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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

Peter Mahon - Dougherty & Company LLC, Research Division

Eli J. Kantor - Iberia Capital Partners, Research Division

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

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

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

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

Mostafa Dahhane - Wunderlich Securities Inc., Research Division

Stephen F. Berman - Canaccord Genuity, Research Division

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

Oasis Petroleum (OAS) Q4 2012 Earnings Call February 26, 2013 11:00 AM ET

Operator

Good morning. My name is Ginger, and I will be conference operator today. At this time, I would like to welcome everyone to the Year-End 2012 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 the conference.

Michael H. Lou

Thank you, Ginger. Good morning, everyone. This is Michael Lou. We are reporting our fourth quarter and year-end 2012 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 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've 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 report on Form 10-Q. We disclaim any obligation to update these forward-looking statements.

During this call, we will 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. Following our normal format, I'll make some introductory comments. Taylor will follow with some operational color, with a focus on our 2013 plan. And Michael will finish with a few financial highlights.

For the first 18 months post IPO, you heard us consistently talk about executing on our identified drilling inventory and focusing on holding our tremendous acreage position. With that objective in sight, our senior leadership team gathered at the beginning of 2012 to identify strategic risks and opportunities that we would be facing over the following 12 months as we transition from just holding acreage to full development.

We had a broad dialogue covering important topics like our safety program, organizational development, capital discipline, oil movement and the resulting differentials in continuing cost control. With this as a framework, we established ambitious milestones and target metrics for 2012. As you've seen in our results, the team delivered on our objectives, with results including value-added growth and production, reserves, acreage and drilling inventory, capital efficiency and oil price realizations.

As we looked to 2013, we have again outlined our strategic agenda for the next 12 to 24 months including optimizing our development program, including pad operations, infill density and continued focus on cost control; oil supply demand in North America and the resulting pricing and differentials; organization development and improvement, including additional focus on regulatory items and community relations; and finally, business growth. Taylor will touch on 2013 in more detail in a moment. But before he does, I want to start with a discussion of value-added growth in 2012.

We grew production 110% in 2012 to 22,500 BOEs per day, and we exited the year with 27,600 BOEs per day in the fourth quarter. Our proved developed reserves grew by 95% to 70 million BOEs, and total proved reserves grew 82% to 143.3 million BOEs, resulting in a proved developed to total proved ratio of 49%. Most importantly, we accomplished this growth while improving capitalization efficiency.

Additionally, we were able to improve overall operational performance significantly in 2012 by staffing the right personnel throughout the organization and working constructively with our service providers on both cost and efficiency.

We also successfully high-graded and grew our net acres by 9% in 2012 up to 335,383 total net acres. Of this, we count approximately 305,000 as core to the Bakken. As of year end, we had 265,000 acres held by production. Through acreage acquisitions and various trades in 2012, we added 37 controlled operated drilling spacing units to our inventory. Increasing the number of drilling blocks, further derisking the Three Forks across our position and improving comfort around infill density resulted in an increase to our gross operated primary inventory up to 987 locations.

Next, Oasis delivered a great year in terms of capital efficiency. We've drove down average well costs from $10.5 million in the first half of 2012 to approximately $8.8 million while maintaining our EURs. This was accomplished through a combination of lower service costs, efficiency gains and completion and well design optimizations. As we move into 2013, we'd expect 60% to 70% of our wells to be on pads, which should continue to improve efficiencies and reduce cost.

The third driver of value the team has been focusing on is improving price realizations. Just over a year ago, we started moving our operated oil production into a third-party oil gathering system, which gives us access to 6 different rail facilities and 4 pipeline connections. The increased optionality that rail provides has allowed us to drive down differentials. In 2012 our differentials to WTI dropped from 14% in the first quarter to 1.6% in the fourth quarter. We've been able to utilize rail to get crude to coastal markets where it can achieve better price realizations than if the volumes were piped. We currently have about 80% of our crude transported via rail to take advantage of the strong differentials.

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

Taylor L. Reid

Thanks, Tommy. In 2013, we're expecting production for the year to range between 30,000 and 34,000 barrels equivalent per day on average, and we're targeting 27,000 to 29,000 barrels a day equivalent for the first quarter of 2013. In an effort to mitigate the impact of tough winter conditions, we are utilizing multiple well pads that will limit the amount of rig moves during this time.

