Chord Energy Corp (CHRD) 2014 Q1 法說會逐字稿

Good morning my name is Mike, and I will be your conference operator today. At this time I would like to welcome everyone to the first quarter 2014 earnings release and operations update for Oasis Petroleum.

All lines have been placed on mute to prevent any background noise. After the speakers' remarks there will be a question-and-answer session. I will now turn the call over to Michael Lou, Oasis' CFO to begin the conference. Thank you Mr. Lou, you may begin your conference.

Thank you, Mike. Good morning, everyone this is Michael Lou.

Today we are reporting our first quarter 2014 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. Taylor will reference our corporate presentation during his remarks. You can find it posted on our website at www.oasispetroleum.com.

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 measures can be found in our earnings release or on our website. I'll turn the call over to Tommy.

Good morning, thanks for joining us today. In the first quarter, our team continued to execute and deliver on expectations, as we produced in the middle of our production range and continue to drive down well costs in spite of harsh weather conditions.

So we're delivering on results that meet our plan while at the same time, we continue to drive higher returns through maximizing recoveries while implementing cost efficiencies. As we manage our business, we look forward two to five years and make decisions today that we believe will help us achieve our long-term objectives.

As we transition to full field development, this is more important today than it ever has been. We take into consideration our assets, our inventory, our people, and capitalization to determine a thoughtful, long-range plan. This permeates throughout the organization as we plan our drill schedule, develop infrastructure, and allocate capital.

We have an organizational culture of continuous improvement in all facets of our business, and we believe this drives our corporate and operational excellence that will be rewarded in long-term value growth. Today we are going to highlight some of the work we're doing to accomplish this, and will provide you with some examples of the direction we're going as we transition to full field development. But first, I will highlight some of our first quarter activities.

First, we continue to grow production in the quarter with a 5% increase over the fourth quarter excluding our recently divested Sanish assets. For the second quarter, we anticipate production to grow to 43,000 to 46,000 BOEs per day, which at the midpoint is about an 8% growth quarter over quarter, adjusting for Sanish. As we have discussed in the past, we expect our growth to accelerate going into the second half of the year with increased activity.

Second, we're continually trying new drilling and completion techniques to improve well recoveries and economics. Generating per-well recoveries within our stated type curve bands across, effectively, our entire acreage position. In fact, although our base designs by area are achieving strong economics across our inventory of projects, we will complete approximately 60% of our wells in the second half of this year, with something different than our base design to maximize economics.

One great example that Taylor's is going to cover is in Slickwater completions, where we have seen material uplift of production through much of our West Williston position. We will complete about 40% of our wells with Slickwater completions in areas we've seen it work, which equates to 16 wells in Indian Hills and Eastern Red Bank in the second half of the year. In addition we're completing another 7 wells with Slickwater in new areas where we believe that it should be applicable. We're also testing multiple other concepts which we believe may increase production or reduce costs.

Third, we are continuing to optimize well costs and improve capital efficiency. In the first quarter, our average well cost was just $7.2 million per well, including the savings we realized with OWS. With approximately 80% of our wells on pads of two or more wells, we were able to maintain our drilling and completion efficiencies during a tough winter operating condition.

As we look to the rest of the year, we will allocate approximately 55% of our drilling and completion capital to the deeper areas of the basin where we are moving towards full DSU development. The remaining 45% of our capital will be spent on continuing to test alternative completion techniques, down spacing initiatives, and holding recently acquired acreage.

While we continue to improve capital efficiency through lower well cost on our base designed, and our shift to multi-well pads, we are sticking with our original $1.4 billion capital budget, as more capital is been allocated to drilling in deeper parts of the basin and the increased Slickwater activity.

So we're off to a great start to the year as the team continues to execute and find ways to deliver value. With that I'll turn the call over to Taylor to provide more detail on our operations.

Thanks, Tommy.

First, I want to highlight the efforts of our operations team here in Houston, and especially in Williston. In the face of an extremely harsh winter, their efforts allowed us to grow our volumes by 5%, excluding Sanish, quarter over quarter. They did an exceptional job.

As Tommy discussed we have allocated capital according to our understanding of our area performance. At the well level we have done a lot of work varying completion techniques to custom fit the completion style to our project areas.

