Seeking Alpha
We cover over 5K calls/quarter
Profile| Send Message|
( followers)  

Oasis Petroleum (NYSE:OAS)

Q3 2013 Earnings Call

November 07, 2013 12:00 pm ET

Executives

Michael H. Lou - Chief Financial Officer and Executive Vice President

Thomas B. Nusz - Chairman, Chief Executive Officer and President

Taylor L. Reid - Chief Operating Officer, Executive Vice President and Director

Analysts

Philip Johnston

David W. Kistler - Simmons & Company International, Research Division

Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division

Michael Hall

Timothy Rezvan - Sterne Agee & Leach Inc., Research Division

David Snow

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

Irene O. Haas - Wunderlich Securities Inc., Research Division

Peter Mahon - Dougherty & Company LLC, Research Division

Jonathan D. Wolff - ISI Group Inc., Research Division

Operator

Good afternoon. My name is Toni, and I be will 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. [Operator Instructions] 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.

Michael H. Lou

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 risk 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'll describe in our earnings release as well as 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.

Thomas B. Nusz

Good morning, and 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 down-spacing and other bench work, and increasing value through acquisitions and acceleration.

First, as we noted in the press release, well cost continued to move down across our position. Additionally, we have lowered spud-to-rerelease 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. Additionally, 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 5 additional wells that will be completed on the acquired assets in the fourth quarter. Second, 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 down-spacing 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 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 tailor, who will discuss our operational results and some preliminary thoughts for 2014.

Taylor L. Reid

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 acquisition, 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 have been positive, with wells performing in line with wells previously drilled in their respective area. 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 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 to 20 wells on a spacing unit, with 5 to 6 wells across each of the Bakken lower bench intervals. Additionally, preliminary testing of 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 pads currently on production, the Patsy and Paul S wells; and one third bench, the Omlid, online as well. All 3 wells look similar to first bench wells in the area. Capacity, Paul S and Omlid produced 784, 712 and 804 barrels equivalent per day, respectively, during 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 2 quarters alone, we plan to drill an additional 15 lower bench wells. And as we look to 2014, we expect the overall program to be pretty evenly balanced between Bakken and Three Forks wells.

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 have executed simultaneous operations for the first time. The team put up some great results, with spud-to-rig release averaging 19.2 days, with frac days averaging 2.6 days per well. The first well that we drilled, [indiscernible], 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 operation. Advancements like SIMOPS will be important as we drill more large multi-well pad. Even so, as previously stated, pad operations lead to lumpy growth. And that, combined the winter operations and spring breakup, will lead to backlog of 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 a change.

Finally, given the success of OWS and our increased activity, we have ordered a second frac spread. It should begin operation late in the second quarter of 2014, and when combined with our existing frac spreads, should handle approximately 50% to 60% of our wells. The decision to add a second crew was obviously pretty easy given our success with the 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 Mike.

Michael H. Lou

Thanks, Taylor.

I'll begin with a brief update on the acquisitions. The closing of the West Williston 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 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 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'll see how it'll ultimately shapes out.

The 4 acquisitions that recently closed added large operated blocks adjacent near 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 had 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 by 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 30, whereas the West Williston acquired assets were just over 25% connected. There is 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 describes 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 50% going down own disposal wells. We'll be able to invest in salt water 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 Clearbook 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 growing offset wells. As we drill new wells close to producing ones, we'll continue to experience frac protect cost. 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.

Question-and-Answer Session

Operator

[Operator Instructions] Your first question comes from the line of Philip Johnston with Cap One.

Philip Johnston

Just wanted to get some clarity on your third quarter CapEx figures that you provided in the table. Just 2 questions there. First, on the $127 million of acquisitions related to -- I guess the CapEx related to acquisition. Is that just cash paid for the East Nesson properties and the deposit on the West Williston transaction or that also include some actual CapEx that you incurred on the East Nesson properties after you closed it in September?

