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 Q1 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 Liu, Oasis' CFO to begin the conference. Thank you. Mr. Liu, you may begin your conference. Thank you, Mike.
Good morning, everyone. This is Michael Liu. Today, we are reporting our Q1 2014 results. We're delighted to have you on our call. I'm joined today by Tommy News 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 ks 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
Good morning and thanks for joining us today. In the Q1, our team continued to execute and deliver on expectations as we produced in the middle of our production range and continued 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 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 we'll 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 Q1 activities.
First, we continue to grow production in the quarter with a 5% increase over the 4th quarter, excluding our recently divested Sanish assets. For the 2nd 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 half of the year with increased activity. 2nd, 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 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 at 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. 3rd, we're continuing to optimize well costs and improve capital efficiency.
In the Q1, our average well cost was just $7,200,000 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 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 costs on our base design and our shift to multi well pads, we're sticking with our original $1,400,000,000 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.
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 910 in our investor presentation that shows 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 Foreman Butte and 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 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 profit quantity, concentrations and method of delivery. In areas of the basin with the thickest section and highest charge, we will test much higher profit 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 at the frac in zone, increase EURs and reduce well costs. Finally, we're working on some completion designs around the delivery of proppant through coiled 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 4.50 MBOE type curve.
That combined with our recent well cost in the area of $1,000,000 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 Threefour 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 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 of the lower benches throughout our position. You can see the results for wells with over 30 days of production on the slide, including the Paul S, Patsy, Omelet, Mangum and Bonita. As you can see, all the wells are producing within or above our tight curve range, except for the Bonita, which is on the far eastern side of our East Nesden position. There are 4 additional wells with less than 30 days of production that have not been included in the graph due to early time data.
The Highstead and Lefty wells are 2nd bench wells in Indian Hills, both of which have performed like other lower bench wells in the area in early time. The Osage well, a second bench test in South Cottonwood produced 780 barrels equivalent per day in its 1st 7 days, which would place it in the middle of our type curve band. The last well we'll highlight the AVA in the 3rd 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 gained 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.
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 established 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've 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 that we booked workover activity in frac protect to our LOE, which caused a bit of an uplift there. Similar to the Q4, 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 4th quarter.
We should be able to reduce the fixed component over the course of the year in the variable piece over the next 18 to 24 months with saltwater disposal infrastructure. Additionally, we had just over a $1 BOE impact to LOE in the Q1 from increased workovers and frac protect work. We're 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 4th 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 $240,000,000 of EBITDA for the Q1. With capital expenditures of $308,000,000 in the Q1, we had only a $68,000,000 outspend moving closer to cash flow breakeven. Coupled with our tax efficient sale of our Sandish properties for $322,000,000 and the repayment of our revolver, our balance sheet is in good shape with net debt to annualized 1st quarter EBITDA at approximately 2.3 times and our liquidity remains strong with $1,500,000,000 available. This includes our $1,500,000,000 revolver, which was recently redetermined to a $1,750,000,000 borrowing base, although we decided to leave commitments at the $1,500,000,000 level. Finally, OWS has been a very successful business for us.
It has returned more than 2 times the cash we have invested in OWS since its inception. Throughout 2013 and into the Q1 of 2014, OWS saved the company about $400,000 per net well. The second spread should be at full capacity this summer 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. Your first question is from Scott Hanold with RBC Capital Markets.
Thanks guys. Good quarter. It sounds like your guys are getting a little bit more, I guess, sort of in terms of looking at different types of completion techniques. And it certainly looks like the slickwater fracs where you've got a what over 60 wells now. I think it looks like it being drilled has shown much better results.
And could you again tell us how much of that of your 500,000 acres that might be applicable for?
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 also have planned test in our Painted Woods area and also in Montana. So we hope to expand as significantly as we tested over a broader area.
Okay. And I guess maybe more pointed 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?
Yes. There's 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 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 that very northern parts of Cottonwood are going to be an application, but we'll see as we push it out.
Okay. And so those are the areas where you're trying different things like those coiled hooping frac that where slickwater may not work. Is that sort of the plan?
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 coiled 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.
Okay. Understood. Thanks.
Thanks, Scott.
Your next question is from Ryan Oatman with SunTrust. Hi, good morning.