On pads, production tends to be delayed as the time from spud to first production is increased for all but the last well drilled. Consequently, early year pad drilling should result in back-loaded production, with moderate growth during the first half of the year and a ramp in the third and fourth quarters.

In 2013, we have a total capital expenditure budget of just over $1 billion and plan to complete 128 gross operated wells and 133 total net wells. Approximately 88% or a little less than $900 million of the capital budget is directed to our drilling and completion activities, with the remainder spent primarily on other items, such as leasehold, infrastructure, geology and well services.

Like Tommy mentioned, our pad development program is a key initiative in 2013. As we move into pad drilling, we will be able to mobilize rigs more efficiently, improved frac crew utilization, decrease our footprint and implement central tank batteries to reduce well and operating cost. Ultimately, we expect to reduce well cost by 5% to 10% compared to a single well. We're budgeting an average of $8.6 million per well and have set an internal goal to drive well cost down to $8 million by the end of the year, although this is not reflected in our budget.

One of the key cost reduction drivers in 2012 was the impact of OWS, and it will continue to be a key initiative in 2013. With the utilization of OWS, we were able to save $17.5 million capital expenditures on Oasis-operated wells. In 2013, we are forecasting savings of approximately $500,000 for gross well completed, and we intend to use OWS on approximately 40% to 50% of our wells.

Our third initiative for Oasis will be to improve our understanding on both infill density and Three Forks prospectivity across our position. We expect to drill infill pilots in 22 spacing units, with effective spacing ranging from 6 to 12 wells per spacing unit. We currently include from 3 to 7 wells per spacing unit in our primary inventory so the results of our pilots have the potential to add significantly to our primary inventory.

In 2013, we hope to move more of our Three Forks inventory into the primary categories as well. Currently, we have approximately 110,000 acres or about 1/3 of our acreage included in our primary Three Forks inventory. At the end of 2012, we brought on production in 2 additional extensional test. The Justice in Hebron and the Mercedes in Red Bank. Early results from these wells are encouraging as they look similar to nearby Bakken wells. Additional extensional tests in 2013 include 8 Three Forks wells in North Cottonwood, 10 in Red Bank and 2 in Montana. The results of 2012 and 2013 Three Forks extensional program will help us to shift more of the Three Forks inventory from potential to primary. Including the extensional wells, we plan to drill approximately 50 Three Forks wells in 2013.

In addition to these Three Forks test, we will have 6 vertical pilot wells drilled into the lower benches by the end of the first quarter. The vertical pilot wells will have cores and high-resolution logs to provide data in the lower benches in each of our major producing areas. These results will help us to select the areas where we will pilot test second and possibly third bench wells in late 2013 and in 2014.

To wrap up our operational highlights, our infrastructure is substantially complete for oil, gas and produced water. Our oil gathering system will complete on the East side by the end of the first quarter, and a small section of Indian Hills just north of the river will be completed by the end of the second quarter. Once these are established, we'll have more than 80% of our volumes falling through pipe.

Our gas infrastructure currently captures approximately 90% of our gas in liquids production and will continue to tick up as we connect our wells. In the fourth quarter, we were able to produce and sell approximately 15.3 million cubic feet per day or 50% more gas than the third quarter due to new well connections in October.

Finally, through our SWD system, we are currently disposing of approximately 75% of our produced water into Oasis-operated SWD wells, with approximately 55% flowing through our pipelines. We will continue to leverage the backbone of our SWD system as we connect new wells and ultimately reduce our operating cost associated with water handling.

In 2013, we are expecting LOE to be between $5.75 and $7 per BOE.

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

Michael H. Lou

Thanks, Taylor. We had another great year as we continue to execute on our plan, drive down our well costs, expand our leasehold position, capitalize on higher price realizations and build out our team.

For the year, we spent $1.15 billion and completed 117 gross operated wells. Differentials for the quarter were at an all-time low at 1.6%, largely due to the benefit of rail getting to the coast. And we'll continue to look for ways to optimize our realizations. Production taxes were 9.4% in the year. And LOE closed out the year and the quarter at $6.68 per BOE, down from $7.23 per BOE in the third quarter. Our total G&A was $57.2 million, including the G&A associated with OWS.