Before I get into too much detail, I'd first like to point you to page 9 and 10 in our investor presentation, that show some of the encouraging results from our new completions. As you can see, we are testing a number of different things including fluid types, proppant concentration and mix, and also the way in which we mechanically deliver our fracs. In general we test concepts first, and once we know and understand the results, we will move forward with the technology and discuss them externally.

The biggest move we have made recently is with Slickwater completions in the core of our West Williston position. On the wells we have completed in Indian Hills, we have seen an uplift of about 25% through 90 days of production. Which is very impressive considering our average Indian Hills well already produces above our 750 MBoe type curve. In Red Bank, we have seen increases greater than 30% through 12 months.

Based on the results in these areas, we think that Slickwater currently has application on over 100,000 acres of our land. And we will be testing it in new areas as well, including South Cottonwood in Montana in the second half of the year.

To test the impact of Slickwater on spacing, we will also conduct Slickwater fracs on seven wells in the white unit, in Indian Hills. The unit will be a partial DSU spacing test and will have wells in the Bakken, in the first through third benches of the Three Forks. So in total for 2014, we will complete 32 Slickwater jobs across our entire position.

With respect to other completion methods, about 40% of our wells will be completed, optimizing proppant quantity, concentrations, and method of delivery. In areas of the basin with the thickest section and highest charge, we will test much higher proppant volumes in an effort to improve recoveries an increase production.

In some other areas like North Cottonwood, we found it beneficial to reduce proppant volumes to keep the energy of the fracking zone, increased EURs and reduce well cost. Finally, we are working on some completion designs around the delivery of proppant through coil tubing fracs and cemented liners. We anticipate sharing results on these various completions for you throughout the year.

Oasis well inventory has a broad range of characteristics including different depths, well designs, and cost. This enables us to drive very compelling economics across our portfolio. One area we would like to highlight is in Montana.

On page 12 of our corporate presentation, you can see that the actual well results for Montana are falling right on top of our 450 MBoe type curve. That, combined with our recent well cost in the area of $6 million, including OWS cost savings, leads to strong economics. We have approximately 90,000 net acres in on Montana that deliver robust economics in the area. Our tailored approach to completion designs by project area has resulted in strong economics from the deepest part of the basin to the edges, and we're very proud of that.

An additional area of success has been the evolution of our Three Forks program in the deeper benches. I'd like to refer you to page 13 of the investor presentation. Since the last call, we have brought online four new Lower Three Forks wells bringing the total number of producers to nine. Results have been encouraging from these wells, as they continue to expand our comfort of the lower benches throughout the position.

You can see the results for wells with over 30 days of production on this slide. Including the Paul S, Patsy, Omlid, Mangum, and Bonita. As you can see all the wells are producing within or above our type curve range except for the Bonita which is on the far Eastern side of our East Nesson position.

There are four additional wells with less than 30 days of production that have not been included in the graph due to early time data. The Hysted and Lefty wells are second bench wells in the Indian Hills, both of which have performed like other lower bench wells in the area in early time. The Osage well, a second best test in South Cottonwood, produced 780 barrels equivalent per day in its first seven days, which would place in the middle of our type curve band.

The last well we'll highlight, the Ava, in the third bench in South Cottonwood, produced 530 barrels equivalent per day through seven days also within our type curve band. These tests are important confirmations as we transition to full field development. With this improved understanding of the Three Forks and our knowledge of infill spacing, we are moving to full DSU development on about 20% of our acreage, as represented on the map on page 8 of our presentation.

By going to full DSU development in these areas, we gain several advantages. First, our improvements in cost and efficiency. As all wells will be drilled on pads which will continue to drive down our well costs. In addition, we will use multiple rigs on each DSU, thereby reducing cycle times and bringing forward production.

As you can see, the team has been focused on the key objectives, and we believe the key objectives that we believe drive shareholder value over the long-term. We have had a lot of success with our strategy, and believe our ability to execute, engineer and drive technological advancement will deliver strong results into the years ahead.

With that, I'll hand the call over to Michael.

Thanks, Taylor.

