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 third quarter 2013 earnings release and operations update for Oasis Petroleum. All lines have been placed on mute to prevent any background noise. After the speaker's remarks, there will be a question and answer session. I will now turn the call over to Michael Lou, Oasis CFO, to begin the conference. Thank you. Mr. Lou, you may begin your conference.
Thank you, Toni. Good morning, everyone. Today, we are reporting our third quarter 2013 results. We're delighted to have you on our call. I'm joined today by Tommy Nusz 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 that could cause actual results to be materially different from those currently disclosed in our earnings release and conference call. Those risks include, among others, matters that we have described in our earnings release as well as in our filings with the Securities and Exchange Commission, including our annual report on Form 10-K and our quarterly reports on Form 10-Q. 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, thanks for joining us today. It's been 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 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 downspacing and lower bench work, and increasing value through acquisitions and acceleration. First, 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 third quarter.
Our improved efficiency and optimization work has reduced total well cost to $8 million per well before taking into account OWS, which lowers costs by another $500,000 per well. Having hit our year-end 2013 target well cost of $8 million already, we continue to have confidence in our ability to get to $7.5 million by the year-end 2014, both those numbers being before the effect of OWS. We now expect to hit our production targets for 2013 with $40 million to $60 million less in capital than our original $1.02 billion budget, even when we include capital for the five additional wells that will be completed on the acquired assets in the fourth quarter. Second, we're more optimistic about the potential for inventory growth as we progress our downspacing efforts, do more work on the lower benches of Three Forks.
We've been encouraged by the results of the downspacing tests we've completed to date. Taylor will cover that in a bit more detail momentarily. 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. 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 two from the acquisition, and the incremental rig we just picked up, we're currently running 14 rigs. With the addition of the two 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%-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 pad. 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 fourth quarter production to be between 42,000 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 four wells per horizon to drain the Middle Bakken in 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 15-20 wells in a spacing unit with 5-6 wells across each bench of the Bakken and lower bench intervals. Additionally, preliminary testing 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 two second bench tests currently on production, the Patsy and Paul S wells, and one third bench, the Omelet, online as well. All three wells look similar to first bench wells in the area. The Patsy, Paul S, and Omelet produced 784, 712, and 804 bbl equivalent per day, respectively, during the first 30 days of production. The Bonita well in North Cottonwood, the second bench test, is not yet completed but will be online in the fourth quarter. We are also currently drilling a third 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. As we look to 2014, we expect the overall program to be pretty evenly balanced between Bakken and Three Forks wells.
The transition to 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%-90% in 2014. Recent advancements include an eight-well pad where we executed simultaneous operations for the first time. The team put up some great results with spud to rig release averaging 19.2 days, and frac days averaging 2.6 days per well. The first well that we drilled in Nesson 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 backloaded production again in 2014. Improving upon the efficiency gains of simultaneous operations will be important in helping us to deal with unevenly loaded pad operations. 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 a change. Finally, given the success of OWS in our increased activity, we have ordered a second frac spread.
It should begin operations late in the second quarter of 2014, and when combined with our existing frac spread, should handle approximately 50%-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 Williston acquisition was on October 1st. 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 billion of senior notes and drew approximately $600 million on our revolver. With $145 million of pro forma cash after the acquisition and $900 million of availability on the revolver, we have more than $1 billion of liquidity to fund our accelerated drilling program. While we have ample capacity under our revolver 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 four 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 two 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'll see how it ultimately shakes out. The four 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 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 natural 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 standalone had about 85% connected to pipe as of September 30th, whereas the West Williston acquired assets were just over 25% connected.
There's an opportunity over the coming quarters and 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 fourth 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 owned 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 third quarter results, our realized oil price averaged $100.75 per barrel, with about a 5% differential to WTI.
As most of you know, differentials have been very tight since the fourth quarter of 2012, but they have recently started to tick up. We're expecting the fourth quarter to widen out a bit as compared to the third quarter, with WTI and Clearbrook to coastal markets spread gapping out again. We've shifted from as low as 40% rail in the third quarter 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 million 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 Toni to open the lines up for questions.
At this time, ladies and gentlemen, if you would like to ask a question, press star, then the number 1 on your telephone keypad. Once again, press star, then the number 1 to ask a question. We'll pause for just a moment to compile the Q&A roster. Your first question comes from the line of Phillips Johnston with Capital One.
I just wanted to get some clarity on your third quarter CapEx figures that you provided in the table. Just two questions there. First, on the $127 million of acquisitions related to I guess the CapEx related to acquisitions. Is that just cash paid for the East Nesson properties and the deposit on the West Williston transaction, or does that also include some actual CapEx that you incurred on the East Nesson properties after you closed it in September?