In the fourth quarter, we had adjusted EBITDA of $164 million, an increase of 17% over the prior quarter, primarily due to production growth and differential improvement. For the full year, adjusted EBITDA was $512 million, and we exited the year with $239 million of cash on hand. Combining this with our revolver capacity of $748 million, we had total liquidity of $987 million available to invest in the business in 2013.

In light of this, to protect our drilling program, we have also hedged approximately 20,700 barrels of oil per day in 2013 at approximately $90 floors and 8,500 barrels of oil per day in 2014 at approximately $91 floors.

To close out, we are excited about what 2013 has in store. We have a great team and the right assets to drive execution, growth, efficiency and shareholder value.

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

Question-and-Answer Session

Operator

[Operator Instructions] Your first question comes from Peter Mahon.

Peter Mahon - Dougherty & Company LLC, Research Division

I just have 2 questions. You talk about well costs going down in 2012 and going down further in 2013. Can you give me some idea of how that should roll through the depletion line, like when should we start to see that line item decline? Because steadily throughout 2012, we saw that increase on a per BOE basis. So how should we think about that in 2013 and into 2014?

Thomas B. Nusz

Yes, Peter, DD&A is a lagging indicator of our well cost, and so we reset our DD&A twice a year. So what you'll see is that the third and fourth quarter of last year really reflects what happened in the early part of 2012, so it reflects the higher well costs from the beginning part of the year. And as we move into this year and the first and second quarters of this year, you should start to see that come back down. And certainly throughout the rest of the year, you'll see that DD&A rate come back down a little bit.

Peter Mahon - Dougherty & Company LLC, Research Division

Sounds great. And then you also mentioned that more of your production is coming out of the Montana side of the play. When you look at the well results so far, have they been consistent with kind of your decline curve that you set out maybe a year or 2 ago?

Taylor L. Reid

Generally, the wells in Montana have been consistent with what we were seeing about a year ago and continues to play out Montana positively.

Thomas B. Nusz

Albeit, that tend to be more to the lower end of the type curve range that we've set out there.

Taylor L. Reid

Yes, so they're probably more in the type curve of 600 MBOEs, and the average wells in Montana are probably more in the 450 to 500 MBOE range.

Operator

The next question is from Eli Kantor.

Eli J. Kantor - Iberia Capital Partners, Research Division

I had 2 quick questions. First is on the Middle Bakken and TFS, 3 by 3 downspacing pilot that you completed last year. It looks like results from the Middle Bakken were pretty much just as good as what you had achieved from stand-alone completions in the field, but the rates from the TFS wells were not as prolific. And I was wondering, if you're seeing any -- what you're seeing on the performance end from the TFS wells and if the lower peak month rates are related to geology or if it's a completion issue?

Taylor L. Reid

Which pilot are you talking about? The Davis unit? Is it in Indian Hills?

Eli J. Kantor - Iberia Capital Partners, Research Division

Yes, that's right. It's the Davis unit.

Taylor L. Reid

Okay. So there are -- one of the Three Forks wells in that pilot, we were only able to initially get 10 stages off in the well. So the early results on that well were muted. We have gone back and finished that frac, and so the rate is up on that well. In general, when we look across the positions, so the areas where the Three Forks is working, Alger, the wells in North Cottonwood, Indian Hills and Eastern Red Bank, generally, the Three Forks wells are performing pretty close to what the Bakken wells are doing in the area to a little bit below it. So about the same to at most, 10% down, but it's still early days in terms of the Three Forks program. To date, we drilled 25 total Three Forks wells versus hundreds in the Bakken.

Eli J. Kantor - Iberia Capital Partners, Research Division

That's helpful. My second question is on TFS development in Red Bank. When you look at your recent result from the Arlyss well and then pure results from Brigham and from Continental, it looks like peak month rates declined as you move from east to west. And I'm wondering if that's a fair assessment? And if so, would you expect the Mercedes well or has the production that you've seeing from the Mercedes well been below that of the Arlyss? I'm just trying to get a sense of the production variances in your opinion or due to differences in completion design or due to a change in geology?

Taylor L. Reid

So as you go east to west, I think that's a fair assessment and that it's consistent in the Bakken as well as in the Three Forks. So production tends to drop off as you go further west and water production tends to increase. So the Mercedes is likely to not produce at quite the same rate as the Arlyss but will be in the ballpark, and it's likely that the Mercedes was likely to be similar in the Bakken wells and in and around which it produces.

