Good afternoon. My name is Toni and I will be your conference operator today. At this time, I would like to welcome everyone to the 3rd quarter 2013 earnings release and operations update for Oasis Petroleum. 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, Tony. Good morning, everyone. Today, we are reporting our Q3 2013 results. We're delighted to have you on our call. I'm joined today by Tommy News and Taylor Reid as well as other members of the team.
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 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 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 or on our website. I'll now turn the call over to Tommy.
Good morning and thanks for joining us today. It's been an an exciting and important quarter and year for Oasis. We entered this year knowing it would be a transitional year moving from acreage capture to acreage development and and optimization. With our recent acquisitions totaling 161,000 net acres in the heart of the basin, our year is now both transitional and transformational. The team has continued to make progress on multiple fronts, including improving capital efficiency, further resource understanding through down spacing and lower bench work and increasing value through acquisitions and acceleration.
1st, as we noted in the press release, well costs continue to move down across our position. Additionally, we have lowered spud to rig release down to 21 days in the Q3. Our improved efficiency and optimization work has reduced total well cost to $8,000,000 per well before taking into account OWS, which lowers cost by another $500,000 per well. Having hit our year end 2013 target well cost of $8,000,000 already, we continue to have confidence in our ability to get to 7.5 $1,000,000 by the year end 2014, both those numbers being before the effect of OWS. Additionally, we now expect to hit our production targets for 2013 with $40,000,000 to $60,000,000 less in capital than our original $1,020,000,000 budget even when we include capital for the 5 additional wells that will be completed on the acquired assets in the Q4.
2nd, we are more optimistic about the potential for inventory growth as we progress our down spacing efforts, do more work on the lower benches of Three Forks. We've been encouraged by the results of the downspacing test we've completed to date and Taylor will cover that in a bit more detail momentarily. And third, we are encouraged by our ability to capture additional resource through both acquisition and acceleration. Michael will give you an update on our acquisitions, but we continue to be excited about the opportunity to develop the 161,000 net acres that we acquired around the end of the quarter. All of the work we have done on our position is relevant to development of what we just picked up.
As we integrate the assets, capitalize on our capital efficiency and resource understanding and grow our drillable inventory,
we believe it
is prudent to accelerate the rate of development across all of our almost 500,000 net acres. Between the 11 legacy rigs, the 2 from the acquisition and the incremental rig we just picked up, we're currently running 14 rigs. With the addition of the 2 rigs we expect to pick up in the back half of the year, we should exit 2014 with 16 rigs. With these rigs and the continued improvement in drilling days, it looks like we'll be able to spud approximately 210 gross operated wells next year, of which approximately 80% to 90% will be on pads. With that, I'll hand the call over to Taylor who will discuss our operational results and some preliminary thoughts for 2014.
Thanks, Tommy. The team delivered another great quarter. We completed 38 gross operated wells with 29 of these wells or 75% of the total on pads. While the total completions came in a little light of expectation, we still came in just above the midpoint of our guidance range of 33,000 barrels equivalent per day. With the momentum of increased activity in the second half combined with our recent additions from acquisitions, we are projecting 4th quarter production to be between 4,200,000 and 46,000 barrels equivalent per day.
We are currently producing 13 of the 22 spacing tests planned for 2013. Early production from these well tests has been positive with wells performing in line with wells previously drilled in their respective areas. Early production data coupled with our modeling work is suggesting that it will take more than 4 wells per horizon to drain the Middle Bakken and First Bench of the Three Forks in many areas of the basin. We will give more color around our plans as we roll out our 2014 program in January, but it is safe to say that the bias on well density is up from our current standard of 4x4. We even have a few DSUs that will test as many as 15 to 20 wells in a spacing unit with 5 to 6 wells across
each
and core work indicate there is a significant amount of resource in the second and third bench of the Three Forks across parts of our acreage. In Indian Hills, we have 2 second bench tests currently on production, the Pat C and Paul S wells. And onethree bench, the Omelet online as well. All three wells look similar to 1st bench wells in the area. The Patsey, Paul S and Omelette produced 784, 712 and 804 barrels equivalent per day respectively during the 1st 30 days of production.