We had another great quarter to start the year. We took over operations of the assets we acquired late last year on January 1. We continue to be encouraged by the strong results we see in the area, as well as the benefits of application of Slickwater completions across the acquired assets in West Williston.

With most of the acreage effectively held by production, we have only limited drilling on the newly acquired acreage in 2014, as we establish the infrastructure. When the infrastructure is in place, and our knowledge of spacing and completion style is established, we will run multiple rigs on the acreage to develop the entire position in one pass through corridor development. We expect to start this increased activity sometime in 2015.

The team did a great job of keeping production up this quarter despite harsh winter conditions. You have heard that the winter weather persisted at extremely cold temperatures through a large part of the quarter, severely hampering operations.

In fact, on our operated position, we completed only 40 gross operated wells compared to 45 wells expected. From a non-operated perspective, activity was off about 1.5 net wells on the quarter. Despite that, our team did a great job continuing to bring wells back online through increased workover activity, which is up 40% quarter over quarter. Keep in mind is that we book workover activity and frac protect to LOE, which caused a bit of an uplift there.

Similar to the fourth-quarter, LOE was higher than previous levels due to some temporary conditions. First the acquired assets increased our LOE by approximately $2.00 per BOE which you saw the impact of, in the fourth quarter. We should be able to reduce the fixed component over the course of the year and the variable piece over the next 18 to 24 months with saltwater disposal infrastructure.

Additionally we had just over a $1.00 per BOE impact to LOE in the first quarter from increased workovers and frac protect work. We're encouraged that we'll be able to bring LOE down to the $8.00 to $8.50 per BOE range by the end of the year. And infrastructure additions should lower the even more into next year. With that, we expect to come in around the high-end of our LOE guidance range for the year.

Differentials decreased from 12% in the fourth quarter to 9% this quarter which is consistent with the 8% to 10% long-term view of differentials. Strong differentials in production drove a record $240 million of EBITDA for the first quarter. With capital expenditures of $308 million in the first quarter, we had only a $68 million outspend, moving closer to cash flow breakeven.

Coupled with our tax efficient sale of our Sanish properties for $322 million, and the repayment of our revolver, our balance sheet is in good shape with net debt to annualized first-quarter EBITDA at approximately 2.3 times and our liquidity remains strong with $1.5 billion available. This includes our $1.5 billion revolver, which was recently re-determined to a $1.75 billion borrowing base, although we decided to leave commitments at the $1.5 billion level.

Finally, OWS has been a very successful business for us. It has returned more than two times the cash we have invested in OWS since its inception. Throughout 2013, and into the first quarter of 2014, OWS saved the Company about $400,000 per net well. The second spread should be at full capacity this summer and we're excited about the additional scale it will provide.

With that I'll turn the call over to Mike to open the lines up for questions.

(Operator Instructions)

We will pause for a few moments to compile the Q&A roster. Scott Hanold, RBC Capital Markets.

Thanks, guys, good quarter. It sounds like you guys are getting a little bit more, I guess, assertive in terms of looking at different types of completion techniques. And it certainly looks like the Slickwater fracks where you've got, what, over 60 wells now, I think it looks like being drilled has shown much better results. And could you again tell us how much of that of your 500 thousand acres it might be applicable for?

Scott, this is Taylor. So for right now for the areas that we have data and have seen successful tests with the Slickwater it's about 100 thousand acres, a little over 100 thousand acres, so roughly 20% of the position.

We have plans in the remainder of this year to test it on the east side of the basin in South Cottonwood. We'll also have planned tests in our Painted Woods area, and also in Montana. So we hope to expand is significantly as we test it over a broader area.

Okay, I guess maybe more pointed to that question is that, is there anything that's unique about where you tested compared to where you are going to be going, that would tell you it may or may not work? Or is the reality you're just need to get comfortable with running a pilot at this point?

We don't think it's going to work in all areas, but we think it has the potential to work in quite a few of the areas. The first places that we saw it work were in the areas that had a thicker section with full charge, but, that being said, we've seen it work in areas where the section is thinned and you don't have quite as much charge. And that would specifically be in Foreman Butte and in the northern part of our East Red Bank area.