Exactly right, Phillips. What you said first, which that is the East Side acquisitions. Payment for that as well as the deposit for the West Williston side. Obviously, that closed October 1st. You'll see the full amount of that CapEx in the fourth quarter numbers.
Okay. The clean E&P CapEx is more like $244 million or so. I was just trying to square that number to the $8 million per well-completed cost that you achieved in the quarter. If I take the $244 million and divide that by the 29.6 net wells that you brought online, sort of implies a little over $8.2 million per well. 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.
Yeah, there's some of that, and there's some infrastructure cost in that number as well. As you back out that for the saltwater disposal infrastructure that we put in.
Okay.
As you back that out, that's how it rectifies.
Okay. Then, you mentioned additional lower Three Forks benches next year, I may have missed this, but did you say what the percentage mix will be between the various benches within the Three Forks? Just as a follow-up, will most of those lower bench tests be single well tests like the four that you've drilled, or is the plan to move more towards multi-well, multi-formation density pilots like some of your peers in the field are doing?
We didn't talk about the percentage of wells that will be lower benches. Did say that in the next few quarters, you'll have 15 wells drilled in the lower benches. Overall, Three Forks and Bakken well count will be roughly 50/50, pretty well balanced. In the areas where we have greater confidence in the lower benches, we'll be drilling out some spacing units where we'll drill across all the horizons. Middle Bakken, first bench, second bench, and potentially third bench. Then in areas where it's
We have quite as high a confidence it will be more one-off type of wells testing the lower benches in those areas. 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 & Company.
Morning, Dave. Dave, are you on?
Yeah. Can you hear me?
Yeah.
We are. Yeah.
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, gets you to somewhere between $1.1 billion-$1.2 billion for CapEx, before infrastructure, et cetera. Is that a good way to start thinking about 2014 program?
Yeah, that's not bad. I think it's pretty straightforward, but I think you're in the range.
Okay, appreciate that. As we think about the guidance for Q4, 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?
Right now, it's pretty similar to what we announced at the time of the acquisition. It's in that same range. However, as we progress through the fourth quarter, on those assets, we're drilling on pads, won't have as many completions as we might otherwise have. You may see that drop off a little bit, but we've got the ability to make that up on our remaining assets.
It'll be flattish.
Yeah.
Okay. I appreciate that. That's helpful for understanding what your base growth is from the original asset base. Just one more. As we think about completing less wells in Q3, was that just the nature of some slipping into Q4? 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?
Yeah, a lot of it is just timing of when wells come on relative to a day that's the end of the quarter. We were still pretty close. We're still targeting the 128 for the year. We'll catch up. I think there's five incremental wells that are on the acquired assets. The original 128 plus five will put you in the range for the fourth quarter.
Okay. 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.
Yeah.
Okay. That's very helpful. I'll let somebody else jump on. Thanks, guys.
You bet.
Your next question comes from the line of Noel Parks with Ladenburg Thalmann.
Good morning.
Morning.
A couple 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 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 understanding and consistency, relatively, of the subsurface. While these wells are getting pretty close together, we still tend to have a few surprises. The other one, I think that's probably the biggest thing is just infrastructure.
Okay.
Whether it's gas, oil, water gathering, water distribution, the whole bit. I think it's largely infrastructure.
Yeah, infrastructure's 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 them impacting you as well. You can control that. That helps out.
Right. Great. I don't know if you touched on this already. I hopped on a little late. As we look ahead to the year-end reserve bookings, I'm just trying to think through, you've got a lot of drilling. I'm thinking just number of locations on the PUD side should grow considerably. I guess the two things I was wondering about is, as far as the five-year PUD 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, in a more unlimited capital situation, would be in the proved or the PUD area? Then also, whether you expect you're going to see significant performance improvement bookings?
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.
Sure.
We're at a little over 215 million barrels currently. Our PUDs relative to overall proved is at 47%. 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 PUDs in a couple of years. Staying within that five-year window is really not going to be a problem for us.
Okay. The performance improvement?
Like I've talked about in the past, we are consistently focusing on improving the results on our wells. Doing that through stimulation, looking at optimizing fracs, both what we're doing and then what other operators are doing in the basin. We've got to focus on trying to improve that all the time. I can't tell you or give you a projection about where that's going to go.
Yeah, keep in mind that our reserves are prepared externally, not audited externally. They're going to largely work off of the historical performance. It's not like we're rolling into PUD some expectation of performance improvement. It's largely working off of the historicals within that [acreage breadth].
Thanks a lot.
You bet.
Your next question comes from the line of Michael Hall with KeyBanc.
Thanks. Good morning, guys.
Hey, Michael.