Operator

Your next question is from Ron Mills with Johnson Rice.

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

A couple of questions. One, maybe -- I don't know who it's really for, but on the marketing side and the price differentials, you talked about apparently 80% rail and within the next few months, you'd have 80% available to you via pipeline of your production. How flexible are you in terms of being able to change between pipe and rail to take advantage of regional differences and getting your crude to particular markets?

Thomas B. Nusz

Yes, so there's 2 things that are in there, Ron, and so it's probably good to clarify that a little bit. But when we talk about what's on infrastructure, that's our gathering system. So pretty soon, we'll be at 80% gathering -- on the gathering system inside the basin. And then that gathering system allows us a lot of flexibility of ways out of the basin. And so when we talk about 80% rail and 20% pipeline, we've got access with that gathering system to get to 6 different rail sites, 4 different pipeline sites. And then it's pretty easy for us month-to-month to move that back and forth to basically the best price. Right? And so what we've kind of consistently said is we do want to keep some diversification. We'll kind of keep in that 15% to 20% range in both pipe and rail, and then we'll use that middle 60% to 70% of our volumes to go to the best price. Currently, that's on the rail side, and that's continuing into the first quarter. But we'll just kind of continue to monitor where we're going to get the best price and go there, and it gives us the flexibility to do that.

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

Okay, great. And as you look out over the course of 2013 in terms of the differential outlook, do you expect the fourth quarter numbers to move back towards where the historical is, maybe not to the same magnitude, but -- or is there something going on in the short-term basis that provide a lot more comfort over the first half of this year versus the second half of the year from just a differential expectation standpoint?

Thomas B. Nusz

Yes, from the long-term perspective, I think it's hard for us to do anything but go back to kind of historical levels. If you look at lease sales, probably more in the kind of 12% to 15% historically, now with this infrastructure, with the gathering system that we got, long-term differential is probably more in the 8% to 10% because of the reduction of trucking. So that would be kind of that long-term historical norm is probably 8% to 10% differential. Early part of this year, in this first quarter, currently what we've seen is it's looking low single digits kind of like it was in the fourth quarter. But we'll see how that continues to progress through the year.

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

Okay. And then one last one. On the infill spacing test that you're going to do, how are those going to spread through the year in terms of -- it sounds like in Indian Hills, you may be testing upwards of 6 potential Bakken locations per -- in different areas, trying to increase from 3 at, say, North Cottonwood to 4 plus. Has that progressed through the year? Or do those -- are those infill programs going to occur kind of more sporadic? I guess, I'm trying to get a sense as to how you're going to go from the 3 to 4, to 5, 6 -- 5 to 6 in terms of your infill pilots?

Thomas B. Nusz

Yes, so, Ron, we've got them -- we're kind of spread out through the year. We do have a fair number of them designed for really starting right now so that as we go into breakup, we have a lot of wells on pads. But we're not going to start with doing 3 wells per formation of the spacing unit and then build to 6. We've got test in common areas where we're testing multiple concepts. So for example, in North Cottonwood, we have one spacing unit where we're going to drill the equivalent of 11 wells per spacing. We're not going to drill all 11. So it would be equivalent of 5 Three Forks and 6 Bakken wells. And then right next to that, we're going to drill 1 that has equivalent of 8 wells in the spacing unit so the equivalent of 4 Bakken and 4 Three Forks. But with a smaller number of wells, we won't drill out the whole thing. And we've got tests like that in each of the areas, testing variance in those number of wells in the spacing unit that have just really kind of spread throughout the year.

Operator

Your next question is from Noel Parks from Ladenburg Thalmann.

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

A couple of things. I know you said that your HBP acreage count was up to 265,000, and I see you have about $25 million allocated for leasehold this year. What's left to drill in the inventory at this point before you get to being entirely HBP?