The Bonita well in North Cottonwood, the 2nd bench test is not yet completed, but will be online in the Q4. We are also currently drilling a 3rd bench test in South Cottonwood that includes a core through the full Bakken and Three Forks section. In the next two quarters alone, we plan to drill an additional 15 lower bench wells. And as we look to The transition of pad development has been remarkable and continues to progress. As I mentioned, we drilled 75% of our wells on pads in Q3, but that will increase to 80% to 90% in 2014.
Recent advancements include an 8 well pad where we executed simultaneous operations for the first time. The team put up some great results with spud rig release averaging 19.2 days frac days averaging 2.6 days per well. The first well that we drilled in the unit was on production in just 105 days. We were able to cut the time to first production in half and bring forward production nearly 15 weeks compared to a pad not utilizing simultaneous operations. Advancements like SIMOPS will be important as we drill more large multi well pads.
Even so, as previously stated, pad operations lead to lumpy growth and that combined with winter operations and spring breakup will lead to backloader production again in 2014. Improving upon the efficiency gains of simultaneous operations will be important in helping us to deal with unevenly loaded pad operation. It is also important to remember that we remain focused on well performance and well returns. We have performed a variety of completion styles in order to find the optimum frac design for each area. Along with other operators, we have tested a number of new frac techniques.
We will continue to monitor results and modify designs when economics of the wells warrant to change. Finally, given the success of OWS and our increased activity, we have ordered a second frac spread. It should begin operations late in Q2 of 2014 and when combined with our existing frac spread should have handle approximately 50% to 60% of our wells. The decision to add a second crew was obviously pretty easy given our success with our first crew. As you can see, we have a lot of exciting things on the horizon.
With that, I'll hand the call over to Michael.
Thanks, Taylor. I'll begin with a brief update on the acquisitions. The closing of the West Wilson acquisition was on October 1. Other than production guidance provided by Taylor, we are leaving all other financial guidance ranges the same for the full year. To fund the acquisitions, we raised $1,000,000,000 of senior notes and drew approximately $600,000,000 on our revolver with $145,000,000 of pro form a cash after the acquisition and $900,000,000 of availability on the revolver, we have more than $1,000,000,000 of liquidity to fund our accelerated drilling program.
While we have ample capacity under our revolver for to fund development, we also remain focused on maintaining a strong balance sheet. We discussed our intent to delever through growing production over the coming quarters when we announced our 4 transactions in September. And we also commented that we intended to aggressively hedge in the near term. We were able to lock in some attractive hedges over the past 2 months, adding contracts of about 6,500 barrels per day in 2013 and about 3,500 barrels per day in 2014. We've also looked for other options to help delever.
In fact, you may have seen that we recently put our non operated position in Sanish on the market. We just started this process, so we will see how it ultimately shapes out. The 4 acquisitions that recently closed added large operated blocks adjacent to our own, increased our inventory by 42% and provided us an opportunity to add scale in an area we're familiar with. As we leverage the strength of our operating abilities, the assets are an important component to our resource conversion strategy. The acquisition added approximately 854 gross operated well locations and 54 gross operated well locations to our inventory in some of the best areas of the basin.
And our drilling spacing unit inventory has grown by 119 to 399 units. With the acquired assets, we are determining the best options for developing the infrastructure. Our team has done a phenomenal job on our legacy assets and we can take the best practices to the new assets where we can either put in infrastructure via in house efforts or through third party build outs. For National Gas, Oasis standalone has over 95% of its wells connected to pipeline and the West Williston acquired assets are connected at a similar level. For oil, Oasis stand alone had about 85% connected to pipe as of September 30, whereas the West Williston acquired assets were just over 25% connected.
There's an opportunity over the coming quarters years to get this number up and the team is actively working on options now. We're obviously trucking a little bit more now, which drives differentials a little wider than they otherwise would have been going into the 4th quarter. We now have almost 60% of disposal water on pipeline and almost 90% going down our own disposal wells. The acquired assets are a little behind us with about 40% on pipe and 60% going down own disposal wells. We'll be able to invest in saltwater disposal infrastructure on the position next year to help drive down LOE, which will be a little inflated from normal levels in the near term.
Looking at the 3rd quarter results, our realized oil price averaged 100 point $7.5 per barrel with about a 5% differential to WTI. As most of you know, differentials have been very tight since the Q4 of 2012, but they have recently started to tick up. We're expecting the 4th quarter to widen out a bit as compared to the 3rd quarter With WTI and Clearbrook to coastal markets spread gapping out again, we've shifted from as low as 40% rail in the Q3 to more than 90% on rail for November. This enables us to take advantage of the premiums the coastal markets are getting relative to WTI. On the cost side, LOE ticked up a bit in the quarter to $7.18 per BOE.