Thomas B. Nusz

Exactly right, Philip. We said, first, that is the East side 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 fourth quarter numbers.

Philip Johnston

Okay. So the clean sort of E&D 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. 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.

Thomas B. Nusz

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 salt water disposal infrastructure we put in, if you back that out, that's how it rectifies.

Philip Johnston

Okay. And then you mentioned additional lower Three Forks benches next year. And I may have missed this, but did you say with the percentage mix will be between various benches within the Three Forks? And just as a follow-up, will most of those lower bench tests be single well test 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?

Thomas B. Nusz

So we didn't talk about the percentage of wells that will be lower benches. We 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 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 horizon. So, Middle Bakken, first bench, second bench and potentially third bench. And then in areas where we don't have quite as high a confidence, it will be more one-off type 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 other areas in lower benches.

Operator

Your next question comes from the line of Dave Kistler with Simmons and Company.

David W. Kistler - Simmons & Company International, Research Division

If I look at the 210 gross wells you're drilling next year and the cost estimates you guys had put out, adjust for working interest, kind of gets you to somewhere between $1.1 billion to $1.2 billion for CapEx before infrastructure, et cetera. Is that a good way to start thinking about '14 program?

Thomas B. Nusz

Yes, that's not bad. Yes, I think you're -- I mean, it's pretty straightforward. But I think you're in the range.

David W. Kistler - Simmons & Company International, Research Division

Okay, appreciate that. And then as we think about a 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?

Michael H. Lou

So, David, 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 fourth quarter, on those assets we're drilling on pads, and so won't have as many completions as we might otherwise have, so you may see that drop off a little bit but we've got the ability to make that up on our remaining assets. So it'll be kind of flattish.

David W. Kistler - Simmons & Company International, Research Division

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?

Thomas B. Nusz

Yes, I mean, a lot of it is just timing of when wells come on relative to a day that's the end of the quarter. We are still pretty close. We're still targeting the 128th for the year, so we'll catch up. And then I think there's 5 incremental breadth that are on the acquired assets, so the original 128 plus 5 will kind of put you in the range for the fourth quarter.

David W. Kistler - Simmons & Company International, Research Division

Okay, so 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?

Thomas B. Nusz

Yes.

Operator

Your next question comes from the line of Noel Parks with Landenburg Thalmann.

Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division

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 where sort of more far-slung? Is it just getting the full development faster, gas takeaway being simpler?

Thomas B. Nusz

No. What I'd tell you is 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. But then the other one, I think that's probably the biggest thing is just infrastructure, whether it's gas, oil, water, water gathering, water distribution. The whole bit, but I think it's largely infrastructure.

Taylor L. Reid

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 much with you impacting third parties and them impacting you as well. You can control that, so that helps out.

Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division

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 booking, I'm just trying to think through -- you've got a lot of drilling, so I'm thinking just number of locations on the PUD side should grow considerably. So I guess the 2 things I was wondering about is, as far as the 5-year PUD booking limit, just in 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.

Thomas B. Nusz

So, when you look at our -- in 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 million 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 PUDs in a couple of years. So staying within that 5-year windows is really not going to be a problem for us.

Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division

Okay. And the performance improvement?

Thomas B. Nusz

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 with 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 or give you a projection about where that's going to go.

Taylor L. Reid

Yes, keep in mind that our reserves are prepared externally, not audited externally, and are going to largely work off of the historical performance. I mean, it's not like we're rolling in, to PUD, some expectation of performance improvement. It's largely working off of the historicals. Wouldn't that -- accurate, right?

Operator

Your next question comes from the line of Michael Hall with Heikkinen Energy.

Michael Hall

Let see, the 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 -- like you talked about a 15- to 20-well unit? How quickly are those sort of tests going to make their way through the system?

Taylor L. Reid

For 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, probably, about 6 months or less to work through it, because we're going to apply multiple rigs to get in a reasonable amount of time so we won't have too long of a lag between the first spud in those units and then get into first production. But you won't see impact from those until 2015.

