acres with rights to all depths except the Middle Bakken and the 1st bench of the Three Forks and 12,000 net acres with shallow rights only in West Williston. We are also adding approximately 9,300 barrels of oil equivalent per day to our production for a 28% increase. We are significantly adding to our operated position by adding 119 operated drill blocks and 854 gross operated locations to the portfolio, an increase north of 40% for both compared to our current asset.
The assets are 91% operated, leaving our company at a similar operational level with similar working interest compared to our standalone metrics. In a nutshell, these assets look a lot like ours and we're adding to our operated position in a meaningful way. On slide 7, you can see that we are increasing our gross operated inventory by 42%. Pro form a, we will have 2,874 gross operated locations with an average working interest of 68%. We are assuming each spacing unit will have 4 Bakken wells and 4 First Bench, 3 Forks wells.
We will cover the potential to grow this inventory through down spacing and lower bench work in the next few slides. On Slide 8, you can see some of the industry down spacing activity in the basin. We have 22 spacing tests across our acres position testing up to 7 wells per formation. These will be testing drainage within the same zone and communication between the Bakken and the Three Forks. We have been encouraged by the results so far, but it is still early.
In addition, other operators are performing similar or more aggressive down spacing tests in the basin. The map on the right gives you a better sense for the location of these tests and the identity of the operator performing the work. In addition to the downspacing activity, we also see a lot of opportunity to improve our inventory through the lower benches of the Three Forks as seen on slide 9. Based on the core work we performed, we are in the process of drilling 2 wells into the 2nd bench of the Three Forks. In addition and not outlined here, we are planning on drilling additional lower bench wells, including multiple benches concurrently to test interference.
Our confidence is increasing that the reservoirs will produce economic wells and will add to our inventory. In addition to the wells we are drilling, the West Wolfson acquisition had 2 lower bench well tests, 1 in the 2nd bench and 1 in the 3rd bench, which were completed by the previous operator. These wells have performed in line with other First Bench Three Forks wells in the area. Slide 10 begins to address the potential to capture efficiency through the additional scale gained by these 4 acquisitions. As we have discussed in the past, we have decreased well costs from $10,500,000 and are targeting a year end well cost of $7,800,000 on average with the impact of OWS.
As we move forward, we believe pad development and efficiency gains should be able to drive to an average well cost of $7,300,000 by the end of 2014. Transitioning to the right side of the slide, Oasis has accumulated a large portfolio of inventory with different characteristics, but equally compelling economics. Our well costs vary by project area depending on depth and rock qualities and we tailor the completion style to enhance EURs, reduce well cost and ultimately decrease F and D finding and development cost to boost returns. We achieved essentially the same economics for a 525,000 barrel equivalent well as for a 675 MBOE well due cost control and completion optimization. When comparing wells across the spectrum of our portfolio, we are encouraged by the fact that we have made lower EUR well returns comparable to high EUR well returns.
Both the East and West asset acquisitions will benefit from our approach to cost control and completions. Turning to page 11, our infrastructure has enabled us to have some of the best EBITDA margins in the business. In the Q2 of 2013, our EBITDA per BOE was $67.55 due to high price realizations and decreasing LOE per BOE. Given the proximity of the new acreage to our existing position, we will be able to leverage our current infrastructure to do more of the same. As we look to grow OMS, the acquired acreage also provides a great opportunity to expand on our saltwater disposal and freshwater systems currently in place and extend them into the new project areas.
On the oil and gas gathering systems, we can quickly tap the existing infrastructure or consider the installation of systems ourselves through OMX. On slide 12, you can clearly see we have a great growth engine here, both organically and through these acquisitions. We have rapidly grown both production and reserves and we expect to continue to grow production reserves on a combined basis. We've added the base production of the acquisition to our previously announced guidance for the 2013 average daily production. We plan to provide more color on production and capital expenditure guidance at the acquisition closing date and in the normal budgeting cycle as we've done in years past.
