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Oasis Petroleum (NYSE:OAS)

Q1 2013 Earnings Call

May 08, 2013 11:00 am 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

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

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

Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division

Subash Chandra - Jefferies & Company, Inc., Research Division

Mostafa Dahhane - Wunderlich Securities Inc., Research Division

David Deckelbaum - KeyBanc Capital Markets Inc., Research Division

Mark McDowell

David R. Tameron - Wells Fargo Securities, LLC, Research Division

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

Dan McSpirit - BMO Capital Markets U.S.

Eli J. Kantor - Iberia Capital Partners, Research Division

Peter Mahon - Dougherty & Company LLC, Research Division

Gail A. Nicholson - KLR Group Holdings, LLC, Research Division

Operator

Good morning. My name is Regina, and I will be your conference operator today. At this time, I would like to welcome everyone to the first quarter 2013 earnings release and operations update for Oasis Petroleum. [Operator Instructions]

I would now turn the call over to Michael Lou, Oasis Petroleum's CFO, to begin the conference. Thank you, Mr. Lou, you may begin your conference.

Michael H. Lou

Thank you, Regina. Good morning, everyone. This is Michael Lou. We are reporting our first quarter 2013 results and 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 our 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 will also make references to adjusted EBITDA, which is a non-GAAP financial measure. Reconciliations to adjusted EBITDA to the applicable GAAP measure can be found in our earnings release or on our website.

I'll now turn over the call to Tommy.

Thomas B. Nusz

Good morning. In line with our past calls, I'll lead off with some general comments; Taylor will provide an operational update with some of the key items we're focused on this year; and Michael will finish with a few financial highlights.

I'd like to start by saying that I'm definitely proud of the team for what they've accomplished over the last 3 years and in the last 12 months, in particular. Oasis has been an amazing growth story, as we have doubled year-over-year production in 2011 and 2012, while executing in an environment that has had plenty of challenges. Yet the team has continued to rise to the occasion and that has set us up for continued long-term growth without sacrificing capital efficiency.

So let me expand on 3 key areas of our business that drive our value proposition. First, back in 2011, we experienced one of the toughest winters on record. Subsequently, we put in infrastructure, modified logistics and adjusted our planning processes to help mitigate the impact of such conditions. Our efforts paid off in the first quarter of this year, as we delivered production above the top end of our range at 30,153 BOEs per day. We also raised our full year production guidance range to 31,000 to 34,000 BOEs per day, implying we plan to achieve 44% annual year-over-year growth at the midpoint of our guidance range.

Second, over the last year, we have overcome massive cost inflation by lowering weighted average operated well costs from about $10.5 million in the first half of 2012 to $8.4 million in the first quarter of 2013. And we are well on our way to achieving our $8 million goal by the end of this year. The $8.4 million in the first quarter of 2013 and the year end target of $8.0 million are before savings from OWS. Including the impact of OWS, our well costs were $8.1 million across our operated program for the first quarter of 2013. So the right way to think about modeling our average cost to drill and complete wells going forward would be to include the $300,000 reduction attributable to OWS.

The team has been able to drive well costs down by lowering third-party service costs, improving efficiencies and continuing to optimize completion design. As a result, we're in good shape on our drilling and completion budget as we exit the first quarter, even as we delivered more gross operated wells and a few more net operated wells to production than what we had originally planned based on increases in working interest in the operated wells.

We still plan on completing 128 gross operated wells this year but it looks like we can add about 2.4 net wells to our forecast of net wells completed during 2013 based on our first quarter working interest improvements. So we're on track to spend $100 million -- $111 million less on drilling and completion CapEx in 2013 compared to 2012 while completing about 106 net wells in both years.

And lastly, in the midst of significant volume growth in 2011 and 2012, we have established the necessary infrastructure to allow us to optimize EBITDA by both increasing our net realized prices and lowering our cost structure.

We now have approximately 90% of our operated wells connected to natural gas gathering infrastructure and approximately 85% of our gross operated oil volumes flow on pipeline. On the saltwater disposal side, about 55% of our saltwater flows on our own pipes to our own disposal wells and an additional 20% is trucked to our own disposal wells.

So we're off to a very good start and hope to be able to carry that momentum through the rest of the year.

With that, I'll turn the call over to Taylor.

Taylor L. Reid

Thanks, Tommy. Two key items that we are focused on that will have a big impact over the long-term are a firm understanding of inter-well spacing as we go to full development and the optimal surface arrangement and pad operation that falls out of the subsurface well density.

