Oasis Petroleum Inc.
Q2 2015 Earnings Call Transcript

Published: 5 Aug 2015

[Operator:]

Good morning. My name is Catherine, and I'll be your conference operator today. At this time, I'd like to welcome everyone to the Second Quarter 2015 Earnings Release and Operations Update for Oasis Petroleum. All participants will be in listen-only mode. After today's presentation, there will be an opportunity to ask questions. Please note this event is being recorded. I would now like to turn the call over to Michael Lou, Oasis Petroleum's CFO, to begin the conference. Thank you. Mr. Lou, you may begin your conference.

[Michael H. Lou:]

Thank you, Catherine. Good morning, everyone. This is Michael Lou. Today, we are reporting our second quarter 2015 financial and operational results. We're delighted to have you on our call. I'm joined today by Tommy Nusz and Taylor Reid, as well as other members of our team. Please be advised that our remarks, including the answers to your questions include statements that we believe to be forward-looking statements within the meaning of the Private Securities Litigation Reform Act. These forward-looking statements are subject to risks and uncertainties that could cause actual results to be materially different from those currently disclosed in our earnings release and conference call. Those risks include, among others matters, that we 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 and on our website. We will also reference our August Investor Presentation which you can find on our website. With that, I'll turn the call over to Tommy.

[Thomas B. Nusz:]

Good morning and thank you for joining us today on our second quarter 2015 earnings call. I'm pleased to announce that we've delivered another strong quarter coming in above the high end of our production guidance range and below the low end of our guidance on LOE. We're also right on top of our internal CapEx plan for the first half of the year and are ahead of schedule on our plan to lower well cost and live within cash flow. I will go into more detail on these items momentarily, but first, I'd like to focus on where we are currently versus our original 2015 plan. As you'll recall, at the end of 2014, well costs for our high intensity completions were coming in around $10.6 million and our goal was to decrease those to an average of $9.5 million this year. During the first quarter, we were able to drive those costs down in the $9 million range and we're now around $7.8 million for slickwater completions in the core. About half of the cost savings came from service cost reductions and the other half came from efficiency gains, which tend to be a bit more structural in nature and will likely remain if we pick up the pace of activity. During the first quarter, cash flow outspend, as measured by EBITDA less CapEx and cash interest, was about $103 million. We projected that we would be close to breakeven on this metric for the remainder of the year. I'm happy to report that during the second quarter, we were actually positive by about $36 million and we continue to expect to be neutral or more likely positive for the second half of 2015. For the quarter, we completed 21 gross operated wells in line with what we said we would do at six wells to eight wells per month. We expect to be at the low end of that monthly range for the remainder of the year completing about six wells per month since we've completed 44 wells during the first half of the year versus our full year plan of 79 gross operated completions. Given the current backdrop for oil prices and mindful of managing our cash flow, we've elected to delay the completion of a number of our drilled but uncompleted wells even though we expect to come in under our full year CapEx budget by about $35 million. While we still have a board approved budget of $705 million that gives us the flexibility to slot additional wells and if oil prices improve considerably, we're currently planning on spending about $670 million on CapEx in 2015. We continue to experience outperformance from our high intensity wells compared to what we originally modeled. Additionally, we have improved uptime performance resulting in a 3% beat compared to the high-end of our first quarter range and another 2.5% beat above the high-end of the second quarter. With our year-to-date outperformance expected continued success and July operational volumes trending north of 50,000 MBoe per day, we're raising full year production guidance to 49,000 barrels to 50,000 barrels of oil equivalent a day, up from the 46,000 barrels to 49,000 barrels from May. With the increase in production guidance in 2015, we're still forecasting relatively flat production throughout 2016 versus the fourth quarter of 2015, which is about 5% higher than originally anticipated. As a reminder to everyone, when we put together our 2015 budget, we used a $50 WTI price for the entire year. We set the plan up to operate the business in a weak oil price environment and to adjust our operations as we pull different levers or realized the different oil price, while WTI topped our budget in the second quarter were now back at levels very similar to our original budget. The team has done a great job managing key drivers to cash flow from production and capital cost to LOE and differentials. So we positioned the company well in a less than stellar macro environment. With that, I'd like to turn the call over to Taylor to go into a little more detail.