To summarize, we are extremely excited about these assets and what they bring to Oasis. The size, scale and proximity of the highly economic operated acreage will continue to add value over the life of the asset. With that, I will turn it over to Michael.
Thanks, Taylor. As we mentioned in the press release and we spell out on Slide 13, we completed our mid year redetermination and increased the borrowing base from $1,250,000,000 to 1,500,000,000 dollars The lenders completed their redetermination based on Oasis' reserves and did not include the reserves from the acquisitions. With the pro form a liquidity of $1,660,000,000 including cash as of sixthirtytwenty thirteen, we have adequate liquidity to fund the acquisitions. These acquisitions will add additional borrowing base capacity and we will opportunistically look to tap the high yield markets to fund a portion of the purchase price and free up capacity under the revolver. Consistent with the continued growth in production that Taylor alluded to, we also expect to rapidly delever over the coming years.
Our cash flow has improved significantly over the last couple of years. If you look at our 2nd quarter results, we had EBITDA of 180 $5,000,000 compared to capital expenditures of $189,000,000 From an operational perspective and using EBITDA as a proxy for cash flow, we were nearly breakeven. As we look to the future, we expect to continue a positive trend and assuming realizations and service costs remain consistent, we believe we can quickly be cash flow positive. To protect our cash flow, we continue to add hedges and are up to 26,500 barrels of oil per day in the Q4 of this year and we've hedged on average approximately 21,000 barrels of oil per day in 2014. As the market warrants, we expect to aggressively layer in hedges to protect our drilling program and the acquisitions.
With that, I will turn the call back over to the operator to open the lines up for questions.
Ginger, will you open up
the lines for questions, please?
We do have a question from Ryan Oatman from SunTrust.
Hi, good morning guys.
Good Morning Ryan. Can you
talk about how this acquisition came about, whether it was a process, whether it was privately negotiated, etcetera?
Yes. There's a combination there's a total of 4 transactions here and it's a combination of both.
Okay. And then looking towards liquidity, you guys spent a fair amount of time on that. Certainly, it looks like liquidity is sufficient to fund this deal. Can you speak to your comfort level around debt levels and any target metrics you have for leverage?
Yes, Ryan, good question. We've traditionally kind of said that we're going to stay conservative on the debt metrics. This will take us a little bit more levered. But as we said, we're near cash flow breakeven just based on the 2nd quarter numbers. With this asset that comes in, there's a couple of rigs that are currently on it.
It's in a very similar situation. We expect to get to free cash flow pretty quickly and delever pretty rapidly over the short term. We feel like we've got plenty of capacity from a liquidity standpoint. We'll tap the high yield markets opportunistically. I think we're set from there.
Okay. Thank you. And then one more for me and then I'll hop back in the queue. Can you provide us a roadmap for your down spacing and lower Three Forks test?
What should we expect and when should we expect it?
As we've mentioned, we have a number of down spacing tests currently in progress, 2022 that will be spud this year or into early next year. We are setting up our program for next year based on what we've learned to date and it's variable depending on where you are in the basin. But generally, and as we've talked about, it's around 4 Bakken and 4 3 Forks wells on average. We've got some areas that we're going to drill in 5 in each. And so as we continue the program, we'll refine it over time and we'll give you kind of by areas what that down spacing looks like.
But we think it's on average at least 4 and 4 at this point. With respect to the 3 forks, we've got a lot of tests in the 1st bench, the lower benches. We have 2 wells that we'll be testing in the 2nd bench, 1 in Indian Hills and 1 in Cottonwood in the 3rd and the 4th quarters. And then we've got as we go out of this year and early next year, we have quite a few more lower bench tests that are planned.
Great. Thank you.
Thanks.
Your next question comes from Dave Kistler from Simmons and Company.
Good morning, Dave.
When you think about what you've acquired, can you walk through any kind of transportation agreements they might have had in place? How that might impact realizations? Or how you're managing your current transportation plans for crude out of the Bakken?