As we have stated previously, an early understanding of the reservoir will promote optimal well spacing and prevent over-capitalization by drilling too many wells in a spacing unit, or by leaving reserves behind by drilling too few. Our work on this front will then lead to best practices for pad development by fitting the subsurface to the surface.

To evaluate the subsurface and inter-well spacing, we are utilizing 3 important methods: inter-well spacing pilot tests, extensional drilling in the first bench of the Three Forks and analysis of the lower Three Forks benches through coring and high resolution logs.

First, many of our wells this year will be testing the limits of the infill density patterns. Early results of the 2012 spacing test suggest that 4 wells per reservoir appear economic with little interference between wells. EURs for the wells in these pilots were in line with other wells in the area.

As we drill wells closer together in 2013, we are seeking to achieve the ideal spacing that maximizes the returns per spacing unit.

This year, we had 22 infill pilots spread across the acreage position, which will test well spacing of up to 6 wells per formation, implying up to 12 wells per DSU [ph] for the Bakken and first bench of the Three Forks combined. We should have some preliminary results of these tests near the end of the year.

Second, the 2012 Three Forks extensional program was very successful, with step-out wells in North Cottonwood, East and Middle Red Bank and in Montana, with results similar to Bakken wells in their respective areas. Based on these encouraging results, we have scheduled 15 extensional and step-out tests across the position in 2013.

We think that there is a high probability that the Three Forks is economic across most of our acreage position and we'll have more well results to share as we approach year end.

Lastly, in the first quarter of 2013, we cored through the lower benches of the Three Forks and performed enhanced log analysis for the 6 pilot wells that were scheduled for this year. We are early in the process of analyzing the data, so we will let you know more as we draw conclusions. Based on what we see, we will likely drill our first well on a lower bench late this year or early next year.

As we are testing the subsurface spacing, we are simultaneously working on surface well arrangements. We are drilling 60% to 70% of our wells this year on multi-well drilling pads. We've improved on the pad designs used in 2012 and are working on surface well configurations and battery designs that should enhance our pad operations as we transition into 2014. Our current design should allow us to drive down costs by 5% to 10% through operational efficiencies, shared services and centralization of tank batteries.

With the data we're gathering this year on the subsurface, we should be set up for optimum spacing as we shift to 80-plus percent pad development in 2014. We are making great progress on this front.

With that, I'll turn it over to Michael to discuss the financial highlights.

Michael H. Lou

Thanks, Taylor. We had another record quarter, with production north of 30,000 BOE per day and the tightest differentials we've ever delivered resulting in oil and gas revenues of $242 million in the first quarter.

Differentials were just 1% in the first quarter, down slightly from 1.5% in the fourth quarter of 2012, as we continue to move substantially all of our volumes on rail to the premium-priced coastal markets. As you know, the differential between WTI and Brent has narrowed more recently, so we are expecting our differentials to widen out a bit in the second quarter. In fact, as our marketing team works -- has worked May sales, they were able to add back some pipe into the mix, putting about 25% of our volumes on pipeline.

As we move forward, we will continue to optimize realized prices through leveraging of our third-party owned crude gathering system, which has multiple marketing options.

During the first quarter of 2013, we formed Oasis Midstream Services, a wholly-owned subsidiary to hold our SWD infrastructure and other midstream assets and give us optionality in the future. With the formation of OMS in the first quarter, we made the appropriate perspective changes to the way the financial statements are presented. Therefore, we now have revenue and operating expenses for OMS, which are related to third-party working interest owner volumes. Historically, revenue from third parties was an offset to our LOE but it is now presented in OMS revenue.

Additionally, we now charge a portion of our G&A and depreciation, which is associated with our operated volumes transported by OMS, to LOE. These changes resulted in higher revenue due to recognition of OMS third-party revenue, higher OpEx due to higher third-party OMS OpEx, lower G&A and depreciation due to OMS allocations and all of this taken together is essentially EBITDA-neutral.

We reported LOE in the first quarter of $7.18 per BOE. Had we not formed OMS, LOE would have been $6.58 per BOE, which was in line with our guidance range. Based on the new presentation, we adjusted our annual LOE range up by $0.50 per BOE to $6.25 to $7.50 per BOE. We have also lowered the top end of our G&A guidance from $85 million to $82 million, and a portion of the reduction is associated with the new presentation of OMS. Obviously, there are a few moving parts here but the end result is the formation -- of the formation of OMS gives us optionality in the future.