Thomas B. Nusz

To 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.

Michael Hall

Okay, that's helpful. And then I guess somewhat related then, on the 210 gross drilled wells, any rough numbers or percentage on how many get completed in the year and how those are spread out, broadly, through all your different areas?

Thomas B. Nusz

Yes, so when you look at the total count, you 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. 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 backloading effect because of winter operations and putting as many of our wells on pad as we can during the breakup period, so more wells completed in the second half.

Michael Hall

And any relative emphasis in any of the kind of subareas within your acreage position or is it going to be pretty well spread out throughout the whole acreage position?

Thomas B. Nusz

So we're trying to -- it's either pretty good spread with the 16 rigs, but again, we can give some more color on that when we come out with the budget in early next year.

Michael Hall

Fair enough. And then you have kind of comparable -- last one for me -- comparable like IP30s offsetting Three Forks wells relative to those deep tests you highlighted?

Thomas B. Nusz

You mean from other operators?

Michael Hall

Yes, or yourselves or prior wells drilled nearby. Just trying to understand kind of how those...

Thomas B. Nusz

Yes, so we've got -- so, for example the Paul S well, you had a 30-day IP of 712 barrels a day. There is 2 first bench wells around it, the Paul S was the second bench. You have 2 first bench wells that are around 775 barrels a day for a 30-day average, and you have 1 well that was about 1,100 barrels a day for a 30-day average.

Operator

Your next question comes from the line of Tim Rezvan with Sterne Agee.

Timothy Rezvan - Sterne Agee & Leach Inc., Research Division

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?

Thomas B. Nusz

That is what we have, yes, on the market.

Timothy Rezvan - Sterne Agee & Leach Inc., Research Division

Okay, okay. Appreciate that clarity. And then should we think about that? That, that will help fund the infrastructure ramp that you've signaled on the recently acquired acreage?

Thomas B. Nusz

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 expected it to be highly contested for us. So that will help us with our liquidity and helping us delever the balance sheet too.

Timothy Rezvan - Sterne Agee & Leach Inc., Research Division

Okay. I'm just asking in context because you can see the debt to EBITDA declining pretty sharply out to 2014, and I guess should we look at, I guess, recent ratios in that 1.5x range as management's comfort level?

Michael H. Lou

Yes, we've kind of said that we'd like debt to EBITDA come down to under 2x, and that'll be a level 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 the things, as we're accelerating, we feel good about the inventory continuing to accelerate a little bit. Like you said, there will be some infrastructure build. So just kind of managing CapEx and the cash flow outspend, and managing the balance sheet.

Operator

Your next question comes from the line of David Snow with Energy Equities Inc.

David Snow

Could you give us a little color on the completions that you're experimenting with? The different ones that you and others are doing, cemented liners, a big part of that or more profits up per foot or different frac fluids. If you help with that, and what kind of response might you have gotten so far?

Thomas B. Nusz

Yes, so we've actually experimented with all those things you talked about. Some of the recent things you heard the industry talking more about have been slick water fracs and then higher fracs with higher concentration. 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'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.

David Snow

Are you liable to see some increase in your IPs and AURs as a result of all this?

Thomas B. Nusz

When we look at the data, some of those frac styles, and 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 costs and so you've got to balance the higher cost versus, not only the IP, but what is going to be the EUR in the wells. Is it just acceleration or are you really increasing reserves? And then what's the economic impact? So, for us, we got type curve ranges that we've been using and those are -- we hadn't changed those at this point, and if we get to a point where we really see significant uptick, we'll let you all know.

David Snow

Cemented liners a big part of this or have you been doing that all along?

Thomas B. Nusz

We've primarily used swell packers, but we have done 2-minute cemented liners like 10 to 15 wells, overall, looking at the results. But right now our standard completion this is still the swell packers.

Operator

Your next question comes from the line of Ron Mills with Johnson Rice.