[Taylor L. Reid:]

Thanks, Tommy. First, I'd like to remind everyone that substantially all the activity for the remainder of 2015 will be focused in the core of the basin. The area which we define as core, including Indian Hills, Wild Basin and Alger, that's about 825 locations, 701 of which are located in the Middle Bakken or the first bench of the Three Forks. At the current pace of completions, this equates to eight years to 10 years of inventory. Not only does operating in the core allow us to drill the highest EUR wells, it also allows us to capture efficiencies through high well density pad operations and reduce cost through infrastructure, which you're seeing play out in both our well cost and LOE. Our focus in 2015 has remained on capital preservation and solid operational execution with an eye towards remaining flexible and opportunistic in this very volatile environment. During the first quarter call, we talked about dropping from five rigs down to four rigs as a result of efficiency gains to moderate spending in this low commodity environment. Likewise, in the second quarter, we realized the opportunity to further reduce rig count from four to three as a result of higher efficiencies on the drilling side of the business. We now plan to run three rigs for the remainder of the year. We have seen drilling days, measured by spud to rig release, fall from about 24 days last year to 16 days more recently for wells drilled in Indian Hills. We've also seen efficiency gains on the completion side improving 40% quarter-over-quarter. During the quarter, we completed 21 gross operated wells, including 18 in the core with seven in Alger and 11 in Indian Hills, plus we had one completion in Montana and two in North Cottonwood. This results in 86% of the activity being in the core, with about 60% of our total activity being focused on high intensity completions for the year-to-date. As mentioned, we expect to complete 100% of our wells in the core for the balance of 2015, with about 65% of that activity being high intensity completions. I'll now direct you to our Investor Presentation, which was updated this morning. The high intensity wells that we have completed this year continue to demonstrate the same type of outperformance that we have seen in the past relative to our type curves for hybrid completions. On page nine, you can see the updated outperformance relative to our type curves now averages between 34% and 54% in the core. This includes all of our most recently completed wells. In Indian Hills, we added six wells to our Middle Bakken high intensity population, bringing the total to 14 wells, and five wells to our first bench high intensity population, bringing the total to nine wells. In Alger, the well count did not change, but we have more longer-dated production. As you can see, both areas continue to significantly outperform the base wells. Moving to the next slide. You can see our updated economics run with our latest well cost of $8 million for high intensity completions and $7 million for a hybrid style completion. As you can see with our new costs, we can achieve 20% to 35% IRRs with our high intensity fracs in the core at $50 pricing. We continue to believe that there is still room for service cost to come down and for additional efficiency gain should we continue in this $50 environment. On slide 12, you can see the performance of our high intensity completions outside the core, in this case, in Montana. We have talked about these wells before and continue to be encouraged by their performance. As a reminder, the Jimbo Federal well was our slickwater style completion, utilizing all sand instead of ceramic, which resulted in savings of about $500,000. As you can see, the well is performing in line with the average of offset slickwater completions using ceramic and both are materially outperforming the type curve for the area. We believe we can complete these slickwater wells for around $7 million to $7.5 million, which produces IRRs above 20% at $60 pricing. We're not saying we're going to move outside the core right now, but we're really excited to see that through cost reductions and high intensity performance gains, these areas are positioned to provide good returns in a low oil price environment. Based on this success, we also plan to test all-sand in the core. On page five of our presentation, you can see that total costs for our two high intensity style completions, slickwater and high volume proppant are now coming in at $7.8 million and $8.3 million, respectively, representing a 26% improvement to our year-end 2014 cost. We plan on completing some all-sand slickwater tests in the core during the second half of 2015, which has the potential to save another $500,000 versus current well costs. With that, I'll turn the call over to Michael.

[Michael H. Lou:]