With the cash on hand and our recently increased borrowing base, we have approximately $1.4 billion of liquidity. Additionally, we layered in 2 additional hedges in the quarter in order to protect our drilling program and cash flows.

We currently have approximately 22,000 barrels of oil per day hedged in 2013, with floors and swaps just around $91 per barrel on average and 13,000 barrels of oil per day hedged in 2014, with approximately $91 per barrel floors and swaps on average, as well.

Another great quarter for our company, starting the year strong with excellent execution through the winter months, which sets the stage for a great 2013.

With that, we'll turn over the call to Regina to open the lines up for questions.

Question-and-Answer Session

Operator

[Operator Instructions] And our first question will come from the line of Dave Kistler with Simmons & Company.

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

Real quickly, very impressive on the well cost savings coming from, call it, 8.8 in '12 down to about 8.1 when you factor everything in, or 8.2. Obviously, 8% to 10% savings. You talked about at the start of the year going from kind of a 5% to 10% savings goal and then Taylor made in his comments the possibility of 5% to 10% savings associated with the pad configurations. How do we put all that together in terms of where costs are going from here? Obviously, it seems like you're going to continue to ramp those down and probably fall under $8 million throughout the year.

Thomas B. Nusz

You want to touch on that?

Taylor L. Reid

Yes, Dave. So this is Taylor. We -- price [indiscernible] made a big jump here early in the year and we're well on our way to our target at year end, and we continue to hold that target at $8 million. But based on where we stand, like you've mentioned, we've -- we're optimistic we may be able to do better than that.

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

Okay, okay. And maybe switching over a little bit, you kind of outlined at the beginning of your comments what you guys have done on the infrastructure build out with respect to gathering on gas, on oil, on saltwater gathering, disposal. When you think about those assets that are now in place, does that strategically put you guys in a better position as acreage within that infrastructure area may expire in terms of your ability to purchase it and be a cost advantaged purchaser of that acreage going forward? Just trying to think about competitively, as you fill out your portfolio through the balance of the year, does that put you in an advantaged position as a prospective buyer?

Thomas B. Nusz

Yes, I think it does, Dave. And it's not so much in the middle of the basin, but as you move out towards the edges, where things get to be a bit more cost-sensitive. As a practical matter, in a lot of these areas, especially in the central part of the basin, everything is pretty well held. But for instance, at the end of last year, we did a fairly sizable deal over on the northern part of North Cottonwood and some of that driven by our ability to execute as well as impending the infrastructure. We got that oil system in, in fact it just came on here a month or so ago. So I think those things do give us an advantage, whether it's the third-party on gas and oil or the internal on saltwater.

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

Okay, I appreciate that. And then one last one. With the creation of OMS, liquidity is in great shape, so is this a vehicle that's designed to give us more transparency with respect to cost in that side of the business and actually revenues and EBITDA on that side of the business? Or is it being set up as something to be spun out over time? And should we read anything into the fact that, with plenty of liquidity, the possibility of spinning that out, that we could see accelerated activity from you guys at some point?

Michael H. Lou

I think on the OMS, Dave, that we formed it just to give us optionality in the future. Like you said, we don't have a need for that liquidity currently. We have a very strong balance sheet, a lot of liquidity. So it's nothing that is a near-term thing for us necessarily, but just gives us options going forward.

Operator

Your next question will come from the line of Noel Parks with Ladenburg Thalmann.

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

Just a couple of things. Looking at the working interest that you picked up around your areas, I just want to get a sense of roughly what the cost was of those?

Thomas B. Nusz

Are you talking about just the increase in our interest, our existing wells? Or additions to our acreage position?

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

Well, I meant the existing but if the -- if you could give a little detail on any other additions, that'd be great, too.

Michael H. Lou

So in the first quarter, our average working interest, if you just kind of do the math, looks about 86% average working interest. Now we knew that the first quarter was going to be a little bit higher on average just because of the well -- makeup of the wells that we were completing there. So our budget initially was around 79% in the first quarter. So you had an uplift of 7% working interest across those wells. Now that comes in, there is kind of a pickup on some of the acreage that we'll just buy in, some of it we'll kind of swap into, some of it -- a little bit of it will be nonconsents, so it's kind of a mixture of things. Our average acreage cost, it tends to be about $1,000 an acre on average kind of throughout the program last year. That's kind of -- that kind of hold through this year. So that gives you a bit of a feel on cost of those working interest increases.