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

As it relates to the down-spacing, you have 13 of the 22 are online and you talk about encouraging results. Were you expecting much, if any, degradation as you were going through this or are you positively surprised or not? And then corollary to it is given the fact that 38 completions, during the third quarter, you are still able to come in a little bit above the midpoint of the 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.

Thomas B. Nusz

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. That's probably about -- given the timeframe that we've got, probably about -- all you can say about it at this point?

Taylor L. Reid

Yes, I really wouldn't expect a lot of degradation, early time. And so, as we talked 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.

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

Okay. And then, Taylor, you mentioned 2014 growth profile will also be back-end weighted similar to 2013 is. Is that something we just need to think about from an overall seasonality standpoint, where you have a little bit of growth in the first quarter from the fourth 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 2015 and beyond once more infrastructure is in place and you're less dependent on weather related downtime?

Thomas B. Nusz

Ron, it's probably a pretty good -- a decent assumption that it's going to be, in a typical year, backloaded. 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 the equipment. Road's closed and you've got road bans on. So, even if you got the infrastructure in place, you can't move sand and other equipment to frac, frac-less. So you tend to plant your rigs. And the effect of that is it pushes out those completions into third and fourth quarter. 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 first 2 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. But in 2011 and '13, you see that more typical pattern of flat in 1Q and 2Q, and then backloaded increases.

Thomas B. Nusz

And we'll continue to play it 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. And we've shown that we can pretty effectively manage that this year. It's just that's the way we view it.

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

And then just on the Three Forks. The wells that you 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? And I assume, given that next year is going to be more balanced, I'm assuming that it'd be squared 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?

Taylor L. Reid

So, for second bench wells, a lot of activity by other operators, more kind of central deeper part of the basin. And we've got test in those areas, but we've also now are stepping out, and Mike talks about drilling this well, he's waiting on completion in North Cottonwood. Third bench test, at this point they're in Indian Hills, and the well that we got drilling in South Cottonwood, the Magnum well, and just one of those online at this point. But we'll have some units where we'll likely drill third bench test. Tommy talked earlier about the 15 wells that we're going to drill on the lower benches in the next few quarters. As we get those results, that would then result in more lower bench test in the back half of the year.

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

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?

Taylor L. Reid

Yes, 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 Painted Woods. And then also, on our Eastern Red Bank area, we've got a second bench test that we'll be drilling.

Operator

Your next question comes from the line of Irene Haas with Wunderlich Securities.

Irene O. Haas - Wunderlich Securities Inc., Research Division

Just want to get a feeling for your Three Forks Sanish benches. How extensive is it? Is it controlled by drill depth or is it present to us in Northern Cottonwood area?

Taylor L. Reid

So, 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 what where we're getting to the interest and where we're drilling wells. We see second bench potential across areas we just talked about. So, partial Red Bank will be testing, potentially Painted Woods, Indian Hills, South Cottonwood and North Cottonwood. And then third bench wells, early time but at this point we've got a test in the near-term planned for Indian Hills and South Cottonwood.

Operator

Your next question comes from the line of Peter Mahon with Dougherty.

Peter Mahon - Dougherty & Company LLC, Research Division

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?

Thomas B. Nusz

Our working interest position ends up being around 70% on our operated acreage, Peter. We normally come in somewhere between 70% and 75% on working interest. So it'll kind of fluctuate in that ballpark.

Peter Mahon - Dougherty & Company LLC, Research Division

Got it, okay. And then I know we 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?

Michael H. Lou

Well, remember the Sanish position is all non-operated. So as we start -- we talk a lot about our gross operated inventory. And so when we talked about basically 400 drilling spacing units in our operated inventory, that drives -- if you go by our old inventory slides, it has 4x4 and now those, potentially, could be a little bit higher than that. That's really our drilling inventory that we really talk about. And Sanish is, remember all non-ops, so it's not included in that.

Peter Mahon - Dougherty & Company LLC, Research Division

Okay, got it. So you guys haven't quantified that to a new degree?