Yes. So on the infrastructure slide that we have in the deck, you can see that our asset currently is very well connected both on the gas, oil and saltwater disposal sides. The acquisitions that we're acquiring, the transportation is a little bit earlier in that phase of development. But as you can see, it fits very nicely with our current infrastructure. So we think that we can get those online very quickly.
It also gives us a lot of flexibility of how we want to get those online.
Right. And from that standpoint, I assume that that actually increases your outlook for return on capital employed from the assets you're picking up versus if they were disparate from your current infrastructure?
That's correct. We drive very good cash margins because of our infrastructure program and we think this fits very nicely where we can continue to do the same on these assets.
So if I were to simplify it, just you're looking at these more as bolt on assets even though it's 4 different projects across the swath of your acreage?
Absolutely. You can see the maps. They fill in our acreage position nicely, still large contiguous operated where we can drive the same type of results that we have on our current asset position.
So then looking at incremental investments necessary to kind of tie everything together, How should we think about this with respect to OWS kind of increasing the acreage position by about 50%? Should we assume that you guys will be building out OWS a little bit further to be able to optimize what you've already gained as far as traction on well costs, etcetera?
That's one of the things that we're looking at, Dave. And just like you said with this big increase, it's probably going to make sense to take that step.
Okay.
And then last one
There'll be some short term stuff. There's a as we've talked about, there's a whole laundry list of things that go into that OWS bucket. And there's some of those things that are smaller in scale that we can take advantage of quicker as well.
That's helpful. And then one last one, just can you talk about as you've acquired this, are you bringing additional people on as part of the acquisition? Or do you have the right kind of crews in place at this point to be able to prosecute this going forward?
So, at the in the field level operationally, we'll continue to be continued to be run for a period of time by the current operator. So, it will be a transition at which time we'll take over and very likely we will take some of their employees, but it's we're in good shape as far as picking up the operations and then transitioning as we take that over by the end of the year.
Right. Appreciate it, Jeff.
And then on a technical side, it's it'll be very easy for us or as easy as it can be on a relative basis adding people to be able to scale, which is one of the big advantages to this deal.
Perfect. I appreciate the additional insights guys. Thank you.
You bet. Thanks, Dave.
Your next question is from Scott Hanold from RBC Capital Markets.
Good morning.
Good morning, Scott.
Hey, congratulations on the deal. Thanks.
When I take
a look
at some of the acreage that you acquired, can you talk a little bit about the stuff up in North Cottonwood? It looks like some of the stuff is a little bit further north and you kind of had some core acreage. Is there something you're seeing up there differently now that makes that a little bit more attractive?
Sure. So you're right. It is on the north end of the North Cottonwood position. What we've found is a combination of things with the wells that we've drilled up there over the past year. We've improved our results by modifying our fracs.
And then on top of that, we've really driven our cost down in that area. So our complete cost up there is less than $7,000,000 for a well. And when you combine those two things, it really makes for a track of economics. And so that gave us the confidence that we could take this position and really perform well with it.
When you look
at so you're drilling for less than $7,000,000 And then is are the EURs up there kind of on the lower end of that range that you all provide, sir, in that 5, 125 MBOE?
Is that right? Yes. So the $525,000,000 is the midpoint of the low end of our EURs when you look at the bottom half. On the very north end, those EURs are probably in the 400 to 450 MBOE range. But with the drilling costs that we're talking about, very economic.
Okay. Okay. And then on your plans to I guess increase to a I guess it'd be pro form a 15 to 16 operated rigs. What sort of drove that decision? Was it this acquisition by itself?
Or was that sort of in combination with what you're seeing on the down spacing pilot? Because I know I think the plan had been sometime by the end of the year to early next year, you'd have a better sense of the down spacing potential and then would discuss kind of acceleration. Is this kind of that acceleration? Or there could be another bike to that?