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

Great. And talking about acreage out there in general, I guess, I just wonder -- I'm sure pretty much the low hanging fruit has clearly been picked up and leased. Is there around your properties any significant -- I don't know, I guess I'd call it dormant acreage, as acreage that just requires really tough land work or just unusually sort of uncooperative landholders? So I guess I'm just trying to get a sense of, in your existing footprint, if we look out a little longer-term, do you view the chances of picking up more acreage as being pretty good or pretty much it's a done deal, not much left?

Taylor L. Reid

We think that we'll be able to continue to build our acreage position, and it's really, like Tommy suggested, not really the core middle of the basin that's highly competitive. It's out a little bit more on the edges, where we've -- with our cost structure and the infrastructure we have in place, we have some advantages that have allowed us to build a position. It takes a lot of work, anything from guys that could hold leases currently to other people that -- operators that hold the production and/or the acreage that we'll buy. So we'll just continue to try to build that position and we think we'll do it. Not necessarily in gigantic chunks but in pieces that'll build up over time.

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

Great. I just have one thing on the income statement from the quarter. I'm sorry if you mentioned this before. I noticed that the well services expense line was, I think, sequentially lower than the prior period. I just wondered if there was any new trends there?

Michael H. Lou

That's just a combination of things of the type of wells that you're completing. So you might have some more wells that are completed that have lower proppant cost or -- the type of mix is important and then the working interest side is important. So remember, when we report that OWS line item, it's only our third-party piece. So in this case, if you look at the 86% average working interest, what shows up in our income statement's only the 14% of the work that they do that's not for our own wells or our own working interest position. So it can be higher or lower in any given quarter based on those factors.

Operator

Your next question will come from the line of Ryan Oatman with SunTrust.

Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division

I was wondering if you could talk about the rationale to form OMS and what you're seeing in the basin right now on saltwater disposal trends that, that subsidiary might be able to capitalize on?

Michael H. Lou

Yes, Ryan, good question. On OMS, once again, it's more about optionality for us. We have now a fairly large system on the saltwater disposal side specifically, that we've been investing in over the last couple of years, we'll continue to invest in. We've got a system kind of across most of our acreage that continues to be built out. So right now, it's forming the subsidiary really just to put the assets in there, to provide optionality in the future in case we want to do something with it. Nothing that we have in mind near-term but, if you can kind of leverage that system, right now we just kind of feel like it gives us the most optionality and most transparency if we put it in a separate subsidiary.

Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division

Okay. And is there a chance to increase kind of the third-party use of that system as opposed to just keeping it more internal?

Michael H. Lou

Yes, right now we only move water on our own operated wells, and so there is a third-party component to it. But you're right. Is there an ability to bring in third-party operated wells onto the system? That's certainly a possibility. We're not going there right now but that's certainly a possibility for the future.

Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division

Okay. And then just a quick modeling question. G&A came in pretty low in the quarter, less than $14 million. So I was just wondering if there's downside potential to that guidance of $75 million to $82 million and if you can just walk us through kind of the assumptions there?

Michael H. Lou

Yes, it's a good question. There's a couple of pieces there. The $75 million to $85 million, the old range, we did lower kind of the top end because we came in a little bit lighter in the first quarter. There is an impact, as we formed OMS, now a portion of our G&A actually gets allocated to OMS. It gets kind of wrapped up into that allocation so we'll only show a smaller portion, which allows our total G&A to come down a little bit. But we feel pretty good about that new range that we just put out.

Operator

Your next question comes from the line of Subash Chandra with Jefferies.

Subash Chandra - Jefferies & Company, Inc., Research Division

I know you said it was early on the lower benches but I was curious if you could comment on some of the things that I think would be visible from the work you've done already, like I would expect you might see oil saturations, thicknesses, frac barriers, et cetera, if you can comment on that. And then second, sort of the -- where were the verticals placed, over how wide an area, if you could talk to it?