Taylor L. Reid

So we've got the acreage that is not yet held by production. Quite a bit of that is on the east side of the basin. We've picked up a lot of acreage the last year in the Cottonwood area, new acreage that has expirations on it. In the existing position, it wasn't -- last year, it wasn't -- didn't have as many expiries that we had to get to, so a lot of that was more back-loaded. So you have quite a bit, that's the east side and the North Cottonwood. And then there's a fair amount also over on the west side in the Missouri area, so that's in Montana. And it's further out to the west. So those are 2 of the big hunks. And then there is also some additional acreage that's far south on the west side down in MonDak in the order of 2,000 to 3,000 acres that we may not get to because results aren't quite as good there. And then on the east side in the very north end in St. Croix, we've got around 10,000 acres that ultimately we may not hold.

Thomas B. Nusz

Those last 2 bits are what bring you down from 335 down to 305 roughly of what's core and what's not.

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

Got you. That's just what I was looking for. And I just wanted to turn to hedging for a moment. Just noticing through the pattern you maintain usually in how far you hedge, I just wonder what your thoughts are going forward since we're continuing in this relative flatness of the curve. Just wondering if you're feeling a little bit like there's not as much urgency out there or you kind of prefer to wait and see directionally where we're headed with oil going forward.

Taylor L. Reid

Yes, we've always kept a pretty balanced plan, probably a little bit more on the aggressive side on the hedging to make sure that we keep cash flows at a certain level, especially as we're outspending cash flow. We're clearly outspending cash flow this year as well while not nearly as much as we did last year. And next year, we'll will likely, with a similar type of program, outspend cash flow by, call it, $150 million to $200 million. So call it $350 million to $400 million this year, $150 million to $200 million next year. And with that, we'll probably try to lock in with hedges and that pricing to make sure we maintain cash flows. But what we've done is we've kind of kept it to a 2-year type program and continue to layer in opportunistically throughout the year, and we'll probably do the same this year.

Operator

Your next question is from Dave Kistler from Simmons & Company.

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

When I look at the E&D spending budget you guys put out about -- I want to say, about $996 million and then I look at net wells and the cost you're putting in per well, there's a gap about $100 million that I assume is associated with a bunch of science work, et cetera. Can you kind of walk us through that deviation and what that captures?

Michael H. Lou

You're working off of '12 or '13, Dave?

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

I'm sorry, I missed your first part of your comment.

Michael H. Lou

You working off of 2012 CapEx or 2013?

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

2013. I was just looking at the -- I guess, in your slides, that you've got the E&P budget set at $996 million, and then you've got your net wells at $103.4 million. And if I'm using the $8.6 million as your well cost, there's about a $100 million...

Michael H. Lou

Yes, the drilling and completion dollars, it's just right under $900 million. So that additional $100 million, basically, is land, geology.

Thomas B. Nusz

Yes, so you've got a little over $40 million in infrastructure, Dave, $25 million in land, other facilities $20 million, and then microseismic and logging on our vertical program is about $10 million on top. And that gets you to $996 million. And then there's another $25 million that's OWS and non-E&P capital, which gets you a little over a $1 billion.

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

Perfect. And then as I think about your kind of marketing side of things, can you guys walk through what the pricing is for accessing pipe and pricing is for accessing rail. Just so that when we look at where LLS and TIR and the like, ANS, we can try to triangulate a little better to maybe where realizations will work out throughout the year?

Thomas B. Nusz

Yes, it's moving around quite a bit but in the fourth quarter. You had -- historically, it was easier to try to triangulate around the Clearbrook price on the pipe side. And the Clearbrook pricing was anywhere from a $2 discount to $5 discount kind of in that range most of the fourth quarter. On the rail side, you were getting quotes just kind of at WTI or a little bit of a premium, too. So there was a decent gap between rail and pipe in the fourth quarter. That's holding somewhat through the first quarter, but we'll see where that goes going forward.

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

Okay. So they're not quoting you a specific kind of cost on the rail. They're just quoting you a differential off of the representative pricing hub.

Thomas B. Nusz

That's generally how we get it.

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

Okay. Okay, I appreciate that. And then one last one, and maybe this is for Taylor. When you talk about completions as you move to pads, having delays as your -- not necessarily delays, but as you complete multiple wells, it takes longer to tie those into sales. Can you talk maybe a little bit about how those are trending right now? Are we looking at completions that are going to be back-end loaded in this quarter or how you kind of thinking about staggering those throughout the -- maybe the next 2 quarters?