Yes. I think it's a little bit of both. I mean, keep in mind that as we talk about down spacing, even if we go into next year, I mean, it's going to be a little while before you can ever get close to saying with 100% certainty what you've got. I mean, we're going to have to make some educated guesses here. But I think it's a little bit of both in terms of the existing asset and the acquired asset kind of planning for additional density and additional benches, because otherwise that inventory number would years of inventory number would really start to expand.
Yes. What kind of inventory you like to hold when you look at it from a longer term perspective?
We've been kind of staying in the 14 to 15 year range. Now pro form a will be at about 16 at the current rig count. So it's kind of starting to grow into the upper teens, which is what kind of leads you to say, you need more rigs to bring that back in line with where we were before.
Okay. Understood. And then on the down spacing, you had indicated you're testing up to 7 wells per formation in both the Bakken and Three Forks. Are you doing that in the same drilling unit? Or would those be in separate drilling units?
I mean, in theory, are you you're not trying a 7 and 7 in the same drilling unit, are you?
Yes. It's so we've got up to 7 wells in a single formation. It's not a full 7 wells, though it's a subset. So we might drill 3 wells in that closer proximity to test that spacing. And then based on those outcomes, we'll go and drill full spacing units.
Okay, understood. All right. Thanks, guys.
You bet. Thanks.
Your next question is from Subash Chandra from Jefferies.
Congrats again. The midyear reserve report, how many locations well locations were included in that?
For the acquisition?
No. I guess just your base midyear reserves. And if you have both numbers that'd be great.
So, developed 60. So, PUD is proved undeveloped, number of gross wells is 320 2 locations.
Is that up or not up?
Yes. And then net is 206 were undeveloped. On undeveloped, the net number is 302 locations.
Okay. Is it typical that your second half reserve adds exceed your first half or how were you sort of thinking about this year? I think about this
year? Go ahead.
I'm not sure I understand what you
mean by I think that we don't know yet, but just keep it in mind the number of completions that we had in the first two quarters. We had 31 and then 20, so 51 out of 128. So obviously, as we've been telling you guys, we're going to kind of be back end loaded. So not unreasonable, but it's a little bit too early to tell.
Right. Okay, good. That was good. And just to be clear, that was on the 151,000,000, the number of net PUDs and PDP were on the 151,000,000 barrels?
That's on the 100 and well, the total reserve number is 169,000,000 barrels. The number is 88.
Okay. And you might have answered this. I might have missed it. But can you talk to some background on how long the property was on the market? And it looks underutilized.
I mean 2 rigs for half your acreage. You're doing quite a bit more on twice the acreage that you have. So safe to say that the current production number doesn't really reflect what even current productivity of the field could be?
Yes. I think that's fair. I mean, it's you've hit on it Just from a rig intensity standpoint, if you want to call it that, a bit lighter than most of the other positions in the basin. And so not nearly as far along on pad development when you say that Taylor?
Yes, absolutely. They've got across our position one well drilled per space and unit. And as we mentioned most of the acreage is already held. So it's now in a perfect position for us to come in and down space. So all that work that we've been doing on our acreage as you can see from the map, this is right in the middle of what we operate.
So what we're doing translates directly into this acreage for down spacing.
Okay. Thank you very much.
Your next question is from Noel Parks from Ladenburg Thalmann.
Good morning.
Good morning, Noel.
Just a few things and my apologies also if I missed some of this earlier. The transactions are these 4 separate sellers or 1 seller with a couple of different packages?
4 separate sellers.
Okay. And the production, the 9,300 a day of current production on the acreage, is that all Bakken and or Three Forks? Or is some of that legacy from other formations?
Yes. There's a little bit of shallow production or legacy non Bakken Three Forks production, it's not a big number.
Okay. And the I don't know if they're similar or if they vary, but the sellers, how early did they start their Bakken, I guess, horizontal drilling? And were they in the early sort of the early wave of working the play or just more recent years?
I think it's fair to say that it was earlier on. You can look at the position on the west side and just tell by the magnitude of it and the position of it that that had to be put together relatively early in the process In terms of evolution of drilling activity, obviously, more evolved on the west side than the east. Just going back to what Taylor talked about in terms of North Cottonwood and coming up with that EUR cost combination to come up with the right structure to make that economic or get it back into equivalent type economics.