Thomas B. Nusz

Okay. So we -- the location of the pilots range across our acreage position. So we had -- have them in the east side, in North Cottonwood, in Middle and South Cottonwood. We have 2 of them that are -- or actually 1 right now in Indian Hills. We had an existing 1 that was already in Indian Hills. And then 1 in Red Bank and 1 in Hebron. So they cover across the whole position. As far as results, we have the cores. We've done visual inspection. There's -- the testing work is underway on the cores, so we don't have that data analyzed yet. We do have log data but it's important that we get the high-resolution logs to match up on core -- I mean, match up with the log analysis to confirm and make sure that what we're seeing on logs is accurate. We are -- I'd just say that we're encouraged by what we've seen, for sure, in the first bench. It's present across the position and our results in the first bench continue to support that. The second bench, present across the position and looks like it may have appreciable saturation. The thing that all this work is focused on is the thin-bed, embedded nature as you go into the Three Forks and we're definitely seeing that. We're picking up more porosity and potentially oil saturation than you would otherwise see if you just had standard logs. And that's kind of all we can say about it right now. Like you said, we're encouraged. It's going to take us at least half the year to get -- to start to get -- in half-year, I mean by the summertime, to start to get some of that core work back. And then as we integrate all that data, like I said, by year end, we'll probably pick some places to test the lower benches.

Subash Chandra - Jefferies & Company, Inc., Research Division

Okay. And this program was also designed to pick up third and fourth benches, et cetera, right?

Thomas B. Nusz

Yes, it's actually -- we cored all the way through the sections. So through the -- all the benches in the Three Forks.

Subash Chandra - Jefferies & Company, Inc., Research Division

Okay. And one more for me. Were there any other extensional TFS completions since the April presentation update?

Thomas B. Nusz

No. The latest ones were the ones that we'd previously talked about.

Operator

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

Mostafa Dahhane - Wunderlich Securities Inc., Research Division

This is Mo sitting for Irene. Just a quick question on the oil pricing. How do you feel about the Bakken differential going forward?

Michael H. Lou

Yes, differentials have been, obviously, extremely strong for the last couple of quarters. Like we said, it's gapping out here a little bit in the second quarter. Overall in the basin, given the amount of takeaway capacity in the basin, which is now well over the current production levels, we feel pretty good that the differential is, call it capped out a bit. So a lot of it's going to be dependent upon the relationship between that coastal market price, or call it Brent right now and WTI and what that differential looks like. So as that narrows, our differential in the basin gets a little bit wider. And that's what you've seen here recently. But overall, we feel in a very good position differential-wise, that we won't see the $20-plus differential blowout that we saw in the early part of last year, which was mainly because of a very constrained takeaway capacity market. So given that you have a lot of capacity now, you shouldn't see those big blowouts in the basin going forward.

Operator

Your next question comes from the line of David Deckelbaum with KeyBanc.

David Deckelbaum - KeyBanc Capital Markets Inc., Research Division

My question is on the Three Forks, primarily. I recall, your primary locations are based on 110,000 net acres of your position. I thought you said earlier that you're seeing encouraging data that you think it's prolific across all of your acreage. I guess, could you give a little bit of color around that, and at what point -- or how much time do you think you'd need before you'd include those locations in primary inventory?

Taylor L. Reid

Yes. So the 110,000 acres that you're talking about is based on the wells that were tested kind of through mid last year. And so there are a few wells outside of that area that we have data on. They were drilled last year, completed last year. We talked about them a little bit in the third and fourth quarter. The results on those wells, they're light. They look like the Bakken wells that are around them. So they're economic. One is the Mercedes well, which is in Middle Red Bank. And another one is the Justice well, which is in Montana,, in the Hebron block. Both of those wells look to be economic. And then -- and so based on that then also, the North Cottonwood well we drilled last year, the Zdenek, we just include a very small area around it as being within primary but the rock, the subsurface from that down to the South Cottonwood area looks very consistent. And so as we drill out additional tests in that North Cottonwood area and then the West Red Bank, in the Montana areas this year, we just -- based on all the data we have, we're encouraged that you're going to see that economic area in the Three Forks significantly expand and probably cover most of our acreage. But we still got to get the data and confirm. All that's just our early indications.

David Deckelbaum - KeyBanc Capital Markets Inc., Research Division

Sure. And my last question is just on the well costs. You guys have done a great job, just at least measuring expectations and coming in beneath cost now. How much of that $400,000 -- I guess, how would you break that out in terms of efficiencies or bid prices on contracts just coming in lower, because obviously it's before the impact of OWS. And then as you look out to '14, would it be unreasonable to assume that another 10% reduction in cost is unreasonable?