This is primarily the result of costs associated with more frac protect activity while drilling offset wells. As we drill new wells close to producing ones, we'll continue to experience some frac protect costs. Adjusted EBITDA grew to a record $220,000,000 as we realized $72 of EBITDA per BOE sold. To close out, we have a lot of good things in store for us and we're confident in the direction we're heading. With that, we'll turn the call over to Tony to open the lines up for questions.
Your first question comes from the line Philip Johnston with Cap One.
I just wanted to get some clarity on your Q3 CapEx figures that you provided in the table. Just two questions there. First, on the $127,000,000 of acquisitions related to or I guess the CapEx related to acquisitions, is that just cash paid for the East Nesson properties and the deposit on the West Wilson transaction? Or does that also include some actual CapEx that you incurred on the East Nesson properties after you
closed it in September? No, exactly right, Philip, what you said first, which that is the Eastside acquisitions, the payment for that as well as the deposit for the West Williston side. Obviously, that closed October 1. So you'll see the full amount of that CapEx in the 4th quarter numbers.
Okay. So the clean sort of E and D CapEx
is more like $244,000,000 or so. I was just trying to square that number to the $8,000,000 per well completed cost that you achieved in the quarter. If I take the $244,000,000 and divide that by the $29,600,000 net wells that you brought online, sort of implies a little over $8,200,000 per well. So I was just wondering what the delta is. I mean it's probably just a timing difference in terms of CapEx allocation from quarter to quarter, but I just
wanted to clarify that.
Yes, there's some of that and there's some infrastructure cost in that number as well. So as you back out that for the saltwater disposal infrastructure that we put in, as you back that out that's
how it rectifies. And then you mentioned additional lower Three Forks benches next year. And I may have missed this, but did you say what the percentage mix will be between the various benches within the Three Forks? And just as a follow-up, will most of those lower bench tests be single well tests like the 4 that you drilled? Or is the plan to move more towards sort of multi well, multi formation density pilots like some of your peers in the field are doing?
So, we didn't talk about the percentage of wells that will be lower benches. It did say that the next few quarters you'll have 15 wells drilled in the lower benches. Overall, Three Forks and Bakken well count will be roughly fifty-fifty pretty well balanced. In the areas where we have greater confidence in lower benches, We'll be drilling out some
spacing units where we'll drill
across all the horizon. So middle Bakken, 1st bench, 2nd bench and potentially 3rd bench. And then in areas where it's we don't have quite as high a confidence, it will be more one off type of wells testing the lower benches in those areas. So right now the greatest confidence is more in our Indian Hills and South Cottonwood areas and we're testing some of the other areas in lower benches. Okay.
Makes sense. Thanks.
You bet.
Your next question comes from the line of Dave Kistler with Simmons and Company.
Good morning, Dave. Dave, are you on? Yes. Can you hear me? Yes.
We are.
Yes.
Okay. Sorry about that guys. If I look at the 210 gross wells you're drilling next year and the cost estimates you guys have put out adjust for working interest kind of gets you to somewhere between $1,100,000,000 to $1,200,000,000 for CapEx before infrastructure etcetera. Is that a good way to start thinking about 2014 program?
Yes. That's not bad. I think you're I mean it's pretty straightforward. But I think you're in the range.
Okay. I appreciate that. And then as we think about the guidance for Q4, what was the what is the current or exit rate of the acquisition in terms of a production basis? I think at the time you announced the acquisition it was about $9,300 Has that declined since then? Where do we sit on that as we think about production going forward?
So that it's right now it's pretty similar to what we announced at the time of the acquisition. So it's in that same range. However, as we progress through the Q4, on those assets we're drilling on pads and so it won't have as many completions as we might otherwise have. So it may see that drop off a little bit, but we've got the ability to make that up on our remaining assets.
So it will be kind of flattish, yes.
Okay. I appreciate that. That's helpful for understanding what your base growth is from the original asset base. And then just one more. As we think about completing less wells in Q3, was that just the nature of some slipping into Q4?