Yeah, first, noteworthy, I'd say, shift in posture around density tests and bench tests and your game plan on that. How quickly do you plan on testing the, like you talked about, a 15-20 well unit? How quickly are those sorts of tests going to make their way through the system?
Those, we've got a couple of units that we'll drill at pretty high density, they're second half of the year next year. We'll be able to drill them in, it'd be about six 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 first PUD in those units and then getting the first production. 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, that'll be helpful in how we lay those things out going into the second half of next year.
Yeah.
Okay, that's helpful. I guess somewhat related then, on the 210 gross drill wells, any rough numbers or percentages of how many get completed in the year, and then how those are spread out broadly through all your different areas?
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. 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, 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. More wells completed in the second half.
Okay. Any relative emphasis in any of the sub-areas within your acreage position? Is it going to be pretty well spread out throughout the whole acreage position?
We're trying to achieve a pretty good spread with the 16 rigs. Again, we can give some more color on that when we come out with the budget in early next year.
Fair enough. Do you have comparable, last one from me, comparable IP30s, the offsetting Three Forks wells relative to those deep tests you highlighted.
You mean from other operators?
Yeah. Yourselves or prior wells drilled nearby. Just trying to understand how those.
For example, the Paul S well, you had a 30-day IP of 712 barrels a day. There's two first bench wells around it. The Paul S was a second bench. You have two first bench wells that were around 775 barrels a day for a 30-day average, and you had one well that was about 1,100 barrels a day for a 30-day average.
Okay. That's helpful. Appreciate it. Thanks, guys.
All right, Michael. Thanks.
Your next question comes from the line of Tim Rezvan with Sterne Agee.
Good morning, folks. I had a quick one just on the Sanish assets being marketed. Should we assume that's all, I guess it's 8,000 net acres and about 2,800 barrels of production?
That is what we have on the market.
Okay. Appreciate that clarity. Should we think about that will help fund the infrastructure ramp that you've signaled on the recently acquired acreage?
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. That'll 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 decline pretty sharply out to 2014, I guess should we look at recent ratios in that one and a half times range as management's comfort level?
Yeah. We've said that we'd like debt to EBITDA to come down to under 2x, that'd be a level that we're comfortable with. Like you said, we know that as production grows, we can see that coming down over the next coming quarters. 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. Just 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 cemented liners a big part of that, or more proppant per foot or different frac fluids? If you could help with them and what kind of responses might you have gotten so far?
Yeah. We've actually experimented with all those things you talked about. Some of the recent things you've heard the industry talking more about have been slick water fracs with higher proppant concentration, just bigger fracs overall. We've experimented with those as well as looking at all of the other operator data in the basin, that's where we come back to make adjustments to our typical fracs by area based on what we see with all that work. We're not in a position to talk about what results are for each of those individual fracs 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?
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, along with it, you've got higher cost. You got to balance the higher cost versus not only the IP, but what is going to be the EUR in the well. Is it just acceleration, or are you really increasing reserves? What's the economic impact? For us, we've got type curve ranges that we've been using, 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.
Cemented liners a big part of this, or have you been doing that all along?
We primarily use swell packers. We have done cemented liners, probably 10-15 wells overall, looking at the results. Right now, our standard completion is still the swell packers.
Thank you.
See you, [inaudible]. Thanks.
Our 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, yet you talk about encouraging results. Were you expecting much of any degradation as you were going through this? Are you positively surprised or not? Then corollary to it is, given the fact that 38 completions during the third quarter, 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.
Right. What I would say, Ron, is that I think we would expect the wells, at least early days, to perform consistent with the offsets. You're just too early time. The good news is that you're not seeing degradation, they're performing in line with what we expected, and that's probably about, given the timeframe that we've got, probably about all you can say about it at this point, huh?
Yeah, I really wouldn't expect a lot of degradation early time. 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. 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 1st quarter from the 4th and flattish in the 2nd and then most of the growth in the second half, and is that something that steady state as we go forward, or does that become less seasonal in 2015 and beyond once more infrastructure's in place and you're less dependent on weather-related downtime?
Ron, 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. Roads close, and you got road bans on, so even if you got the infrastructure in place, you can't move sand and other equipment to frack with, so you tend to plant your rigs, and the effect of that is it pushes out those completions into 3rd and 4th quarter. 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.
Oh, okay.
Yeah. In 2011 and 2013, you've seen that more typical pattern of flat in 1 and 2Q, and then back-loaded increases.
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.
We've shown that we can pretty effectively manage that this year. It's just that's the way we view it.