Thanks, Taylor. To add to Taylor's comments about efficiency, we have seen significant improvements in LOE, largely due to connecting and moving more volumes on our saltwater gathering pipelines. At the end of 2014, we were around 40% connected and we have moved that to around 65% connected in the second quarter. Having these volumes move on the OMS system was the primary driver for the 4% drop in our LOE quarter-over-quarter. We are now running about 18% below our 2014 LOE per Boe levels, coming in at $8.26 during the second quarter. As you know, we break out OMS as its own segment and we reported EBITDA of $10.7 million in the first quarter of 2015. During the second quarter, we grew OMS EBITDA to $17.4 million, primarily due to more saltwater volumes and a pickup in activity in our freshwater distribution business. While we did not expect to keep freshwater at these heightened levels for the remainder of the year, we're now targeting north of $55 million in EBITDA for OMS in 2015. We've highlighted the performance of the White and Hagen Banks wells in Wild Basin on past calls. The wells continue to impress and we continue to invest in the midstream infrastructure project in Wild Basin. We are currently building the natural gas processing facility and are working on finalizing right away for oil, gas and water lines that will be ultimately be constructed next year. On past calls and in other discussions, many of you have asked about our opportunity to monetize OMS, both the existing water distribution gathering and disposal business, as well as the Wild Basin project. While we don't have any formal update on timing, we are continuing the process to potentially monetize these assets and are exploring numerous options and we will give you an update when we have something more definitive. As we've discussed in the past, we are very focused on maintaining control while maximizing the value of this rapidly growing business. We have seen encouraging data points in the market with infrastructure capital coming into the Williston Basin through either strategic acquisitions or through private capital investments at extremely compelling valuations. The good news for Oasis is that we have a strong liquidity position to fund infrastructure until we find the right option to maximize value and keep control. From a liquidity standpoint, we exited the second quarter with only $155 million drawn on our $1.7 billion borrowing base. We have $1.5 billion of elected commitments and we expect that the fall redetermination should not have a material impact on this number. Even though we expect things to run at lower price deck in the fall than they did in the spring, we have a lot of positive momentum to offset lower commodity prices including lower well costs and LOE and better differentials. Speaking of better differentials, in 2015, we've continued to see some great pricing out of the Williston Basin. We were below our guidance range of $6.50 per barrel to $7.50 per barrel in the second quarter coming in at $5.90 per barrel off of WTI. We expect the third quarter to range between $5.50 per barrel and $6.50 per barrel as we continue to benefit from flattening production and additional takeaway capacity in the basin. Conversely, natural gas price realizations came in a bit light primarily driven by both lower Henry Hub and liquids pricing. We will likely see a slight step-up in the third quarter in natural gas price realizations. We did see some oil price improvement in the second quarter in WTI, and we were able to layer in some additional hedges for both the second half of 2015 and in 2016. We've increased our position to 28,000 barrels of oil per day at an average floor of $75.61 in the second half of 2015 to 8,000 barrels of oil per day at $63.20 in the first half of 2016, and 3,000 barrels of oil per day at $63.94 in the second half of 2016. On the G&A front, we have continued to manage cost down to all-time lows in the second quarter, and cash G&A per Boe came in at $3.38, which is down 21% compared to 2014 levels. All-in cash operating costs including LOE, production taxes, differentials and cash G&A are down 25% to 2014 levels, and totaled $23.71 per BOE in the second quarter. Taylor spoke about our efforts to remain flexible in the downturn. You've seen us proactively manage our services with lower pricing and minimal contract breakage penalties and we have seen significant operational efficiencies all contributing to lower capital and operating costs. This has allowed us to outperform on nearly every metric for the year with higher production on lower capital and stronger cash margins with higher realizations and lower operating cost and G&A cost. For the second quarter and through the remainder of 2015, we expected to be cash flow positive while continuing to grow annual production 79% year-over-year. As we look into 2016, we continue to remain flexible, especially given the uncertainty of the oil price environment. In 2016, at a $50 WTI flat deck, we believe that we can continue to keep capital within cash flow assuming alternative financing for OMS, which will keep volumes flat and maybe even growing a bit from 2015 levels. If oil price starts to move north of $55 or $60, we will begin shaping a broader capital plan for 2016, which will start showing higher year-over-year growth, still managing to keep cash flow neutral. Additionally, as Taylor mentioned, it is important to note that we have great economics in the core as well as outside of the core. Our high intensity production results and recent cost reductions in areas like Montana continue to prove that we have a deep cost resilient inventory in our extended core and fairway areas that extends well past eight years to 10 years of core inventory. Finally, we mentioned that the second quarter was a tremendously successful quarter for Oasis. Our team did a great job of coming in over our production guidance range allowing us to increase production guidance range for the year while expecting to come in under budget on capital. With additional production along with reductions in operating costs, better differentials and lower G&A costs, we expect to be able to continue to improve our balance sheet and capital structure in the second half of 2015, setting ourselves up for the future. With all the hard work of our employees, we've quickly repositioned Oasis to be able to continue to grow and make solid returns at a much lower oil price in 2016 and beyond while continuing to spend within cash flow and preserve our strong liquidity position. I'll now turn the call over to Catherine for questions.

[Operator:]

We will now begin the question-and-answer session. Our first question comes from Neal Dingmann with SunTrust. Please go ahead with your question.

[Neal D. Dingmann:]

Good morning, guys.

[Michael H. Lou:]

Good morning, Neal.