And what does that mean with respect to possibility that Q4 comes on maybe stronger than anticipated or really more so with the acceleration in rig count 2014 coming on stronger than anticipated?
Yes. I think it yes, I mean a lot of it is just timing of well when wells come on relative to a day that's the end of the quarter, we are still pretty close.
We are still
targeting the 128 for the year, so we'll catch up. And then I think there's 5 incremental Brett that are on the acquired assets. So the original 128 plus 5 will kind of put you in the range for the Q4.
Okay. So that the slippage of those didn't have anything to do with the CapEx reduction. It's purely drilling efficiencies that are driving the CapEx reduction? Yes. Okay.
That's very helpful. I'll let somebody else jump on. Thanks guys. Good
Your next question comes from the line of Noelle Parkes with Ladenburg Thalmann.
Good morning. Good morning.
A couple of things.
Let's see.
Overall, given that you enjoy such a nicely concentrated acreage position, What's probably the biggest advantage that you guys can exploit there compared to your competitors who are sort of more far flung? Is it just getting to full development faster, gas takeaway being simpler?
No. What I'd tell you is that it's a couple of things. One is just we still tend to have a few surprises. We still tend to have a few surprises. But then the other one I think that's probably the biggest thing is just infrastructure.
Okay. Whether it's gas, oil, water, water gathering, water distribution, the whole bit, but I think it's largely infrastructure.
Yes. Infrastructure is big. Having concentrated positions is also going to help out as you go to drilling at density on these spacing units where you've got to take into account offset wells with Frac Protect and having a concentration of your own wells you don't have to deal as much with you impacting third parties and then impacting you as well. You can control that. So that helps out.
Right. Great. And
I don't know if you touched on this already. I hopped on a little late. But as we look ahead to the year end reserve bookings, I'm just trying to think through you've got a lot of drilling, so I'm thinking just a number of locations on the pad side should grow considerably. So I guess the 2 things I was wondering about is as far as sort of the 5 year booking limit, just a sense of how much I don't know how you quantify it. How many of the locations are going to wind up in probables that kind of in a more unlimited capital situation would be in the proved or the PUD area?
And then also whether you expect you're going to see significant performance improvement bookings?
So when you look at our overall reserves, we're not in a position to comment on what it's going to be at year end. We're at a little over 215,000,000 barrels currently. Our PUDs relative to overall proved is at 47%. And when you look at the number of wells that we have booked as PUDs relative to the number of wells we drill in a year, you would burn through that full amount if you drilled all those in a couple of years. So staying within that 5 year window is really not going to be a problem for us.
Okay. And the performance improvement?
We like I've talked about in the past, we are consistently focusing on improving the results on our wells. So doing that through stimulation, looking at optimizing fracs, both what we're doing and then what other operators are doing in the basin. And so we've got to focus on trying to improve that all the time, but I can't tell you give you a projection about where that's
going to go. Yes. Keep in mind that our reserves are prepared externally not audited externally. And they're going to largely work off of the historical performance. So it's I mean, it's not like we're rolling into PUD some expectation of performance improvement.
It's largely working off of the historicals. Wasn't that accurate, Brett?
Your next question comes from the line of Michael Hall with Heikkinen Energy.
Thanks. Good morning, guys. Hey, Michael. Let's see. Yes, first, noteworthy, let's say, shift in posture around density tests and bench tests and your game plan on that?
How quickly do you plan on testing the I think you talked about a 15 to 20 well unit. How quickly are
those sorts of tests going to make their way through the system?
So those we've got a couple of units that we'll drill at pretty high density, but they're second half of the year next year. We'll be able to drill them in it would be about 6 months or less to work through because we're going to apply multiple rigs to get them drilled in a reasonable amount of time so that we don't have too long of a lag between the first spud and those units and then get the first production.
But you won't see impact from those until 2015. Keep in mind Michael, as Taylor talked about we've got about 15 lower bench tests over the next couple of quarters. And so that will be helpful in kind of how we lay those things out going into the second half of next year. Okay. That's helpful.
And then I guess somewhat related then on the 210 gross drill wells any rough numbers or percentage of how many get completed in the year? And how those are spread out broadly through all of your different areas?