Just on the Three Forks, the wells that you've drilled this year, not just to the upper, but also the second and third, have those been spread fairly well across your different operating areas? Have they been concentrated in particular areas? I assume, given that next year's going to be more balanced, I'm assuming it'd be spread across more of your operating areas. Is that also the same for the lower bench, or is the lower bench more concentrated in terms of testing?
For second bench wells, it's a lot of activity by other operators, more central, deeper part of the basin, and we've got tests in those areas. We also now are stepping out and talked about drilling this well. It's waiting on completion in North Cottonwood. Third bench test at this point are 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. We'll have some units where we'll likely drill third bench tests. Tommy talked earlier about the 15 wells that we're going to drill on the lower benches in the next two quarters. We get those results, that would result in more lower bench tests in the back half of the year.
Are those 15 to 20 going to be more concentrated in places like Indian Hills, or will you also scoot over to South Cottonwood?
They'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 Hanging Woods, also in our Eastern Red Bank area, we've got a second bench test that we'll be drilling.
Perfect. Thank you, guys.
Thanks, Ron.
Your next question comes from the line of Irene Haas with Wunderlich Securities.
Hi. Just wanted to get a feeling for your Three Forks, Sanish benches. How extensive is it? Is it controlled by drill dev, or is it present towards the North and Cottonwood area?
If you remember, Irene, last year, in the beginning of this year, we took a lot of cores and really evaluated the subsurface, and that's where we're getting to the interest in where we're drilling wells. The second bench potential cross areas we just talked about. Parts of Red Bank we'll be testing, potentially Painted Woods, Indian Hills, South Cottonwood, and North Cottonwood. Then third bench wells, early time, but at this point, we've got a test in the near-term plan for Indian Hills and South Cottonwood.
Okay, great. Thanks.
Thanks.
Your next question comes from the line of Peter Mahon 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? 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?
Yeah. Our working interest position ends up being around 70% on our operated acreage, Pearce, we normally come in somewhere between 70% and 75% on working interest. It'll all fluctuate in that ballpark.
Got it. Okay. I know we briefly talked about the Sanish acreage that you're trying to sell, that's been put on the market. In terms of just the inventory you guys talk about, what's the number associated with that acreage?
Well, remember that Sanish position is all non-operated. We talk a lot about our gross operated inventory, when we talk about basically 400 drilling spacing units in our operated inventory, that drives, if you go by our old inventory slides that had four by four, now those potentially could be a little bit higher net. That's really our drilling inventory that we really talk about. Sanish is, remember, all non-op, so it's not included in that.
Okay, got it. You guys haven't quantified that to any degree.
It's in the backup on page 23 of our presentation. That's all broken out.
Finally, I apologize if I missed it, could you just walk through your infrastructure expense CapEx expectation for 2014? I know we talked about $20 million for the second frac crew, but could you walk through some of the other parts to that?
Yeah, 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 million neighborhood per year. Most of that was saltwater disposal type infrastructure around our legacy assets. This year, as we 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. We're going through that process of figuring out, are we going to go with third party on that, or are we going to do some of that internally? That capital actually can fluctuate a little bit depending on which direction we head on that.
Okay, got it. That's all I had. Thanks, guys.
Thanks, Pearce.
Your final question comes from the line of John White with ISI Group.
Morning, guys.
Hi, John.
Hi. Maybe one for Taylor. Just trying to think conceptually about the ability to go beyond four plus four. 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 3%-5% recovery per well within a drilling spacing unit. Is more wells just more infill drilling of the same resource, or is your tendency to think that you'll get equal results or similar on more well count?
It depends on the area, but at the well counts, we're talking about going from four to five, 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%-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. For a spacing unit, we think that somewhere in the 15%-20% is reasonable. As you're taking those wells that are each recovering 3%-5%, you can start doing the math on what that might look like. Going from four to, depending on the area thickness and reservoir quality and all those things, going from four to five to potentially six wells, you're potentially going to see some degradation. At this point, we don't think it's massive. We've just got to do more work on it.
Okay. Am I right to think that the four plus four or five plus five would be a combination of Middle Bakken and then either/or Three Forks one or Three Forks two?
I'll just give you an example. We've got to evaluate each of the intervals, and then how the stimulation interacts, and also how they produce at post-stimulation. Those larger units, those units where we're going to produce or drill more wells, up to 15-20 next year, we're contemplating drilling roughly five in each of the intervals. You'd have five Bakken wells, five first bench, possibly four second bench, and then also third bench wells also. You'd have them spaced throughout each of the producing intervals if 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. Lou 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 third quarter. We executed again operationally, hitting our volume targets and managing costs. At the same time, we added to our asset position significantly with four 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 costs, and improved the economics of our business, and increased 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 on our call today.
Again, thank you for your participation. This does conclude today's conference call. You may now disconnect.