Taylor L. Reid

Yes, so what's going to end up happening, Dave, is we're in pretty good shape kind of caught up in completions right now. And as we work into the first quarter and get close to breakup, we're starting to drill quite a few wells on pads. And so you're going to have anywhere from 2 to 4 wells on most of these pads. And so those are going to get -- by the time you get to production from those, they're really going to be back-end loaded, like you said, more in the third and the fourth quarter. So you're going to end up with first and second quarter production being fairly flat to 4Q of last year.

Operator

Your next question is from Ryan Oatman from SunTrust.

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

I know you guys list a little over 700 net primary locations and another 800 potential locations, and I could kind of see the map on Page 10. Can you walk us through kind of the primary locations in years of inventory remaining and kind of per area at different areas, such as Indian Hills and South Cottonwood? Or do you see a variance between all these different areas listed in terms of primary remaining drilling inventory?

Taylor L. Reid

Yes. What I would do -- what I would suggest, Ryan, as opposed to trying to work through all those mathematical gymnastics on the call, we can follow up with you. But there's a table also in the appendix of the presentation that might be a good starting point for that.

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

Okay. Okay, very good. And then as you guys shift to pad development, what potential do you see to decrease cost further, given the great job you guys have already done decreasing those costs?

Taylor L. Reid

So as we go to pad development, like I mentioned, we're -- I'm thinking we'll get about 5% to 10% of savings relative to just drilling a single well. And then on top of that over time, it's just continuing to focus on efficiency, cycle times. We want to continue to drive down time to drill a well, to frac it. We're more focused on technology that will help to bring down cost over time. So our goal this year is really to drive that down to the $8 million range by the end of the year, and we'll continue to work on bringing that down in 2014 and beyond.

Operator

Your next question is from Mo Dahhane from Wunderlich Securities.

Mostafa Dahhane - Wunderlich Securities Inc., Research Division

All my questions have been answered.

Operator

Your next question is from Steve Berman from Canaccord Genuity.

Stephen F. Berman - Canaccord Genuity, Research Division

I just have one question. You said in your prepared remarks, you hope to bring those -- the well costs down to $8 million by the end of the year. If you are able to achieve that, would you -- as you sit here today, would you pocket those savings, i.e. bring your CapEx budget down, or might you keep the same budget but drill more wells?

Thomas B. Nusz

I think it's a little bit early to say at this point. We'll kind of see where we stand as we go through the year and make a call on that based on well results and oil price and all the other things that go into it. But to really make a call on it at this point, I think, is a bit early. I just think it's early.

Stephen F. Berman - Canaccord Genuity, Research Division

And just one more I thought of. Is there any flexibility -- I believe you said 40% to 50% of your wells would be done by OWS. Any flexibility in that number?

Thomas B. Nusz

That's -- we're obviously going to drive that to the higher side and do as many wells as we can. But from we sit today, we think 40% or 50% is a reasonable number.

Operator

Your next question is from Gail Nicholson from KLR Group.

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

Just 2 quick questions. The internal goal to get your well cost down to $8 million, does that include the savings from OWS?

Michael H. Lou

No, it does not. As we said, there's about $500,000 gross per well savings that we realize through OWS and we hadn't included that.

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

Okay. And then just looking at the Justice well, was there any difference in completion technique or methodology between the Justice and the other Montana Three Forks well, the Wilson?

Taylor L. Reid

Really, the completion techniques have advanced over on the west side, so there are some changes mostly in how we pump the job to get all the stages away. And we found ways to do that more effectively. The amount of proppant -- I don't -- in stages, we were trying to pump in the Wilson were pretty similar. We just got more effective stages, I think, into the Justice.

Operator

There are no further questions at this time. Mr. Lou, do you have any closing remarks?

Thomas B. Nusz

Yes, this Tommy. 2012 was a year where Oasis differentiated itself as one of the premier operators in the Williston Basin. And we're proud what the team has done across all fronts not only in what we do, but how we do it. In 2013, we're putting in a strong foundation, with more efficient operations, lower well cost, as we've talked about, and optimized price realizations. We've also continued to rapidly grow the company while maintaining a strong conservative balance sheet. We believe we're focused on the right things and have the right people in place to execute on our plan. As always, thanks for everyone's participation in our call.

Operator

Ladies and gentlemen, this does conclude today's conference call. Thank you for participating. At this time, you may now this disconnect.

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