So when you look at the total count, you're probably because of the pad drilling and especially those big units I was talking about that are going to be over at the end of the year if things work out like it looks like you're probably going to be more in the 180 range in terms of completed wells versus the 210. But we're still working through all that and that's the kind of data we'll be able to give you when we talk about our budget in February. As far as mix throughout the year, again it's going to you're going to have back loading effects because of winter operations and putting as many of our wells on pads as we can during the breakup period. So more wells completed in the second half.
Okay. And then any relative emphasis in any of the kind of sub areas within your acreage position? Or is it going to be pretty well spread out throughout the whole acreage position?
So we're trying to achieve a pretty good spread with the 16 rigs. But we can again, we can give some more color on that when we come out with the budget in early next year. Fair enough.
And then do you have kind of comparable last one for me, comparable big IP30s be offsetting 3 Forks wells relative to those deep tests you highlighted? You mean from other operators? Yes. Or yourselves or prior wells drilled nearby. Just trying to understand kind of how those wells
are going on. So for example, the Paul S well, you had a 30 day IP of 7 12 barrels a day. There's 2 area 2 1st bench wells around it. The Polish was a 2nd bench. You have 2 1st bench wells that were around 7.75 barrels a day for a 30 day average and you had one well that was about 1100 barrels a day for a 30 day average.
Okay. That's helpful. Appreciate it.
Thanks guys. Got it, Michael. Thanks.
Your next question
Your next question comes
from the line of Tim Rezvan with Stern, Aegis.
I had a quick one just on the Sanish assets being marketed. So should we assume that's all, I guess, 8,000 net acres in about 2,800 barrels of production? That is what we have, yes, on the market. Okay. Okay.
Appreciate that clarity. And then should we think about that, that that will help fund the infrastructure ramp that you signaled on the recently acquired acreage? Yes. That's just something that we're looking at that will just help with the balance sheet overall, Tim. Obviously, that's a great premier asset and we expect it to be highly contested for.
So that will help us with our liquidity and helping us delever the balance sheet too. Okay. I'm just asking it in context because you can see the debt to EBITDA 2014. And I guess should we look at I guess recent ratios in that 1.5 times range as management's comfort level? Yes.
We've kind of said that we'd like debt to EBITDA to come down to under 2 times and that would be a level that we're comfortable with. And like you said, we know that as production grows, we can see that coming down over the next coming quarters. So this is just one of those things as we're accelerating, we feel good about the inventory continuing to accelerate a little bit. Like you said, there'll be some infrastructure build. So just kind of managing CapEx and the cash flow outspend and managing that balance sheet.
Okay. Thank you for the color. You bet.
Your next question comes from the line of David Snow with Energy Equities Inc.
Hi. Could you give us a little color on the completions that you're experimenting with the different ones that you and others are doing is submitted liners a big part of that and more profit per foot or different frac fluids. If you can help us then and what kind of responses might you have gotten so far?
Yes. So we've actually experimented with all those things you talked about. Some of the recent things you've heard industry talking more about have been slickwater fracs and then higher fracs with higher profit concentration, higher just bigger fracs overall. We've experimented with those as well as looking at all of the other operator data in the basin. And that's where we come back to making we'll make adjustments to our typical fracs by area based on what we see with all that work.
And we don't not in a position to talk about what results are for each of those individual frac valves other than tell you that we're optimizing relative to what we see in each of the areas in which we produce.
Are you liable to see some increase in your IPs and EURs as a result of all this?
There's when we look at the data, some of those frac styles in some of the areas do increase IPs, but they can also have other effects like higher water cuts. And then along with it you've got higher cost. And so you've got to balance the higher cost versus not only the IP, but what is going to be the EUR and the wells? Is it just acceleration? Are you really increasing reserves?
And then what's the economic impact? So for us, we've got type curve ranges that we've been using and those are we haven't changed those at this point. If we get to a point where we really see a significant uptick, we'll let
you all know. And is Landers a big part of this? Or have
you been doing that all along? We've used we primarily use 12 packers, but we have done similar liners, probably 10 to 15 wells overall looking at the results. But right now our standard completion is still as well factors.
Thank you. You bet. Thanks.
Your next question comes from the line of Ron Mills with Johnson Rice.
Good morning. As it relates to
the downspacing, you have 13 of the 22 are online and yet you talk about encouraging results. Were you expecting much if any degradation as you're going through this? Are you positively surprised or not? And then corollary to it is given the fact that 38 completions during the Q3, you were still able to come in a little bit above the midpoint of your range. Am I reading too much into that in terms of the way the well performance is holding up relative to your curves.