So based on that we're pretty optimistic we'll be able to push out further. We don't think we'll see, we'll try on the east side to the north but we don't think the very northern parts of Cottonwood are going to be an application, but we will see as we push it out.

Okay. So those are the areas where you're trying different things like those coil tubing fracks, where Slickwater may not work, is that sort of the plan?

Correct. In areas like at North Cottonwood where we've had issues with bringing in water as we've done larger fracks. We think doing a coil tubing frack, where we can do more stages, albeit smaller, individual stages, will help us to keep that frack intensity in zone and make a better well and cut down on the water.

Okay, understood. Thanks.

Thanks, Scott.

Ryan Oatman, SunTrust.

Hi, good morning. I thought the operations up date was encouraging, and appreciate the detail that you guys provided in the presentation.

Quick question for me, obviously with the base program we've seen the well cost dropped significantly. We've also seen slick water completions outperforming over 25% in early days. Can you just describe the differences in cost between wells completed with Slickwater versus gel? And should we see these as kind of mutually exclusive in terms of the well cost savings and the productivity uplifts that we're seen in topline?

Yes. So the cost difference in a Slickwater job versus our base design is on the order of $1.5 million to $2 million more to do a Slickwater. When you look at our wells to date and our costs to date, so 7.6 gross (sic - see presentation $7.6 million) and 7.2 net (sic - see presentation $7.2 million) that includes a few Slickwaters, but not as great a percentage as you're going to see for the remainder of the year.

So, but keep in mind still going to be, in total, 20% of our completions going forward. So, while that might place a little upward pressure on cost, we think we can offset that and at least keep our cost per well on average where they were for the first quarter for the remainder of the year.

Okay, that's helpful. And then looking at the recently acquired acreage, I guess in 3Q of last year, can you describe kind of the process that's, progress I should say, that has been made on infrastructure additions and kind of what you need to see there before getting more aggressive?

Yes. So, on the infrastructure there, Ryan, it's a process. We've kind of talked right after the acquisition that we had to take some time to put in oil gathering, gas gathering, as well as saltwater disposal.

We're in that process right now, we're working with third parties also looking at a internally, we need to figure out what we're going to do exactly there. It's probably 12 to 24 months out, and it's going to be kind of the scaled build across that infrastructure, across those areas.

As we said, what we're looking at putting some of the infrastructure in, starting a more kind of development type drilling sometime next year. It's probably going to be the second half of next year.

Great, I'll hop back in the queue, thanks.

Dave Kistler, Simmons & Company.

Morning, guys. Real quickly, and I apologize if I missed this, when you guys talk about the recovery increases associated with Slickwater, was that factored in to your original production growth guidance this year?

So, the original guidance for this year really was based on our base EUR's without slick water. So, there could be some upward movement, but keep in mind the bulk of these jobs are going to be done second half and like a lot of our production is kind of backend loaded. So, you may see more of an impact in 2014, but certainly could see, I mean 2015, but certainly can see some at the end of 2014.

And just thinking about that, if it's really factoring into, call it the first part of 2015, could that reduce some of the production variability that we're seen into the winter? Or can winter still impact the general flow of those?

Dave, the combination of winter, depending on what type of winter we have if it's real harsh, it's probably going to still have some impact. That, combined with, as we go to these full DSU drill outs, more and more this work is pad work, and so it just, by nature, tends to be kind of lumpy.

Okay. Appreciate that.

And then, just thinking about those full DSU development, I think in your slide 9 you talk about four to five wells per formation, through the Three Forks three. How much of your acreage, will we start thinking about that as a legitimate possibility? Admittedly, I think you been pretty conservative on the spacing and certainly had a nice uptick at year-end, but how do I think about this, going forward?

So, you're talking about the ones, the Slickwater DSU drill out?

Exactly.

So, what we're trying to figure out is, is what is the drainage areas like for these Slickwater jobs. So we're going to pump Slickwater's in seven wells within that partial DSU. Then, based on that, we'll make an adjustment.

What could happen is, you could have a little bit bigger drainage area but we just don't fully understand that yet. That's why we want to do this full DSU. And based on what we see, we'll translate through the inventory but no changes to the inventory right now.

Okay, appreciate that, guys I'll let somebody else jump on. Thanks for the color.

