Oasis Petroleum Inc.
Q1 2014 Earnings Call Transcript

Published: 6 May 2014

[Operator:]

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. [Operator Instructions] I will now turn the call over to Michael Lou, Oasis' CFO, to begin the conference. Thank you. Mr. Lou, you may begin your conference.

[Michael H. Lou:]

Thank you, 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 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 risk and uncertainties that could cause actual results to be materially different from those currently disclosed in our earnings release and conference call. Those risks include, among others, matters that we 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.

[Thomas B. Nusz:]

Good morning, and 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 cost in spite of harsh weather conditions. So we're delivering our results to meet our plan while, at the same time, we continue to drive higher returns through maximizing recoveries, while implementing cost efficiencies. As we managed our business, we look forward 2 to 5 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're 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'll 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 8% growth quarter-over-quarter, adjusting for Sanish. As we've 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 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 cost. Third, we're continuing to optimize well cost 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 2 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're moving towards full DSU development. The remaining 45% of our capital will be spent on continuing to test alternative completion techniques, downspacing initiatives and holding recently acquired acreage. While we continue to improve capital efficiency through lower well cost on our base design and our shift to multi-well pads, we're sticking with our original $1.4 billion capital budget, as more capital is being 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.

[Taylor L. Reid:]

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 shows some of the encouraging results from our new completions. As you can see, we're 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 Foreman Butte, 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 at new areas, as well, including South Cottonwood and Montana in the second half of the year. To test the impact of slickwater on spacing, we will also conduct slickwater fracs on 7 wells in the White Unit in Indian Hills. The unit will be a partial DSU spacing test, and we'll 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 and increase production. In some other areas like North Cottonwood, we found it beneficial to reduce proppant volumes to keep the energy of the frac in zone, increased EURs and reduce well cost. Finally, we're working on some completion designs around the delivery of profit to coil tubing fracs and cemented liners. We anticipate sharing results in 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 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 4 newer -- 4 new, lower Three Forks wells, bringing the total number of producers to 9. Results have been encouraging from these wells as they continue to expand our comfort to the lower benches throughout our 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 4 additional wells with less than 30 days 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, the second bench test in South Cottonwood, produced 780 barrels equivalent per day in its first 7 days, which would place it 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 7 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 cost. 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.

[Michael H. Lou:]

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 the 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 1 pass through a quarter of 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 work-over activity, which is up 40% quarter-over-quarter. Keep in mind that we booked work-over activity and frac protect to our 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 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 per BOE impact to LOE in the first quarter from increased workovers and frac protect work. We are encouraged that we'll be able to bring LOE down to the $8 to $8.50 per BOE range by the end of the year and infrastructure additions should lower that 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 2.3x and our liquidity remains strong with $1.5 billion available. This includes our $1.5 billion revolver, which was recently redetermined 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 2x the cash we have invested in OWS since 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 are 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:]

[Operator Instructions] Your first question is from Scott Hanold with RBC Capital Markets.

[Scott Hanold:]

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 fracs where you've got, what, over 60 wells now, I think it looks like being drilled is showing much better results than -- and could you again tell us how much of that, of your 500,000 acres it might be applicable for?

[Taylor L. Reid:]

Scott, this is Taylor. So for -- right now, for the areas that we have data and have seen successful test with the slickwater, it's about 100,000 acres, a little over 100,000 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 -- we also have a planned test in our Painted Woods area and also in Montana, so we hope to expand this significantly as we test it over a broader area.

[Scott Hanold:]

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

[Taylor L. Reid:]

There's -- we don't think it's going to work in all areas, but we think it has 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're going to be able to push it 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'll see as we push it out.

[Scott Hanold:]

Okay. And so those are the areas where you're trying different things like those coil tubing fracs that -- where slickwater may not work. Is that sort of the plan?

[Taylor L. Reid:]

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

[Operator:]

Your next question is from Ryan Oatman with SunTrust.

[Ryan Oatman:]

I thought the operations update was encouraging, and appreciate the detail that you guys provided in the presentation. A quick question for me, obviously, with the base program, we've seen the well cost drop significantly. We've also seen slickwater 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 seeing in top line?

[Taylor L. Reid:]

Yes. So the cost difference in the slickwater job versus our base design is on the order of $1.5 million to $2 million, more to do with slickwater. When you look at our wells to date and our cost to date, so $7.6 million gross and $7.2 million net, that includes a few slickwaters but not a great a percentage as you're going to see for the remainder of the year. So -- but keep in mind it's 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 keep -- at least keep our cost per well on average where they were for the first quarter for the remainder of the year.

[Ryan Oatman:]

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's been made on infrastructure additions and kind of what you need to see there before getting more aggressive?