Taylor L. Reid

Yes, so on the first question, to the $400,000, I assume you were going from the 8.8 to the 8.4, that was really a combination of some savings on the service side but probably a lesser amount in terms of percentage than we saw last year, maybe in the 25% range of that savings and then really, the rest of it through efficiencies. So some of it, a little bit of pad savings and then you got savings on well design and cycle times. Those would be the main components. So less service cost and you're going to see that as the year continues. It's more on the efficiency side where you're going to drive the cost down. And then as you go into 2014, we think we'll continue to get more efficient and bring the costs down but probably not as -- in large of chunks. I'd say where we stand right now, maybe it's more in the 5% range.

Operator

Your next question comes from the line of Mark McDowell with Peregrine Investment.

Mark McDowell

Can you talk about the long-term plans for the midstream segment? Do you think it will ultimately end up being monetized or in an MLP structure, or do you think that will stay internal long-term?

Michael H. Lou

Yes, I think we're very early on in that. Right now, we're still focused on growing that saltwater disposal system to make sure that we kind of touch our whole acreage position in making sure that we can kind of keep up with the production levels with our disposal capacity. So we're highly focused on making sure that, that is an efficient system and it gets to the same point where the crude gathering and the gas gathering is in our systems that we have with third parties right now. So right now, we're operating it. We're putting it into the separate subsidiary to give us options in the future but it's a bit early to figure out where we'll go with that.

Operator

Your next question comes from the line of David Tameron with Wells Fargo.

David R. Tameron - Wells Fargo Securities, LLC, Research Division

Can you guys talk a little bit about the step-outs that you mentioned during the prepared remarks, some of the stuff you're doing? And can you just give us more color on that? Step-outs into Montana, from the Missouri stuff?

Taylor L. Reid

Okay. So you come at the Three Forks in -- so the Three Forks, we've got 15 wells scheduled that are outside of what we've called the primary, kind of derisked Three Forks. And those wells will be, again, spread across the position. There's probably -- I don't have the exact numbers but on the order of 5 or so in North Cottonwood. And then you've got additional wells in Middle, in West Red Bank and then some additional wells in Montana. So that 15 kind of spread across that position outside of South Cottonwood, Indian Hills and East Red Bank.

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

And the timing is just going to be over the next 2 to 3 quarters, 3 to 4 quarters? How should we think about that?

Taylor L. Reid

Correct, it's going to be spread. Some of that is -- some of those wells are on pads, where you're going to have a rig get on a pad and drill multiple wells. But it will be between now and end of the year.

David R. Tameron - Wells Fargo Securities, LLC, Research Division

Okay. And then, Tommy, in the past, you've talked about potentially -- you guys have a new ventures group that's looking for new areas. Any update you want to give us on that?

Thomas B. Nusz

The guys, as we've talked about before, they spend and have continued to spend -- actually, it's probably gone up a bit. We used to talk about it, let's call it, 60% to 65% of their time on the Bakken and then, call it, 15% of their time on Williston expansion. But -- and then, the rest on other things, other upper Rockies-tied oil things. But as a practical matter, those guys have been spending recently probably 100% of their time on just the Williston stuff. And it's -- there are a couple of larger deals out there but then there's these little add-on things that we look at all the time. And some of them take time -- I mean, some of these things, we'll work for a year before we get them done. So but we've been keeping them busy on the Williston stuff.

David R. Tameron - Wells Fargo Securities, LLC, Research Division

Okay, all right. And then final question, when you run the math, guidance looks conservative for the full year. Any comment on that?

Thomas B. Nusz

I think consistent with what we've done in the past, we try to approach it from one direction, not overshoot and then come back and adjust that back down. So I think we'll do that again this year.

Operator

Your next question comes from the line of Dan McSpirit with BMO Capital.

Dan McSpirit - BMO Capital Markets U.S.

Can you sketch for us what working interest looks like, say, on average over the balance of the year and in the out-years, given the increase in the first quarter?

Michael H. Lou

Yes, Dan. On average, we've got about 73%, 74% average working interest through the year. It was a little bit higher, at that 79% level modeled in for the first quarter and so it's a little bit lower kind of through the rest of this year. Clearly, there is a possibility of a bit of upside on the working interest side, like we've did last year and like we did in the first quarter. But it's difficult to quantify the impact. Going forward in our program, it's probably somewhere in that 70% to 75% average working interest kind of throughout our position in future years.

Dan McSpirit - BMO Capital Markets U.S.

Great. And as a follow-up, can you speak to days spud-to-spud and spud-to-sales today and what it looks like going forward, kind of recognizing the impact from pad drilling?