Good morning. I thought the operations update was encouraging. 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 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? Yes. So the cost difference in a slickwater job versus our base design is on the order of $1,500,000 to $2,000,000 more to do with slickwater.
When you look at our wells to date and our cost to date, so 7.6 gross and 7. Net that includes a few slickwaters, but not as greater 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 Q1 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 a progress I should say that's 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, we're it's a process. We've kind of talked to 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 3rd 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 at 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.
Great. I'll hop back in the queue. Thanks.
Thanks.
Your next question is from Dave Gisler with Simmons and Company.
Good morning, guys.
Hey, Dave.
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 this year?
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 2014.
And just thinking about that, if it's really factoring into call it the 1st part of 2015, 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?
Dave, the combination of winter dependent 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 of 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 talked about 4 to 5 wells per formation through the 3 Forks III. How much of your acreage should we start thinking about that as a legitimate possibility? Admittedly, you guys have taken 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 one the slickwater DSU drill out?
Exactly.
Yes. So this what we're trying to figure out is what is the drainage area like for really 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 BSU. And based on what we see, we'll it'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.
The next question is from Drew Venker with Morgan Stanley. Good morning, guys. With the slickwater, are you seeing more outperformance early on in 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.
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 data stuff we have is maybe on Liberty, some Liberty jobs around a year and a half or so. And so we continue to see outperformance. It's not consistent on every well, but on average you maintain that.
And then are there ways
you can reduce the cost of your slickwater completions?
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 that's 60,000 to 70,000 barrels of fluid to a frac that's on the order of 250,000 barrels. So accessing low cost water and transporting it cheaply and then disposing of it cheaply are all very important and that's those are some of the things that we're working on to bring that down.
Can you speak to the incremental costs associated with some of the other alternative completions you'll be testing?
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.
Thanks.
Next question is from David Tamarin with Wells Fargo. Good morning. Can you guys talk about in your 3 forks there that 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 2nd bench and the 3rd 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 3rd bench wells that are better in 2nd 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. 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 in that process?
Yes. I don't yes, I don't I wouldn't tell you that we fully integrated. I mean, our guys are good, but we just took over 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 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 then be trucking oil and water.
Yes. No, that makes 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 and I know there's 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 frac side to get rid of that backlog?
Or how are you thinking about that?
Yes. Keep in mind that we'll we've got the other frac crews starting up Taylor here in the next couple of months. So and plus the weather. Yes. Hope that will help.
And 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. 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. And like Tommy said, we'll be adding our second crew, but we have the ability to flex with our 3rd parties and we currently use both Nabors and Schlumberger as our 3rd party providers. So we think we'll Okay.
Yes. 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.
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 etcetera. 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 are have talked about fighting the well costs and the new completion techniques and you can alleviate those 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 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 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 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.
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?
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 costs.
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 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.
Okay. I appreciate all the answers.
Thanks, Dave.
Your next question is from Subash Chandra with Jefferies.
Yes. On the Q3 to revisit that, Is there a higher ceramic concentration in these wells?
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 conditional gel crosslink job. So at this point, we think ceramic makes sense because of the closure pressure on that thinner frac.
Okay. So you get what you're targeting is a more complex fracture network and keeping that open with the ceramic. So if I guess the $1,500,000 to $2,000,000 how much of that is water versus proppant?
Well, I don't have it off the top of my head, but there is some additional ceramic costs 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 frac 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 advanced planning to make sure that you've 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 that's roughly fifty-fifty 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.
All right. Got it. And one final one for me, just back to the water. Recycling water is 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 trout?
We've actually Sebastian, we've done some jobs with produced water and both the slickwater component and cross linked 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. Obviously, with 250,000 barrel fracs 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. So but we're looking at it.
Okay. Thanks. Your next question is from James Sullivan with Alembic Global Advisors. Your line is open.
Hey, good morning folks. Good morning. Just wanted to check, I mean, I think that the in your documentation, you guys mentioned that you've been applying the new techniques slickwater and others to the Middle Bakken so far. Is there any thought that you guys would go through to the Three Forks with that? And do you have any expectations given the geology about whether the uplift would be similar?
Yes. We do have some Three Forks test plan. 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 three benches. So the first, second and the third.
And we're looking at some additional tests that will also be in the 3 fourths. No reason why that we see why you shouldn't get a similar uplift by doing that stimulation in the 3 fourths versus the Bakken. Okay. Okay. Sounds good.