[Michael H. Lou:]

Yes. So on the infrastructure there, Ryan, it's a process. We've kind talk to, right after the acquisition, that we have 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 it internally, and 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 a scaled build across that infrastructure, across those areas. As we said, we're looking out, putting some of that infrastructure and starting more kind of development type drilling sometime next year. It's probably going to be the second half of next year.

[Operator:]

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

[David W. Kistler:]

Real quickly, and I apologize if I missed this, when you guys talk about the recovery increases associated with slickwater, was that factored into your original production growth guidance of this year?

[Taylor L. Reid:]

So the original guidance for this year really was based on our base EURs without slickwater. 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 back-end loaded. So you may see more of an impact in 2014 but certainly could see -- I mean, 2015, but certainly could see some at the end of '14.

[David W. Kistler:]

And just thinking about that, if it's really factoring into, call it, first part of '15, could that reduce some of the production variability that we're seeing into the winter, or can winter still impact just the general flow of those?

[Taylor L. Reid:]

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 drillouts, more and more of this work is pad work and so it just, by nature, tends to be kind of lumpy.

[David W. Kistler:]

Okay, appreciate that. And then just thinking about those full DSU developments. I think in your Slide 9, you talked about 4 to 5 wells per formation through the Three Forks' 3. How much of your acreage should we start thinking about that as a legitimate possibility? Admittedly, you guys, I think, have been pretty conservative on the spacing and certainly had a nice uptick at year-end. But how do I think about this going forward?

[Taylor L. Reid:]

So you're talking about the one -- the slickwater DSU drillout?

[David W. Kistler:]

Exactly.

[Taylor L. Reid:]

Yes. So this -- what we're trying to figure out is what is the drainage area like for these slickwater jobs. And so we're going to pump slickwaters in 7 wells within that partial DSU. And then based on that, we'll make an adjustment. I mean, what could happen is you could have a little bit bigger drainage area, but we just -- we 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.

[Operator:]

The next question is from Drew Venker with Morgan Stanley.

[Andrew Venker:]

With this slickwater, are you seeing more outperformance early on the wells life and then reversion to offsetting wells performance over time? I guess it's somewhat difficult to see from your cumulative production plot whether that's the case or not.

[Taylor L. Reid:]

In general, what we're seeing across the areas that we've looked at is outperformance 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 deliveries and deliveries jobs around 1.5 years or so. And so we continue to see outperformance. It's not consistent on every well but, on average, you maintain that.

[Andrew Venker:]

And are there ways you can reduce the cost of your slickwater completions?

[Taylor L. Reid:]

Yes. 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 of 60,000 to 70,000 barrels of fluid to a frac that's on the order of 250,000 barrels. So accessing a low-cost water and transporting it cheaply and then disposing of it cheaply are all very important, and that's -- goes at some of the things that we're working on to bring that down.

[Andrew Venker:]

Can you speak to the incremental cost associated with some of the other alternative completions you'll be testing?

[Taylor L. Reid:]

Well, 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.

[Operator:]

Next question is from David Tameron with Wells Fargo.

[David R. Tameron:]

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

[Taylor L. Reid:]

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 in second and vice versa. So we've kind of treating lower benches the same at this point. As we get more data and a better understanding, we let you all know.

[David R. Tameron:]

Okay. All right. 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 there other things to do, or where you're at now in that process?

[Thomas B. Nusz:]

Yes. I don't -- I wouldn't tell you that we fully integrated. I mean, our guys are good but we just took over at January 1. So there's a lot of things that we need to do, just on the base plumbing side. And then infrastructure is going to follow. And so that's -- I think, Michael mentioned that it's probably 12 to 18 months in trying to get infrastructure in place in advance of the high-density drilling because you sure don't want to go out and do a lot of high-density drilling and then be trucking oil and water, or not be able to capture your gas.

[David R. Tameron:]

All right. And just a couple more. As I think about the -- if I look at -- the backlog grew a little bit and I know there are some weather impacts. Your completion schedule for the rest of the year, are you still -- it sounds like you can still hit that $205 million gross target. Do you need to do anything on the frac side to get rid of that backlog, or how are you thinking about that?

[Thomas B. Nusz:]

Yes. Keep in mind that we'll -- we've got the other frac crew starting up, Taylor, here, in the next couple of months and plus the weather. That would help.

[Taylor L. Reid:]

That, combined with the number of wells that are on pads. We intentionally had a large percentage on wells on pad going to breakup, which will go now through typically late May, early June. And then we'll have a period where we're able to work down that backlog as we get off of those pad wells and get our frac crews in there. We don't have a constraint on frac 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 think -- 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 then.

[David R. Tameron:]

Okay. And then one more for me and then 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 these well costs and then your completion techniques and you can alleviate those inefficiencies. But are you seeing upward pressure on service cost? And then sand specifically, what's the current snapshot there?