Thanks, Dave.

Drew Venker, Morgan Stanley.

Morning Guys. With the Slickwater, are you seeing more out performance early on in the well's life, and then reversion to offsetting well's performance over time? I guess it's a somewhat difficult to see from your cumulative production plot, whether that's the case or not?

In general, what we're seeing across the areas that we've looked at is out performance, through the life. But keep in mind the amount of data on these Slickwater jobs is pretty short at this point.

I think the longest dated stuff we have is maybe on some Liberty jobs around a year and a half or so. So we continue to see out performance. It's not consistent on every well, but on average you maintain that.

Are there other ways you can reduce the cost of your Slickwater completions?

As we do more of these we'll find ways to bring the cost down. The biggest cost increase is really water handling, because you go from our base design that is 60 thousand to 70 thousand barrels of fluid, to a frack that is on the order of 250 thousand barrels.

So accessing low-cost water, and transporting it cheaply and then disposing of it cheaply, are all very important. Those are some of things we're working on to bring that down.

Can you speak to the incremental costs associated with some of the other alternative completions will be testing?

I don't have data at my fingertips on all those right now, but maybe we can work on that and get back to you.

Thanks.

David Tameron, Wells Fargo.

Morning. Can you guys talk about, in your Three Forks area, you have a slide in there, that talks about the production of the type curves. But are you seeing a difference between, call it the second bench and the third bench? And if so what would be the difference?

At this point, we just don't have enough data to say, in general, what that difference is or if there is a difference. We've got some third bench wells that are better than second, and vice versa. So we're kind of treating lower benches the same at this point, as we get more data and a better understanding we'll let you all know.

Okay. Alright, and you talked about the infrastructure of the acquisition. Can you just talk about bigger picture? Have you fully integrated that acquisition now, or is their other things to do? Where you are at in that process?

I wouldn't tell you that we fully integrated. I mean our guys are good, but we just took over it January 1. So there's a lot of things we need to do just on the base plumbing side.

And then infrastructure is going to follow, so that's I think Michael mentioned that it's probably 12 to 18 months and trying to get infrastructure in place in advance of high density drilling. Because you sure don't want to go out and do a lot of high density drilling and be trucking oil and water.

Yes, that make sense.

Or, not be able to capture your gas.

All right and just a couple more.

As I think about the, if I look at the backlog grew a little bit. I know there was some weather impacts, your completion schedule for the rest of the year, are you still, it sounds like you can still hit that 205 gross target. Do you need to do anything on the frack side to get rid of that backlog or how are you thinking about that?

Keep in mind, we have got the other frack crew starting up, Taylor, here in the next couple of months. And plus the weather, that will help.

That combined with the number of wells that are on pads. We intentionally had a large percentage on wells on pads going through breakup, which will go now through typically late May, early June. Then we'll have a period where we are able to work down that backlog as we get off of those pad wells and get our frack crews in there.

We don't have a constraint on frack crews at this point. Like Tommy said, we'll be adding our second crew, but we have the ability to flex with our third parties and we currently use both Nabors and Schlumberger as our third-party providers.

So we'll work down the backlog that we have right now, but you're going to see that build up again at the end of the year because we're going to have a bunch of wells on pads again.

Okay and there's one more for me, and I'll let somebody else jump in. Sand, you hear all kinds of rumors about sand backlog et cetera. Can you guys just talk about what you're seeing out in the field? And then just in general are you seeing any upward pressure on,

I know you guys have talked about fighting well cost and the new completion techniques and you can alleviate those through efficiencies. But are you seeing upward pressure on service costs? And then sand specifically, what's the current snapshot there?

So on the sand side, there was a period during the winter where getting it to some of the wells was challenged but it was really around rail. And because of the cold winter, not just up in the basin, but the whole country, you saw some periods where you got just a massive backlog of freight and some of the areas like Chicago that handle and do all the switches for cars coming in and out. And because of all that backlog there, and then also in the basin, there was a period for about a month where there were some disruptions.

And so, what happened is, on some of our wells, not a lot but on a few, we had some extra waiting time, but that has now resolved itself. As the weather has gotten much better all the deliveries of our sand have been on time. So we don't see that as big problem going forward. And on the wells where we did, we just had a little extra waiting, so a little extra cost in terms of waiting times.