Michael H. Lou

I mean it's in the back up, on Page 23 of our presentation. That's kind of all broken out.

Peter Mahon - Dougherty & Company LLC, Research Division

Okay. And then finally, I apologize if I missed it, could you just walk through kind of your infrastructure CapEx expectation for '14? I know we talked about $20 million for the second frac crew, but could you walk through kind of some other parts to that?

Thomas B. Nusz

Yes, infrastructure cost 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 salt water disposal type infrastructure around our legacy assets. This year, as we kind of talk 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 salt water disposal but even on oil and gas. And so we're going through that process of figuring out, are we going to go with third party on that or are we go to do some of that internally? And so that capital actually can fluctuate a little bit depending on which direction we head on that.

Operator

Your final question comes from the line of John Wolf with ISI Group.

Jonathan D. Wolff - ISI Group Inc., Research Division

Maybe one for Taylor. Just trying think, conceptually, about the ability to go beyond 4 plus 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 infill drilling of the same resource or is it your kind of thing to think [ph] that you'll get equal results or similar on more well count?

Taylor L. Reid

So it kind of depends on the area, but well counts, we're talking about, going from 4 to 5, we think the EURs are going to be pretty simpler. 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 4 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 think it's masked [ph], we just got to do more work on it.

Jonathan D. Wolff - ISI Group Inc., Research Division

Okay. And am I right to think that if the 4 plus 4 or 5 plus 5, would be a combination of Middle Bakken and then either or Three Forks 1 or Three Forks 2?

Taylor L. Reid

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 that post-stimulation. But those larger units, those 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 we can have 5 Bakken wells, 5 first bench, possibly 4 second bench and then also third bench wells also. So you have them spaced throughout each of the producing intervals, if those intervals are productive in that area.

Operator

I would now like to turn the call back over to Mr. Lou for any closing remarks.

Thomas B. Nusz

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 cost. 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 costs and improve the economics of our business, and increase the resiliency of our inventory below 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.

Operator

Again, thank you for your participation. This does conclude today's conference call. You may now disconnect.

Copyright policy: All transcripts on this site are the copyright of Seeking Alpha. However, we view them as an important resource for bloggers and journalists, and are excited to contribute to the democratization of financial information on the Internet. (Until now investors have had to pay thousands of dollars in subscription fees for transcripts.) So our reproduction policy is as follows: You may quote up to 400 words of any transcript on the condition that you attribute the transcript to Seeking Alpha and either link to the original transcript or to www.SeekingAlpha.com. All other use is prohibited.

THE INFORMATION CONTAINED HERE IS A TEXTUAL REPRESENTATION OF THE APPLICABLE COMPANY'S CONFERENCE CALL, CONFERENCE PRESENTATION OR OTHER AUDIO PRESENTATION, AND WHILE EFFORTS ARE MADE TO PROVIDE AN ACCURATE TRANSCRIPTION, THERE MAY BE MATERIAL ERRORS, OMISSIONS, OR INACCURACIES IN THE REPORTING OF THE SUBSTANCE OF THE AUDIO PRESENTATIONS. IN NO WAY DOES SEEKING ALPHA ASSUME ANY RESPONSIBILITY FOR ANY INVESTMENT OR OTHER DECISIONS MADE BASED UPON THE INFORMATION PROVIDED ON THIS WEB SITE OR IN ANY TRANSCRIPT. USERS ARE ADVISED TO REVIEW THE APPLICABLE COMPANY'S AUDIO PRESENTATION ITSELF AND THE APPLICABLE COMPANY'S SEC FILINGS BEFORE MAKING ANY INVESTMENT OR OTHER DECISIONS.

If you have any additional questions about our online transcripts, please contact us at: transcripts@seekingalpha.com. Thank you!

Source: Oasis Petroleum Management Discusses Q3 2013 Results - Earnings Call Transcript
This Transcript
All Transcripts