[Taylor L. Reid:]

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 in 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 have 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 a 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 time.

[David R. Tameron:]

Okay. But if we look out 6 months or even a year, some of the sand providers are giving some bullish commentary and I realize they're talking their books a little bit. But I mean, you guys don't see -- you see that market tightening, but you don't foresee issues. Is that the way to read that?

[Taylor L. Reid:]

Yes. We -- there's a lot of sand providers, a lot of available mines at this point. So 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 cost. Now -- I guess, the other question you asked was on general services. And for the Williston, I know some basins are talking about getting a little tighter for the Williston and supply is in decent shape for frac crews and rigs, at least as we see it now for the next 6 months to a year.

[Operator:]

Your next question is from Subash Chandra with Jefferies.

[Subash Chandra:]

Yes. On the slickwater, to revisit that, is there a higher ceramic concentration in these wells?

[Taylor L. Reid:]

So on our slickwater jobs, we're actually pumping all ceramic. And just doing that because the concentration, pumping -- we pump about the same amount of proppant, but it's pumped over 4 times the amount of fluid. So the induced fracs are, we think, more numerous but also not as thick as a conventional gel cross-link job. So at this point, we think ceramic makes sense because of the closer pressure on that thinner frac.

[Subash Chandra:]

Okay. So you get a -- what you're targeting is a more complex fracture network and keeping that open with the ceramics. So if -- I guess, the $1.5 million to $2 million, how much of that is water versus proppant?

[Taylor L. Reid:]

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

[Subash Chandra:]

Okay. And I guess if we look forward, 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 frac and load water? I imagine there would be quite a bit more demand for water as a result?

[Taylor L. Reid:]

The availability of the water, clearly, takes a lot of advance planning to make sure that you got enough within the areas where you're going to frac. We think that, certainly, for the program we're talking about this year, that we'll 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, it's roughly 50-50 ceramic and water. And the water piece of the equation is the biggest one that we can impact right now. But we'll work on both.

[Subash Chandra:]

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

[Taylor L. Reid:]

We've actually, Subash, we've done some jobs with produced water and both the slickwater component and cross link and have done those successfully. So that's one of the things we continue to look at is, if we used produced water for our fracs, can we bring down the cost that way? So obviously, with 250,000-barrel fracs used in 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.

[Operator:]

Your next question is from James Sullivan with Alembic Global Advisors.

[James Sullivan:]

Just wanted to check. I mean, I think that the -- in your documentation, you guys mentioned that you've been applying the new technique, slickwater and others, to the Middle Bakken so far. Is there any thought that you guys would go through the Three Forks with that? And do you have any expectations, given the geology, about whether the uplift will be similar?

[Taylor L. Reid:]

Yes. We do have some Three Forks tests planned. One in particular that we talked about is the White Unit, and that's on page 9 of the presentation. So you can see in that one, we're going to actually do slickwater fracs in all 3 benches, so the first, second and the third. And 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.

[James Sullivan:]

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

[Taylor L. Reid:]

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

[Daniel Braziller:]

Really? Interesting. And the last thing I just wanted to get out in terms of these technology. You did talk about in the presentation, cemented liners. But you haven't -- or you've listed it on there but you haven't mentioned it 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? There are operators who talk about trying to increase the near bore -- the near wellbore fracture systems, and they've had some success with that. Are you guys experimenting with that, too?

[Taylor L. Reid:]

Okay, first on cemented liners. We've done a number of cemented liners tests in the past, probably on the order of 5 to 8 wells. And 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's just varies. And we've got -- some of the cemented liners what we're doing, we've done coil tubing with them and we varied proppant costs and done some other things and pumping the job. So we're not -- we're trying some different things, we're just not ready to come out and talk about that stuff yet.

[Operator:]

Our next question is from David Heikkinen with Heikkinen Energy Advisors.

[David Martin Heikkinen:]

You talked about weather, but can you comment on where 2Q breakup is now and your expected operated and non-operated completions in the quarter?

[Taylor L. Reid:]

So 2Q is -- the weather is warmed up pretty substantially in the basin. We actually had a pretty well behaved breakup going. It's getting quite warm and not a lot of moisture. In the past -- the past week, gotten some pretty significant rains where there were some road shutdowns for a couple of days and, actually, most of the counties implemented that as a breakup measure. And so we -- hopefully, it looks like, at least for the near term, we don't see a bunch of additional rains, so we can continue to 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.

[David Martin Heikkinen:]

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

[Taylor L. Reid:]

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 got continue to work the data. And that's one of the reasons we're doing this full -- or not a full, partial DSU drillout in the White Unit across the Bakken and the benches to test some of that.

[Operator:]

The next question is from Rhys Williams with Johnson Rice.