Right. And sort of along the lines of an earlier question then. So if they were part of the earlier wave for the most part, then it does seem reasonable to expect that the 9,300 a day of production with up to date drilling and completion methods, drilling a similar number of wells like a larger production amount is what you'd expect out of that, right?
Yes. I think that is right. If you had a if you just picked rig intensity by the different operators in and around these areas, just rigs per net acre, I think you'd find that the rig intensity here has probably been a bit muted.
Okay. And then also, with the existing production I don't know what the average well age is. So but is enough of it past its big 1st year decline that this is a fairly stable production base? Has the volume On
a relative basis, yes. I think it's fair.
Okay. So they've made their way sort of if not to their tail sort of they're well on their way then?
Yes. The decline on those that production won't be that different than our current production. It will be pretty similar curve.
It will be pretty similar. Okay. And just the last one then. So looking at the map and sort of the holes you've plugged, if you will, with the new acreage, I'm looking at, for example, the Painted Woods area. Just geologically, I mean, can we sort of just assume a trend, I don't know, I guess, north to south comparing say Red Bank and the areas to the south?
Or are there any special geologic features in there that we should be aware of that would mean you wouldn't have continuous sort of depth progression or formation progression across the areas?
So painted woods, for example, as you trend from east to west, you're getting shallower. On the East side of that block, it's higher EURs more like Indian Hills. And then as you head towards Montana, you get closer to the 500 MBOE range on the west side of the block.
Okay. Thanks. That's it for me.
Thanks.
Your next question is from Ron Neals from Johnson Rice.
Guys. Good morning, Ron. Question, you get to 13 rigs with the closing of this transaction. What kind of pace would you hope to move with to get to the 15 to 16 rig count that you expect to have by the end of 2014? Is it something you expect to do for or be at that level for most of the year?
Or is it something that you would expect would build over the course of 2014?
So it's likely we're going to hold at 13 through the winter and then pick up additional rigs once we're past breakup in the summer. So you'd have probably 2 additional rigs at some point in the summer.
Okay. And then either Tommy or Taylor, on the acres that you talk about the 33,000 acres that's the 2nd bench of Three Forks and below and the 12,000 acres that's shallower rights. Can you give a little more color in terms of where each of those parcels are located the shallow versus the second bench and below?
So the 33,000 acres is kind of spread around different areas, but it's in Foreman Butte, Indian Hills and Painted Woods. It's I don't know the exact split, Ron, but it might be kind of 3rd, a 3rd, a 3rd between those areas, but it's spread around a little bit.
In the North Cottonwood area though, I'm assuming the 12,000 acres of shallow rights is more around the legacy stuff that's probably around North Cottonwood is that?
That's over on the that would be over on the west side as well. The North Cottonwood stuff isn't where we have the depth segregation.
Okay, great. And then as it relates to the deeper rights on the 2nd bench and below and when I look at that relative to the slide showing the Lower Bench Three Forks activity, it looks like some of that acreage then would also be centralized around where the lower benches are currently being tested both by you and by industry?
Yes. So some of it is in those areas.
Okay. Perfect. And then lastly from a production standpoint, Mike, I just want to make sure I didn't miss anything. The numbers in your presentation all relate to 2013. And is it I think Tommy mentioned you may come out with a 2014 CapEx and outlook once the deal is closed?
Just want to make sure I heard that correctly.
Yes. The numbers that you see are related in the presentation are related to 13 and will come out kind of normal course. We'll have more information that comes out kind of at the closing of the deal and then we'll also go through kind of our normal course in terms of 2014 as well.
And does this have any impact on the pace of your build out? Or would you expand build out of your infrastructure not only obviously to from on the gathering side, but does this impact the way you view infrastructure as a part of your whole corporate makeup going forward?