[Neal D. Dingmann:]

Hey. Just a quick question. Tom, you guys obviously liquidity-wise are doing very good. But you've got obviously a big benefit when I look at the – probably the cash basis or even the potential of the Oasis Midstream Services or all that infrastructure development you'll have. I'm just looking at the slides 13 and 14. Your thoughts anytime soon or down the line about potentially monetizing either of those?

[Michael H. Lou:]

Yeah, on the midstream business, we have looked at a number of options. And like we said in the prepared remarks, we've got a lot of things that we're evaluating now. Obviously, there are a number of options. We've seen a lot of capital come into the Williston on the infrastructure side at pretty compelling valuations. We're focused on maintaining control and getting the highest value. So we'll continue to work down that path. We do think that something can come here in kind of the near future, but we'll give you guys a little bit more when we get something a little more definitive.

[Neal D. Dingmann:]

Okay. And then just lastly, one follow-up on that slide 11. It certainly was the case this quarter, and it's evident by the stock price today about this improving economics with the higher recoveries and lower cost. I mean going forward, I mean is that – that higher intensity completions that we should kind of assume or I mean I guess how should we think about that versus that base completion economics?

[Taylor L. Reid:]

Sure. So if you – as we talked about, we continue to ramp up the percentage of our completions that are high intensity 20% last year. First half, it was 60%; second half, it'll be 65% of our activity. If we continue to see this type of performance that we've seen in these wells, we'll push that up closer to a 100% in 2016.

[Neal D. Dingmann:]

Got it. Thank you, all.

[Taylor L. Reid:]

Thanks, Neal.

[Operator:]

Our next question comes from Steve Berman with Canaccord. Please go ahead with your question.

[Stephen F. Berman:]

Thanks. Good morning, guys. Maybe a question for Michael. The comments surrounding flat to moderate production growth in 2016 and generating cash, I think that would imply a CapEx budget with a 3 in front of it. Is that a fair assumption? What are you thinking for spending next year based on comments you made earlier?

[Michael H. Lou:]

Yeah, Steve, on the D&C side, what we've said about 2016 in this kind of environment, we kind of called it around $400 million or just under $400 million. I think that with where costs are, et cetera, we think we can keep production, albeit at even a higher level because we performed well this year, next year we can keep that flat to growing a little bit, still in that $350 million to $400 million range on the D&C side.

[Stephen F. Berman:]

Okay. Thanks for that. And just one follow up. What are you seeing from your non-operated working interest partners? I know there's been some non-consent given where oil prices are. Although I guess with companies focused on their main areas, it's maybe hard for the non-op partners to say no. What's been your experience lately with that?

[Taylor L. Reid:]

It's been a bit of a mix. We've got a few partners that have been going non-consent. And really as the year has worn on, we've seen a little bit less of that. I think that's probably a reflection of well costs coming down as much as they have. But there is still a portion that we're seeing non-consent, but we've planned for that within our budget numbers and we think we're in good shape.

[Stephen F. Berman:]

All right. Great. Thanks, guys.

[Taylor L. Reid:]

Thanks.

[Operator:]

Our next question comes from Michael Hall with Heikkinen Energy Advisors. Please go ahead with your question.

[Michael Anthony Hall:]

Thanks. Good morning and congrats on a solid update.

[Taylor L. Reid:]

Thanks, Mike.

[Michael Anthony Hall:]

I guess I just wanted to circle back on the well cost side of things, again, and sorry if I missed this in the remarks or questions so far. But what would you say maybe a target well cost might be for the beginning of 2016 or by year end 2015 on the high intensity completions in the core?

[Taylor L. Reid:]

As we talked about, we're at $7.8 million for slickwater in the core right now. If we continue to see reductions, and that's really going to be both on efficiency side and on service cost, we'd like to think going into next year we'd be able to get them down another 10%, but we're going to have to continue to monitor.

[Michael Anthony Hall:]

Okay. And on the slickwater versus the high volume proppant, how should we think about how you're evaluating between those two options currently?

[Taylor L. Reid:]

So it's...

[Michael Anthony Hall:]

Can you not take higher volume proppant to the slickwater, I guess is also what I'm trying to think about.

[Taylor L. Reid:]

Yeah, really, Mike, what we are doing is testing each of those high intensity completions across the position in the core. So we've got a mix in Indian Hills and Alger and we'll do the same thing in Wild Basin. And then based on the success of one or the other, depending on the area, we'll make a move to something that's more reflective of that style completion. So by the end of this year, we're going to be in a better position to make that call and then you'll see us start to modify the completion design around that data.