It looks to be a little bit better than that.
What I would say Ron is that it's I think we would expect the wells at least early days to perform consistent with the offsets. I mean, you're just too early time. The good news is that you're not seeing degradation. So they're performing in line with what we expected. And that's probably about given the time frame that we've got probably about all you can say about it at this point, Yes.
I really wouldn't expect a lot of degradation early time. And so if you talk about in the past, it's watching production combined with modeling and pressure monitoring and pressure work to really understand what the drainage is going
to look like. Okay. And then Taylor you mentioned the 2014 growth profile will also be back end weighted similar to 2013. Is that something we just need to think about from an overall seasonality standpoint where you have a little bit of growth in the Q1 from the 4th and flattish in the second and then most of the growth in the second half. And is that something that kind of steady state as we go forward?
Or does that become less seasonal in 20 15 and beyond once more infrastructure is in place and you're less dependent on weather related downtime?
It's probably a pretty good decent assumption that it is going to be in a typical year back loaded. And it's all around some of it's winter and then a lot of it's around breakup when you just can't move equipment. Row is closed and you got row bands on. So even if you got the infrastructure in place, you can't move sand and other equipment to frac with. So you tend to plant your rigs.
And the effect of that is it pushes out those completions into 3rd Q4. Now there's been exceptions to that. If you look at historical production in years where it's cold and wet, you really see that flattening in the 1st two quarters. In years where it's been unseasonably warm and not a lot of rain, we've had a pretty even ramp and a good example of that is in 2012. Okay.
Yeah. But in 2011 and 2013 you see that more typical pattern of flat in 1QQ and then back loaded increases.
And we'll continue to plan that way Ron. It just doesn't make a whole lot of sense to us to spend a lot of money to fight the weather. Right. And we've shown that we can pretty effectively manage that this year. It's just that's the
way we view it. And then just on the Threefour, the wells that you drilled this year, not just to the other, but also the second and third, have those been spread fairly well across your different operating areas? Have they been concentrated in particular areas? And I assume given that next year is going to be more balanced, I'm assuming it'd be squared across more your operating areas. Is that also the same for the lower bench?
Or is the lower bench more concentrated in terms of testing?
So for 2nd bench wells, it's a lot of activity by other operators more kind of central deeper part the basin. And we've got tests in those areas, but we've also now are stepping out and I've talked about drilling this well just waiting on completion in North Cottonwood. 3rd bench test at this point in Indian Hills and the well that we've got drilling in South Cottonwood, the Mangum well and just one of those being online at this point. So we'll have some units where we'll likely drill 3rd bench test. Tommy talked earlier about the 15 wells that we're going to drill on the lower benches in the first in the next two quarters as we get those results that would then result in more lower bench tests in the back half of the year.
And are those 15 to 20 going to be more concentrated in places like Indian Hills? Or will you also kind of scoot over to South Cottonwood? Yes.
There'll be Indian Hills, South Cottonwood and North Cottonwood at this point. We're also looking at some of the acreage to the west that we picked up which would be painted woods. And then also on our Eastern Red Bank area we've got a second bench test that we'll be drilling.
Perfect. Thank you guys. Thanks, Rob.
Your next question comes from the line of Irene Haas with Wonderland Securities. Hi. Just wanted to get a feeling for your Three Forks Sanddish benches. How extensive is it? Does it is it controlled by drill depth?
Or does it kind of is it present towards the North and Cottonwood area?
So if you remember Irene last year, we in the beginning of this year, we took a lot of course and really evaluated the subsurface and that's where we're getting to the interest and where we're drilling wells. We see 2nd bench potential cross areas we just talked about. So parts of Red Bank we'll be testing potentially Painted Woods, Indian Hills, South Cottonwood and North Cottonwood. And then 3rd bench wells early time. And at this point, we've got tests in the near term plan for Indian Hills and South Cottonwood.
Okay, great. Thanks.
Thanks.
Your next question comes from the line of Peter Mahan with Dougherty.
Good morning, guys. I just had a couple of follow-up questions. What can we expect in terms of working interest over the next couple of quarters? And I think we increased from roughly 70% in Q2 to 73% here in Q3. Just how should we think about that trend for the foreseeable future?