Yes. Infrastructure obviously a very a core focus area for us over the last few years. We've done a great job of getting all those online in a big way. We'll continue to do that. OMS that we formed early this year has focused more on saltwater disposal for us currently.
And but we will continue to look oil, gas and water for OMS and see what makes sense versus using third parties.
Perfect. All right. Let me let someone else jump in. Thanks guys.
Thanks Rod.
Your next question is from Irene Haas from Wonderlic Securities.
Yes. Just kind of wondering how we should think about 2014 CapEx. Would it be a bump up of 30% or 40% just wondering? And second question is, would you be able to get all your infrastructure work done before the winter arrives because it can get kind of crazy up there? So just kind of wondering how seamlessly you can fold in your new assets.
And by the way, congratulations on a really very nice bolt on.
Thanks, Irene. Go pick up on that.
Yes. So on the capital side, we've been saying that think of our program for next year probably being just Oasis standalone about the same. And then if you there are 2 rigs running and then we're going to pick up 2 additional rigs, like we said, next summer. So that's you add all those pieces together, you can do the math.
Okay.
And then from an infrastructure standpoint, it is a little bit less mature on the infrastructure side. It's unlikely that you can get it in before winter, but we can certainly put that all in a pretty timely manner over the next call it 12 to 18 months.
Great. If I have one more question to follow-up just for clarity. Your gross operating location of 28, roughly 100 locations growth. How many that's a conservative well count, right? You only count to say 4 Bakken, 4, 3 Forks and probably sticking with 1 bench.
Can you please help me with this?
Yes. That inventory is built on exactly like said Irene 4 Bakken and 4th 1st bench of the 3 Forks wells currently. Obviously, we're doing a lot of work on the in fill testing and lower bench testing, but that's none of that's in our inventory numbers.
Great. Thank you.
Thanks.
Your next question comes from Dan McSturray from BMO Capital Markets.
Good morning, folks.
Good morning.
Going back to the balance sheet, can you paint for us say maybe a more detailed picture on what leverage looks like over the course of 2014? And how or where it sits at the end of next year assuming I guess you tap the high yield market to more permanently finance this acquisition?
Sure. It's going to get right at the close of the acquisition closer to 3 times as you get into 14. You're going to delever pretty rapidly and you're going to be kind of in the mid-2s and we'll just continue to watch that. But we've got to we'll have a lot of liquidity if we are able to opportunistically tap that high yield market like you said and term some of that out. So we'll have a great liquidity position and we'll continue to watch those leverage levels pretty closely.
The good thing is that we will aggressively hedge So we'll lock in a lot of the cash flow. We kind of talked about where cash flow is. We're close to breakeven as of the second quarter. We think we can delever this asset pretty quickly.
Got it. And as a follow-up, I believe you spoke about 2 Lower Three Forks bench well tests underway on the acquired leasehold and stated they were performing in line with other tests. Can you relay or speak to any details on recoveries maybe both in the aggregate on those wells and maybe per stage?
Sure. I don't know if you can add per stage, but the 2 wells we're talking about are the Patxi and the Omelet. The Patxi well is the 2nd bench well. It was a 25 stage frac. And when we look at the recovery on it or EUR, it looks like it's going to be probably between 400,000 and 500,000 barrels maybe to the mid range there.
And then the 3rd bench well, the omelet was a 35 stage frac well. And it looks to be obviously more stages, but looks to be a little better than the Patsy. So more like the upper end of that range around 500. Still early, but really encouraging results from both of those wells.
Got it. Thank you.
Your next question is from Andrew Coleman from Raymond James.
Good morning, folks.
Hey, Andrew.
Question on, I guess, the new ventures team. So they definitely have earned their dinner here with this deal. Do they get a break? Are they back to the grindstone? And is this the time that they might start looking outside the basin?
No. Yes. And they're probably going to be pretty darn busy working around optimization on 500,000 acres. Okay.