Okay. But if we look out six months or even a year, some of the sand providers are giving some bullish commentary, and I realize they are talking their books little bit. But I mean you guys don't see that market tightening but you don't foresee issues? Is that the way to read that?

Yes. There's a lot of sand providers, a lot of available mines at this point. We don't see a tightness in supply from the mines, it's been more logistics at this point. So as we project forward, we're not concerned about our sand costs.

I guess the other question you asked was on general services. And for the Williston, I know some basins are talking about getting tighter for the Williston, supply is in decent shape for frack crews and rigs. At least as we see it now for the next six months to a year.

Okay I appreciate all of answers.

Subash Chandra, Jefferies.

Yes. On the Slickwater to revisit that. Is there a higher ceramic concentration in these wells?

So on our Slickwater jobs, we're actually pumping at all ceramic. Just doing that because the concentration, we pump about the same amount of Proppant, but it's pumped over four times the amount of fluid. So the induced fracks are we think more numerous, but also not as thick as a conventional gelled cross-link job.

So at this point we think ceramic make sense because of the closer pressure on that thinner frack.

Okay. What you're targeting is a more complex fracture network, and keeping that open with the ceramic. I guess $1.5 million to $2 million how much of that is water versus Proppant?

I don't have it off the top of my head, but there is some, absolutely some additional ceramic cost as well.

Okay and I guess if we look forward and it seems like this might, over time, be adopted as a best practice by industry in the basin over the large areas where it does work. How do you sort of foresee the availability and disposal and or recycling of frack and load water? I imagine there would be quite a bit more demand for water as a result?

The availability of the water, clearly takes a lot of advance planning to make sure you've got enough within the areas where you're going to frack. We think that certainly for the program we're talking about this year, that we will be able to supply all those needs. Again the key is to plan pretty well in advance so you can find cheap water sources and plenty of it.

On the disposal side, we think we're in good shape there as well. We've got our own disposal system and infrastructure and we think we'll be able to service all those volumes.

And back to your question on ceramic versus water on the Slickwater job, it looks like it's, the increased cost was roughly 50/ 50 ceramic and water. And the water piece of the equation is the biggest one we can impact right now. But we'll work on both.

Right, got it.

And one final one for me just back to the water. Recycling water is sort of, how credible of goal is that? And is there a desire to do so, or is there a condition of flow back water where it just doesn't really work well recycled how it might react with other agents in the frack job?

We've actually, Subash, done some jobs with produced water. And both will Slickwater component and cross-link, and have done those successfully. So that is one of the things we continue to look at is if we used produced water for our fracks can we bring down the cost that way.

Obviously with 250 thousand barrel fracks using all produced water there's a handling component that you want to be very careful about with respect to spills. You just don't want to get in that situation, but we're looking at it.

Okay, thanks.

James Sullivan, Alembic Global advisors.

Good morning, folks.

Morning.

Just wanted to check out, in your documentation you guys mentioned that you been applying new techniques Slickwater and others to the Middle Bakken so far. Is there any thought you guys would go through to the Three Forks with that? And do have any expectations given the geology about whether the uplift would be similar?

We do have some Three Forks test plans, one a particular that we talked about is the white unit and that is on page 9 of the presentation. So you can see in that one, we're going to actually do Slickwater fracks in all three benches, so the first, second, and the third.

We're looking at some additional tests that will also be in the Three Forks. No reason why, that we see, why you shouldn't get a similar uplift by doing that stimulation in the Three Forks versus the Bakken.

Okay, sounds good.

You guys did mention that you guys have done this in Indian Hills, you know in the kind of pressurized part of the basin, but also that you've had success and Red Bank and Foreman Butte. Could you just quantify, if you're willing, whether the uplift was the same? I would assume not, in Red Bank and Foreman Butte as it was in the charged part of the basin?

Sure. The uplift, like we talked about specifically for Indian Hill's, was around 25%. When you look out Foreman Butte and East Red Bank is actually over 30%. So of the wells down in those areas we've actually seen a little better increase.

Oh Really? Okay. Interesting.