[Rhys D. Williams:]

On the first full DSU that you talked about on Slide 14, can you give, I guess, some expectation on timing of that or when you might talk about it?

[Taylor L. Reid:]

So that's actually, is it on page...

[Thomas B. Nusz:]

Yes. I think -- you're talking about page 9?

[Taylor L. Reid:]

Page 9?

[Thomas B. Nusz:]

The White Unit?

[Rhys D. Williams:]

That was under page 14, under pad development.

[Thomas B. Nusz:]

Okay. Sorry.

[Thomas B. Nusz:]

Yes, the full -- the 15 to 20?

[Rhys D. Williams:]

Yes. Yes.

[Taylor L. Reid:]

So that actually will be spud in the fourth quarter. So...

[Thomas B. Nusz:]

Spud now.

[Taylor L. Reid:]

Or spud now, actually. And we'll -- it should come on production in the first quarter -- I mean, the fourth quarter.

[Rhys D. Williams:]

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

[Michael H. Lou:]

Yes, we've always kind of said that our marketing team had done a fantastic job, and part of it's 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, it can take a little bit of time to add it there. But because of that flexibility and because we're so connected on the infrastructure side, we do see 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 and the last few years.

[Operator:]

The next question is from Andrew Coleman with Raymond James.

[Andrew Coleman:]

I'm just wondering -- well, first one I had was just thinking back to the question on the coil tubing potential for the completions. Do you have a sense or, at this point, it probably is pretty early, but how much that might reduce cycle times?

[Taylor L. Reid:]

At this point, what -- where we think we could get to is that cost and cycle times would be kind of neutral to one of our regular fracs. So the real benefit is if we can get uplift in terms of production. Where you could save some additional time is on cleanout. We potentially don't have to do cleanouts on these coil fracs, so that could be an additional cost and timesaving.

[Andrew Coleman:]

And would you be able to potentially circulate, I guess, clean out the hole and kind of get some flowback, 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 and let the well come back?

[Taylor L. Reid:]

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

[Andrew Coleman:]

Okay. All right. And then I guess last question on that then is, do you think that -- will there be a need -- there probably isn't one right now, but as you look in the future, to maybe buying a coil tubing or I don't know, if you guys look at adding more to OWS after the second crew comes on?

[Taylor L. Reid:]

Yes. At this point, early days, it's really you have to work-over over broader areas. We're not really looking at that right now.

[Operator:]

[Operator Instructions] The next question comes from Noel Parks with Ladenburg Thalmann.

[Noel A. Parks:]

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 detail 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 assumption you have in the presentation, and I'm looking at Slide 25, which I think is unchanged from the last version, you have started the 10-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?

[Thomas B. Nusz:]

Keep in mind, Noel, what we said consistently is we've kind of want to approach this from one direction, so that with additional data, for instance, like in the Three Forks is -- and I forget what slide it is -- where we're kind of expanding the area, where we see the second and third bench, could have some influence. One of the things, as Taylor talked about, is that what's the tradeoff potentially between slickwater and well density, and we'll see some of that in this White Unit and some of the interference testing there. So we had 80% uplift in inventory at the end of last year. I mean, I wouldn't sit here and expect to see a big jump going into the end of the year. It will just be a function of when we get the right data. But keep in mind, for instance, in those slickwaters where that activity is really a bit more back-end loaded, so you think about all that happening in the second half of the year, I wouldn't expect a big change, but we'll just see.

[Noel A. Parks:]

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 the future date or a future year where you can map out a drilling path that's based just on what you want competitive return to be as opposed to -- at a given commodity price as opposed to -- I guess, now you should be doing pretty much a systematic sort of march across the acreage?

[Thomas B. Nusz:]

Yes. As Taylor touched on, the economics are pretty robust across the entire position. As you've -- in lower areas of recovery, you have lower well cost. And I think, going forward, that how you allocate capital and the timing of drilling wells or full DSUs may be 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 kind of infrastructure poor, you don't want to outrun that. And so I think you 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 you're 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 IRRs. So I think 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.

[Operator:]

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

[Irene O. Haas:]

Question is, how's second quarter looking? Any ice pack forecast and things of that nature?

[Taylor L. Reid:]

So actually, we've had a pretty nice warm-up through April and pretty well behaved breakup, as far as the breakups go. And so the frost is effectively out of the ground. The other thing that's happened is it's been fairly dry. Some springs, you really get a lot of rain. And we just had one impactful incident so far, which we had 2 or 3 days of 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 end of breakup and road restrictions to come off by end of the month. And it really hadn't hampered us a whole lot of this point, so we're pretty encouraged.

[Operator:]

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

[Thomas B. Nusz:]

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're 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.

[Operator:]

This concludes today's conference call. You may now disconnect.