And now being that you've reached that size, are there more packages of this magnitude out there that you guys see in your crystal ball? Or I guess secondarily, how big would you see yourself getting in the future? Or could you
get?
Well, on the first one, I don't know that there's that much left out here that's of scale. Just as you look at a map of the basin, I can always get surprised I suppose. But and then hey, it's kind of like what we told everybody on the heels of the IPO. It's head down to execute on what we got. A little bit early to talk about how big we could get.
Okay. Fair enough. Thank you for your time.
Thanks, Andrew.
Your next question is from David Heikkinen from Heikkinen Energy.
Good to talk to you. And it looks like a good acquisition. I was looking at kind of the culmination of Zenergi as a series of partnerships and then some of the land discussion that you had of different rights and ownership at those depths. Can you kind of talk through the integration of these assets and kind of the 100 and 61,000 total acres, 116,000 that had rights across all depths. And then I think Noel or Ron asked about the 33,000 that had 2nd bench.
But just kind of the progression of how this came together and then really just how that kind of the severing and kind of the additional details in your presentation around what the net acres are in the different areas across all depth?
Yes. So I would say on all these things, it's been a bit of a process that's probably depending on which package it is that's been going on for, I don't know, 12 months or some of them a little bit less, some of them a little bit more. So it's been quite some time that the guys have been working this stuff. As you think about the shallow rights, there's a couple of 1,000 acres in that 12,000 there's a couple of 1,000 in Red Bank. There's about 10,000 in Foreman Butte and that's all of it.
As you look at just the call it the on the West side, so there's 136,000 acres cut out the shallow only. There's 124,000 acres. And if you look at it and just look at the slide on what is this page 4 and tracked out the 2 and the 10 that I just gave you. When you look at the where you have depth segregated, which is a function of a farm out, there's about 2 thirds of it in Painted Woods and Indian Hills that goes away. But keep in mind that it's where we've got depth segregation through Middle Bakken and First Bench of the Three Forks, we still have the deeper benches.
And so again, as we've talked about, I mean, that's one of those optimization items that we've got to get the guys behind.
Do you think there's an opportunity to kind of aggregate net interest across that acreage? And is that something you're planning really just trying to acquire some of those farm outs and really just increase net?
Absolutely. We've got a our land group has done a great job historically and we talk about it all the time in terms of trades that we do with other operators in the basin. Now historically those have been mostly one for 1 in adjacent blocks. And obviously when you're talking about depth segregated acreage that ratio won't be one for 1, but we've got a pretty good history with all these guys of being able to use swaps to consolidate and so that will be a big part of what these guys are doing.
Okay. That's helpful. Thanks guys.
Your next question is from Drew Venker from Morgan Stanley.
Hi, good morning. I was hoping if you could talk to in your downstream test, if you've seen any evidence of depletion or communication pressure drawdown things like that?
So far for the test that we've done, we haven't seen any indications of that. But it's early in the test and you'd really expect to experience that further out in time. But based on what we're seeing so far, not just on spacing, but all the data that we're gathering, oil in place, looking at microseismic, modeling work, simulation, all those things and you put that package of stuff together, we're encouraged. And like I said, we think it's on average at least 4% and 4% are going to be better than that in certain areas.
Okay. And we have some more detail you can offer by early next year or I guess when do you plan to talk in more detail about results of those tests?
It'll be probably in the next year sometime. We're like Tommy mentioned earlier, we'll go ahead and based on our early results, pick spacing for each of our areas and go ahead and start drilling out some of our spacing units based on what we know now and then we'll just continue to refine that every year.
Okay. So I guess right now it looks like you have fairly deep inventory if you are corrected on at least 320s working and maybe lower benches work, maybe 160s work. How would you go about bringing forward that value?
Yes. So that goes back to what we talked about a little bit earlier that if those things work then your inventory life is going to start to grow from 15%, 16% -ish to high teens. And so then you got to start looking to run additional rigs or increase project count is probably the better way to say it. If guys keep getting efficient like they have, then you don't need as many rigs to do the same amount of work. But obviously, as you start to get to inventory numbers like that within your financial capability then you got to start thinking about opportunities to accelerate.