And the last thing I just want to get at in terms of these technology. You did talk about in the presentation cemented liners, but you haven't, or you have listed on there, but you haven't mentioned that much.

How much of that have you been doing the coil tubing and cemented liner work? And as a part of the cemented liner completions are you guys experimenting with the kind of more dense aperture systems I guess, per stage?

Other operators have talked about trying to increase the near bore, the near well bore fracture systems and have had some success with that. Are you guys experimenting with that too?

First on cemented liners, we've done a number of cemented liners test in the past probably on the order of five to eight wells. For the total year we have at this point, 11 planned.

With respect to the completion style we're going to do in those, it just varies and we've got some of the cemented liners we're doing, we've done coil tubing with them and we varied Proppant costs and we have done some other things in pumping the job. So we're trying to different things, we're just not ready to come out talk about that stuff yet.

Okay, sounds great. All right, I'll hop back in the queue. Thanks guys.

David Heikkinen, Heikkinen Energy Advisors.

Good morning. You talked about weather. But can you comment on where 2Q break up is now? And your expected operated, and non operated completions in the quarter?

So, 2Q has, you know the weather has warmed up pretty substantially in the basin. We actually had a pretty well behaved breakup going. It had gotten quite warm, and not a lot of moisture in the past. The past week had gotten some pretty significant rains, where there was some road shutdowns for a couple of days and actually most of the counties implemented that as a breakup measure.

And so, hopefully, it looks like, at least for the near-term don't see a bunch of additional rain. So if we continue through breakup, with any luck by the end of the month we'll be out and have less restriction.

With respect to our completion count, we're expecting to do 47 wells for the quarter. And as we talked about we did 40 in Q1, so a bit of a bump up.

Okay and then your productivity, you talked about 25% at Indian Hills and 30%. Is that first 90 days directly correlative of to EUR uplift?

That's the part that we don't know yet and we're working on it. Is it truly all unique reserves, is some of this acceleration? And so when you just look at it from early volumes, it's encouraging, but we've got to continue to work the data. And that's one of the reasons we're doing this full, or not a full, partial DSU drill out in the white unit across the Bakken and the benches to test some of that.

All right, cool. Thanks, guys.

Thanks, David.

Rhys Williams, Johnson Rice.

Good morning, guys. On the first full DSU that you talk about on slide 14, can you give us I guess, some expectation on timing of that? Or when you might talk about it?

So, that's actually, you said on page --.

You're talking about page 9?

Page 9?

It was under page 14, under pad development.

Sorry about that.

No problem.

Yes, the full 15 to 20?

Yes.

So that actually will be spud in fourth-quarter so, or spud now actually. And should come on production in the fourth quarter.

Okay, great.

And in terms of your pricing this quarter, obviously a stronger differential then we were projecting and better than some of your other Bakken peers. Probably driven by your marketing team. Do you think this can continue? And kind of, what's the plan going forward?

We've always kind of said that are marketing team has done a fantastic job in part it is the flexibility that we have in our infrastructure system. So, if you look at our oil gathering side, as well as our gas contracts we're primarily connected across most of our acreage position, especially across our legacy positions. So we kind of talked about the acquired assets, and to take a little bit of time to add it there. But, because of that flexibility and because we're so connected on infrastructure side, we do see a pretty strong differentials.

We do believe that, that kind of 8% to 10%, is probably a good number on average. It does bounce around a little bit, we're able to move back and forth between rail and pipe, whichever gives us the best price on the oil side. So that flexibility has really helped us out over the last few quarters the last few years.

Great, that's it for me. Thank you.

Thanks.

Andrew Coleman, Raymond James.

Thanks a lot for taking my question's this morning.

The first on I had was just thinking back to the question on the coil tubing potential for the completions. Would you have a sense or at this point it is probably pretty early about how much that might reduce cycle times?

At this point what we think we can get to, is that cost and cycle times would be kind of neutral, to one of our regular fracks. So the real benefit is if we can get uplift in terms of production.

Where you could save some additional time is on clean out. You potentially don't have to do clean outs on these coil fracks. So that could be additional cost and time saving.

Would you be able to potentially circulate, I guess clean out the hole and kind of get some flow back, I guess between stages? Or would you still at this point, think about just pumping the whole job before you go in there and try to let the wall come back?