Taylor L. Reid

Yes. So days for spud to rig release is what we really track and we continue to be around 23 days right now. We had a little bit of a tick-up and closer to 24 in the first quarter. But that was due to all the pilot holes that we drilled, which is -- we had to drill vertically all the way through the section, plug back and then kick off. So it just added days to the wells. So we're optimistic we will continue to drive that down. There's a point of diminishing returns at some point where it's tough to get that further but we think we'll push it down some more this year. As you go to pad, that's going to help some, as well. But the biggest help there really is on the move, so that's from releasing the rig and getting to the next one. Instead of that being a 5- to 8-day process to rig down, move to the next well and spud, it's more like a day to skid the rig and get over the new hole and get back to drilling.

Thomas B. Nusz

But as you think about spud-to-spud, it used to be -- we used to call it like 10 wells per rig per year because our spud-to-spuds or like 35 to 37 days, whereas today, it's basically 12 wells per rig per year. So if you think about that at a high level, it's kind of 30 days plus or minus spud-to-spud.

Dan McSpirit - BMO Capital Markets U.S.

Right. Got it. I appreciate the before and after there. And as a follow-up to that, as you move deeper into development mode, where operations become more, maybe, of an exercise in throughput, how does the pace of drilling wells change and with the completions, knowing that there are certain physical limits or opportunities exist? That's maybe more of a theoretical question but just asking just the same, in an effort to get a better handle on the growth profile not next quarter but, really, in the out-years, in the out-periods.

Thomas B. Nusz

So you mean a limit in terms of the activity that we can do or...

Dan McSpirit - BMO Capital Markets U.S.

Right, exactly. How do you think about that? Just -- again, just trying to get a better handle, better picture on the growth profile beyond 2013.

Thomas B. Nusz

Yes, what I would say is at this point, to really project meaningful reduction in the numbers that we just talked about, it's probably a bit difficult to plan on improved cycle times, whether it's spud-to-spud or spud to rig release. On spud to rig release, I mean the best we've done so far is 15 days. But you're always going to have a bit of an outlier. But can we get from the 23 to 20? Maybe 18 if things are really going well. But I don't know at this point going forward that you're really going to see step changes. The thing that tends to swing a bit more is the spud to first production for any number of reasons. When we IPO-ed, as I recall, Taylor, we were running at about 90 days and over the course of the 2 last years, it's -- at one point, it got up to about 120 days. Now it's back in the 90-day range, 80- to 90-day range. I think -- and keep in mind, with these pads, you're kind of batching the work. So it's going to be a bit choppy until you get everything working on pads and then everything will come back in-line. And so that is one place where you should see, once you're in full pad development mode, effectively -- now it's not this clean just because of the way you have to batch the work on the wells, but you ought to be somewhere in the 65- to 75-day range spud to first production once everything gets kind of into full manufacturing mode.

Michael H. Lou

And Dan, if your other part of your question is around pace of how many wells we're going to drill each year. That -- this year, we're drilling 128, we're completing 128 wells. What you see in our presentation is that our inventory of operated wells, at just over 2,000 operated wells, we kind of say we've got a 14-year inventory. That's assuming about 145 well pace. And so that's a way you can kind of think about next year. It might be a little bit higher than this year, it may come through efficiencies it may come with -- because of another rig, but that's kind of how we're thinking about pace going forward. It is maybe a little bit faster than where we are this year. Right now the plan is that we'd likely pick up a rig to get to that pace so that our exit rate's a little bit higher than where we entered this year.

Operator

Your next question comes from the line of Eli Kantor with Iberia Capital.

Eli J. Kantor - Iberia Capital Partners, Research Division

I was hoping you could touch on differences you see in wellhead economics across your acreage position. It looks like well productivity is a little bit more prolific towards the center part of the basin relative to your acreage to the west and to the north. Wondering how much of the difference in well performance is offset by difference in well costs?

Taylor L. Reid

So I'll highlight a couple of areas just to give you an idea what you're talking about. In the middle part of the basin, Indian Hills, deeper, we still use about 60% ceramic in our completions. Our well costs are higher there, a little over $9 million, and -- but very robust economics with the recoveries on the wells in that area, which are kind of 650,000-barrel range, on average. And then if you go to North Cottonwood, you see lower well recoveries, more in the 450,000-barrel range, but well costs are significantly lower. So we're drilling and completing wells there just over the $7 million cost, right around $7.2 million right now. And so the economics of those 2 areas end up being pretty similar. Indian Hills may be a little bit better but North Cottonwood's pretty robust as well. And then depending on where you are in the acreage position, we've got -- it varies, cost and returns.