The 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 mean, I would assume not in Red Bank and Forman Butte as it was in the charged part of the basin? Sure. The uplift is like we talked about specifically Granite Hills was around 25%.
When you look at Foreman Butte and East Red Bank, it's actually over 30%. So of the wells down in those areas, we've actually seen a little better increase. Really? Okay. Interesting.
And then the last thing I just wanted to get at in terms of these technologies. 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 coiled 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? The operators have talked about trying to increase the near bore wellbore fracture systems and have had some success with that.
Are you guys experimenting with that too? Okay. 1st 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 just varies. And we've got some of the cement aligners where we're doing we've done coiled tubing with them and we've very profit cost has done some other things in 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. Okay.
Sounds great. All right. I'll hop back in the queue. Thanks guys.
Thanks.
The question is from David Heikkin with Heikkin Energy Advisors. Good morning. You talked about weather a bit. Can you comment on where 2Q breakup is now and your expected operated and non operated completions in the quarter?
So, 2Q has the weather has warmed up pretty substantially in the basin and we actually had a pretty well behaved breakup going. It's gotten 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 don't see a bunch of additional rain. So if we can continue to break up 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 1st 90 days directly correlative to EUR uplift?
Hey, Dave. That's the part that we don't know yet and we're working on. Is it truly all unique reserves as 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.
The next question is from Rhys Williams with Johnson Rice.
Good morning, guys. On the first full DSU that you talked about on slide 14, can you give us I guess some expectation on
So that's actually it's on page yes, thank you.
You're talking about page 9. Page 9? No, I
was under page 14 under pad development.
Okay, sorry.
No problem.
Yes. The full the 15% to 20%?
Yes.
So that actually will be in 4th quarter. So or spud now actually and will should come on production in the first quarter, I mean the
Q4. 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?
Yes. We've always kind of said that our marketing team has done a fantastic job and 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's going to 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 last few years.
Great.
That's it for me. Thank you.
Thanks. The next question is from Andrew Coleman with Raymond James.
Hey, great. Thanks a lot for taking my questions this morning. The first one I had was just thinking back to the question on the coiled tubing potential for the completions. Do you have a sense or at this point it's probably pretty early about how much that might reduce cycle times?
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 clean out. You potentially don't have to do clean outs on these coil fracs. So that could be an 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 is it who would you still at this point think about just pumping the whole job before you go in there and try to let the well come
back? Yes. 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 then I guess last question on that then is, do you think that would there be a need there probably isn't one right now, but as you look at the future to maybe buying a coal 2 unit if you guys look at adding more to OWS after the second crew comes on?
Yes. At this point, early days. It's really at the work over a broader area. So we're not really looking at that right now.
Okay. Thank you for your time this morning.
Thanks, Andrew. The next question comes from Noah Parks with Ladenburg Thalmann.
Good morning.
Hey, Noel.
I also like many people got on a bit late. And I just wanted to ask about the overall inventory. You guys are afraid about giving a lot of really granular detail about how you look at the inventory. Just thinking about going 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 and I'm looking at slide 25, which I think is unchanged from the last version.
You have sort of the 10 well per unit assumption. Is that distribution of that to be increasing any do you think? Do you think you might be able to get even more aggressive by the end of the year?
Well, I again, keep in mind, Noah, 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 is I forget what slide it is where we're trying to expand in the area where we see the 2nd and third bench could have some influence. One of the things as Taylor talked about is that what's the trade off 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 an 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, we're 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.
Thanks. And just also as you continue to drill a mass of 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 future day or future year where you can map out a drilling path that's based just on what you want the pattern of returns to be as opposed to at a given commodity price as opposed to, I guess, now you're sort of doing 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're 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'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 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.
Thanks a lot. That's helpful. That's all for me. Thanks.
Your next question is from the line of Irene Haas with Wunderlich. Your line is open.
Hey, hello everybody. Congratulations on a really strong quarter considering how rough the weather is. Question is how's second quarter looking? Any ice pack forecast and things of that nature?
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 has 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 in a breakup in road restrictions to come off by end of the month and really it had hampered us a whole lot at this point. So we're pretty encouraged.
This is great. Thank you.
Thanks, Harry.
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'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 cover today. Thank you again for joining us on the call.
This concludes today's