At this point we're just trying to go in there and pump the full job and get out and flow the well back.

Okay. All right.

And I guess last question on that then is, do you think, would there be a need, there probably is not one right now, but as you look at the future to maybe buying a coil tubing run if you look at adding more to OWS after the second group comes on?

At this point, early days, it's really at the work over broader areas. So we're not really looking at that right now.

Okay. Thank you for your time this morning.

Thanks, Andrew.

(Operator Instructions)

Noel Parks, Ladenburg Thalmann.

Good morning.

I also, like many people, got on a bit late and I just wanted to ask about the overall inventory. You guys are great about giving a lot of really granular details about how you look at the inventory.

Just thinking about drilling to date, if you have any thoughts about the distribution of well densities across your acreage? I think the assumptions you have in the presentation, I'm looking at slide 25 which of think is unchanged from the last version, you had started the ten well per unit assumption.

Is that distribution of density increasing any, do you think? Do you think you might be able to get even more aggressive by the end of the year?

Well keep in mind, Noel, what we said consistently is that, we kind of want to approach this from one direction. So that with additional data for instance like in the Three Forks, and I forget what slide it is, where we're kind of expanding in the area where we see the second and third bench could have some influence.

One of the things as Taylor talked about is, what's the trade-off potentially between Slickwater and well density. And we will see some of that in this white unit, and some of the interference testing there.

So we had an 80% uplift in inventory at the end of last year. I wouldn't sit here and expect to see a big jump going into the end of year. It will just be a function of when we get the right data. Keep in mind for instance in those Slickwaters, where that activity is really a bit more backend loaded. So you think about all that happening in the second half of the year, I wouldn't expect a big change but we will just see.

Thanks.

And, just also as you continue to drill, you amass a greater and greater amount of data. Where are you on the learning curve do you think of really being able to anticipate, not just well performance from area to area but also your ability to sort of predict your returns?

I guess I'm thinking about heading forward into a data future year where you can map out a drilling pack that is based just on what you want the pattern returns to be, as opposed to, at a given commodity price, as opposed to, I guess, [nicer] pretty much a systematic sort of march across the acreage?

Yes, as Taylor touched on, the economics are pretty robust across the entire position, as you get in lower areas of recovery have lower well costs. I think going forward that how you allocate capital, and the timing of drilling wells or full DSU's maybe more driven by takeaway infrastructure whether it's oil, water, or gas.

That's why, when we say, you look at some of the acquired acreage from last year where it's infrastructure poor. You don't want to out run that. And so I think you've got to be careful of building a seriatim of wells and ranking by rate of return, and basing your drilling program on that. Because I don't think your adequately incorporating all of the business risks that can drive those returns down. I mean I go out and drill a bunch of wells and then don't turn them on for 12 months I can dramatically influence IRR's.

Right.

You got to have all of the data and look at it in total, and how you feel is the best way to manage the business. And adjust, we're adjusting all the time.

Thanks a lot. That's helpful.

You bet.

That's all for me.

Great, thanks.

Irene Haas, Wunderlich.

Hello, everybody congratulations on a really strong quarter considering how rough the weather is. The question is, how is second quarter looking? Any ice packed forecast and things of that nature?

So, actually we had a pretty nice warm-up through April, and pretty well behaved break up as far as breakups go. And so the frost is effectively out of the ground.

The other thing that is happening has been fairly dry. Some springs you really get a lot of rain, and we just had one impactful incident so far which we had two or three days snow and rain last week which resulted in some road bans from the counties.

But right now the forecast looks pretty decent, so we're hoping for a break up and road restrictions to come off by end of the month. And really it hadn't hampered us a whole lot at this point. So we're pretty encouraged.

This is great, thank you.

Thanks, Irene.

I will now turn the call back over to Oasis Petroleum for closing remarks.

Thanks, Mike.

So we're off to a great start and on track to achieve our annual targets. I can't say enough about the job our team is doing, and how they are focusing on the right things to generate robust economics across the entirety of our significant acreage position which should be evident in the material we covered today. Thank you again for joining us on the call.

This concludes today's conference call, you may now disconnect.