Eli J. Kantor - Iberia Capital Partners, Research Division

And you had mentioned that the recent $400,000 reduction you've seen in well costs was at least partially related to a change in well design. Are you still testing different completion designs or are you pretty much set with the different mixes of ceramic and sand that you're using across your acreage position?

Taylor L. Reid

We continue to optimize our completions and we varied everything from profit, like you're talking about. So we continue to test higher percentages of sand as opposed to ceramic in a number of areas. So in Red Bank, we've now done a number of fracs that are 100% sand. In Indian Hills, we tested some wells with a much higher percentage of sand, closer to 70% as opposed to the current -- or the past amount being more like 40%. But we're also trying a number of different things as well. So the fluid that we pump, the viscosity of the fluid, the rate that we pump the fluid, size of the stages, number of stages, and so depending on where we are in the basin, optimizing all those things to try to really maximize the EURs in the wells and minimize the cost.

Operator

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

Peter Mahon - Dougherty & Company LLC, Research Division

Most of my questions have been answered but I just had one. This has to do with your saltwater disposal system. You talked about 55% of your water being -- running through your gathering lines, as well as being deposited into your disposal wells. It seems like the progress on that system has kind of been stagnant for the last quarter or 2. Can you talk about how that would evolve over the next couple of quarters and how that might impact the timing of the $2 to $3 of savings in LOE costs that you've talked about in the past?

Michael H. Lou

Yes, the saltwater disposal system continues to progress pretty nicely now. Realize that as we're growing this, we're trying to keep up with the growth in production that we're seeing on the oil side as well. So although the percentages don't move as dramatically as maybe you'd like to see, you are moving pretty rapidly in terms of drilling new saltwater disposal wells and putting in that system. That being said, we are moving towards where we can try to get about 70% to 75% of the volumes online. Hopefully a lot of that will be online before the year end. But that's kind of just a ballpark range that you're going to get to. You're always going to have a piece of your business that is trucked to third-party wells. And so we don't have the kind of the same goal of getting to 90% to 95% like we are on the gas side or the oil side in terms of gathering. So we'll always probably use a component of truck costs -- of truck on the saltwater disposal system.

Operator

Your next question comes from the line of Gail Nicholson with KLR Group.

Gail A. Nicholson - KLR Group Holdings, LLC, Research Division

I was just kind of curious, looking over Montana, there's some operators that are shooting seismic to locate some Red River potential. And I was curious if that's something that you might -- guys might consider doing on more of the fringier Montana acreage? Or if you see any potential -- other potential zones outside of the Bakken or Three Forks out there?

Thomas B. Nusz

Yes, really across the whole position we're interested in other objectives. We've just been so focused on first, the Bakken. It was really first big area of focus for us and then holding our land, and now we've shifted more to the Three Forks. But a high degree of focus on those 2 producing formations. And then we will continue to look at the whole column, both shallower and deeper, as we go.

Michael H. Lou

And one more thing to add on that, Gail, is that, I think, our Montana acreage is something that's somewhat misunderstood. But if you're kind of north of that Elm Coulee trend and south of the Brockton-Froid Fault, most of that looks like North Dakota, for the most part. So there are certainly a lot of operators doing things that are in Montana that are outside of that area that we just talked about that looks a little different than what we're doing kind of in this core part of the Bakken. But all of our acreage, even in Montana, looks kind of like what we're doing in North Dakota.

Gail A. Nicholson - KLR Group Holdings, LLC, Research Division

Great. And then just out of curiosity, on the wells that were completed in Q1, what was the percentage that were completed on pads?

Michael H. Lou

That's a smaller number than the -- if we talk about 60% to 70% on the year. We don't have that exact number in front of us, but that -- it is a smaller number at the beginning part of the year and most of the pad work is towards the back half of the year.

Operator

And at this time, there are no further questions. I will turn the conference back to Oasis for any closing remarks.

Thomas B. Nusz

Thank you. Oasis continues to differentiate itself as one of the premier operators in the Williston Basin. We've been able to deliver on expectations, drive down well costs, increase price realizations and expand our resource base. We're proud of the Oasis culture, the accomplishments of our team and the direction we're going as a company.

As always, thanks for everyone's participation in our call and then the continued support of our shareholder base.

Operator

Ladies and gentlemen, this does conclude today's conference. Thank you, all, for joining, and you may now disconnect.

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