So I guess the point being was
I'd say not accelerate really. I mean it's add rigs to execute on inventory growth.
Right. So I guess what I was getting at was, so in that case, in the optimistic case, would you consider raising capital to accelerate? And is that would you want to raise more debt or would
you think
of the equity market?
Yes. What I would tell you is in the timeframe that it takes for us to get some resolution around that inventory, There's a lot of things that will mouse around from a financing and market standpoint. So I think it's a little bit early to make that call.
Okay. And just one last one. Some of the operators have had success with slickwater fracs. I think particularly it's applicable to some of the acreage on the western side of your block and some of the definitely some of the acreage you acquired. Are you testing that some of those liquid refracs now?
Or do you plan to?
Yes. I'll let Taylor chime in, but we have done a little bit of that. I think the one thing that you've got to be mindful of is that it's not just EUR, it's cost structure. So we are testing that, but we got to make sure that our cost structure is right. You got anything to add?
That's accurate. We're testing slickwater fracs. We're looking at what all of the other operators are doing around the basin. And like Tommy said, we're focused on economics and in the finding and development costs in the wells. And so that's the formula we're using to optimize across the position.
We'll continue to do it on these newly acquired assets.
Okay. Thanks.
Thanks.
Your next question is from Ray Deacon from Breen Capital.
I just wanted to make sure I understood the location count of the 2,150 net operated and non operated locations. Does that include wells that are currently online and producing? Or is that a go forward number?
That's inventory. That's drilling inventory.
Okay. Drilling inventory of undruded wells. Got it. And I guess, you talk about the lower Three Forks and being perspective across all of the acreage, I guess. Do you have a sense of kind of how much has been proven so far, I guess?
Guess, kind of maybe over the next year, how much of that will be in kind of the proven category, I guess, in your mind?
So the area that's got the most tests and you can look on Slide 9 is really a kind of central part of the basin and that's in and around our Indian Hills area. And then you can see the blue addition on the map and that's where in that blue addition there's the 2nd and the 3rd bench test already. So feeling pretty good about that area, the central part of the basin. There's you can also see on the map quite a few other tests that are kind of branching out early in time on those, but we're optimistic. I mean, that's I can say at this point, We'll continue to test the lower benches and get a firm idea hopefully within the next year or so what that looks like across the position.
Okay, great. Thank you.
Our next question is from Ron Mills from Johnson Rice.
Hi, Michael. Just one clarification. You mentioned in your comments about still being the visibility to the free cash flow point is still pretty short term. I think you had previously been talking about sometime by the end of 2014. Does this transaction really change that very much given the growth in cash flows that and the fact that A, the fact that these 2 rigs are self funding, it sounds like and B, that the growth will accelerate further?
Or does it get pushed out?
No. That's a great point Ron. Like you said with the current 2 rig program being pretty self funding, it doesn't really extend our breakeven cash flow date. And so what we're kind of saying is that 2nd quarter is pretty close with these current differentials and realized pricing. You're actually pretty close now and we'll get there very quickly in a call it lower oil price $90 ish oil price you're going to get there sometime kind of probably later in 2014.
But this asset itself won't really extend it.
Perfect. Thank you.
Thanks, Ron. Okay. Well, let's wrap up here. We're very excited about what these acquisitions will mean to our company once they're closed. All the assets acquired fit extremely well with our current positions and will provide significant benefits given the large contiguous operated blocks with high working interest, highly economic and price resilient inventory and substantial upside with known catalysts.
And organizationally, I think we've shown that we have what it takes to integrate and execute on the acquired positions. Oasis continues to differentiate itself as one of the premier operators in the Williston Basin and these acquisitions supplement our ability to add incremental value for our shareholders. As always, thanks for everyone's participation in our call today.
Ladies and gentlemen, thank you for participating in today's conference call. This concludes the call. At this time, you may now disconnect.