Yes. Our working interest position ends up being around 70% on our operated acreage, Peter. But we normally come in somewhere between 70% 75% on working interest. So it will all kind of fluctuate in that ballpark. Got it.
Okay. And then I know we kind of briefly talked about the Sanish Acres that you're trying to sell that's been put on the market. What in terms of just the inventory you guys talk about, what's the number associated with that acreage? Well, remember the Sanddesh position is all non operated. So as we start we talk a lot about our gross operated inventory.
And so when we talk about basically 400 drilling spacing units in our operated inventory that net drives as you go our old inventory slides that had 4 by 4 and now those potentially could be a little bit higher net. That's really our drilling inventory that we really talk about. And Sanishes is remember all non op. So it's not included in that. Okay.
Got it. So you guys haven't quantified that to any degree? I mean, it's in the backup on Page 23 of our presentation. That's kind of all broken out. Okay.
And then finally, I apologize if I missed it. Could you just walk through kind of your infrastructure expense CapEx expectation for 2014. I know we talked about $20,000,000 for the 2nd frac crew. But could you walk through kind of some
of the other parts to that?
Yes. Infrastructure costs will be a bit variable. We'll have to figure things out a little bit. Obviously, we've been running more in a $50,000,000 neighborhood per year. Most of that was saltwater disposal type infrastructure around our legacy assets.
This year as we kind of talked about on the infrastructure side with the new acquisitions, there is an opportunity for us to potentially do some of this in house on not only saltwater disposal, but even on oil and gas. And so we're going through that process of figuring out are we going to go with 3rd party on that? Are we going to do some of that internally? So that capital actually can fluctuate a little bit depending on which direction we head on that. Okay, got it.
And that's all I had. Thanks guys. Thanks, Peter.
Your final question comes from the line of John Wolf with IFI Group.
Good morning, guys. Good morning, John.
Hi. Maybe one for Taylor. Just trying to think conceptually about the ability to go beyond 4+4. If you're drilling more wells per section, does that speak to recovery rates per well? I know Taylor and I discussed the idea of sort of 3% to 5% recovery per well within a drilling spacing unit.
So is more wells just more in fill drilling on the same resource? Or is it or is your tendency to think that you'll get equal results or similar on more well count?
So it depends on kind of depends on the area. But the well counts we're talking about going from 4% to 5%, we think the EURs are going to be pretty similar. You may see a little degradation, a little bit of competition for reserves, but it's going to be more weighted to the tail. So it's out in time. The 3% to 5% is still a good number to think about.
We talk a lot about as we're figuring out spacing triangulating with a lot of different data sources and one of those is oil in place and overall recovery in an area. So for a spacing unit, we think that somewhere in the 15% to 20% total recovery is reasonable. And then as you're taking those wells that are each recovering 3% to 5%, you can start doing the math on what that might look like. So going from forward to depending on the area thickness and reservoir quality and all those things going from 4 to 5 to potentially 6 wells, you're potentially going to see some degradation. But at this point, we don't it's math.
We just got to do more work on it.
Okay. And am I right to think that the 4 plus 4 or 5 plus 5 would be a combination of metal Bakken and then eitheror 3 Forks 1 or 3 Forks 2?
I'll just give you an example. We got to evaluate each of the intervals and then how the stimulation interacts and also how they produce that post stimulation. But those larger units,
those units where we're going
to produce or drill more wells up to 15 to 20 next year. We're contemplating drilling roughly 5 in each of the intervals. So you'd have 5 Bakken wells, 5 first bench, possibly 4 second bench and then also 3rd bench wells also. So you'd have them spaced throughout each of the producing intervals if it's productive those intervals are productive in that area.
Got it. Thanks for all the detail. Appreciate it. Thanks.
I would now like to turn the call back over to Mr. Lu for any closing remarks.
This is Tommy. Oasis continues to differentiate itself as one of the premier operators in the Williston Basin. Our team performed exceptionally across the board in the Q3. We executed again operationally, hitting our volume targets and managing costs. At the same time, we added to our asset position significantly with 4 acquisitions.
We now have them closed and have been doing an exceptional job on integration. This has been a tremendous year for us so far as we've done the things to grow our inventory, manage cost and improve the economics of our business and increase the resiliency of our inventory to low oil prices. All of these things strengthen our plan and make us very excited about what the future holds. As always, thanks for everyone's participation in our call today.
Again, thank you for your