[Thomas B. Nusz:]

But I think it gets driven by the rocks. And depending on where you are in the Basin, ultimate performance varies between the two techniques and, as Taylor said, we're testing both and we'll just optimize off of that.

[Michael Anthony Hall:]

Okay. So it's not like you pick one. It's more custom-fitting it to the individual area that you're active in.

[Thomas B. Nusz:]

Yep.

[Michael Anthony Hall:]

Okay. And then that the comments around the potential to be flat to growing modestly within cash flow next year. The comment there also, Michael, was assuming some sort of midstream monetization. So am I to understand then that the gap would be fully covered by the midstream monetization? Was that the intention of that comment? Just want to make sure.

[Michael H. Lou:]

No, I think that's exactly right that any midstream monetization, I think, of the ones that we're looking at can cover that gap on the infrastructure spend, which will be just over $100 million as well as a little bit of other non-D&C capital.

[Michael Anthony Hall:]

Okay. And in the E&P capital itself would be fully funded internally?

[Michael H. Lou:]

Correct.

[Michael Anthony Hall:]

Okay. And as we think about the midstream monetization avenues you're looking at, how should we think about the potential for that to change cost structure down the road?

[Michael H. Lou:]

Yeah, it depends on obviously how we monetize that, Michael. The OMS obviously provides some benefit on LOE as well as some benefit on capital. But given that we'd like to keep control obviously, most of that's going to stay within Oasis. So we'll have to see. At this point, we'll still continue to consolidate, et cetera, on a similar basis. And any smaller minority partner, it would come out below the line.

[Michael Anthony Hall:]

Below the line. Okay. It's very helpful. Appreciate it, guys. Congrats again.

[Michael H. Lou:]

Thanks.

[Operator:]

Our next question comes from Biju Perincheril of Susquehanna. Please go ahead with your question.

[Biju Perincheril:]

Hi, good morning.

[Thomas B. Nusz:]

Good morning.

[Biju Perincheril:]

I'm looking at some of the enhanced completions both slickwater and high proppant volume. It looks like you see a more consistent pickup in productivity when these wells are drilled on tighter spacing? First of all, do you agree with that observation? And if you do, I was wondering what – is there an explanation of why that may be the case?

[Taylor L. Reid:]

We are – I don't know that we've necessarily seen a higher pickup at tighter spacing, but those really are the two things we've got to understand. One is, what is the uplift, if we do these high intensity completions, very importantly, what is the uplift when you do it in spacing, so drilling out a full DSU and doing all of those fracs close together, we've got to get that right and that's one of things we'll continue to work on spacing with the high intensity fracs and it's – we think we've got a pretty good answer right now and we'll continue to perfect that as we go and every year you will see us modify that spacing plan a bit, but we think we're in pretty good shape.

[Biju Perincheril:]

Okay. Is to fair to say that the tighter spacing you haven't seen any deterioration or more interference?

[Taylor L. Reid:]

At this point, the well results continue to show consistent uplift and so it wouldn't indicate interference.

[Biju Perincheril:]

All right, great. Thanks.

[Operator:]

Our next question comes from Ron Mills with Johnson Rice. Please go ahead with your question.

[Ronald E. Mills:]

Good morning. Hey, guys. With another three months of production data that you show on slide 10, the well performance continues to get even better, but when you look at your acreage position or across Indian Hills and in Alger, how repeatable do you think those results are? Or within that core area, do you think there is potential variability across that position?

[Taylor L. Reid:]

Ron, based on what we're seeing right now and we've got to – if you look at the map on page 9, you can see there's a fair spread of where these tests are for the high intensity completions. We're seeing pretty consistent uplift and so we're feeling good that you're going to see that same type of performance across not only the whole core position but as you get into areas like Montana really seeing great uplift as well.

[Ronald E. Mills:]

Okay. And as it relates to slide 10 and just with your production guidance, you obviously brought the low end of 6% or 7% this quarter, but to the extent that that wells continue to perform tracking the million plus barrel range at Indian Hills and call it 850,000 barrels or 900,000 barrels at Alger, how much of a headroom would you have on future production guidance maybe to address as your growth comment, Michael, based on additional production history in these areas?

[Taylor L. Reid:]

So, Ron, we've actually factored in that uplift in the high intensity wells. We modeled 25% to 30% uplift, so there is a bit of potential upside on top of that relative to some of the performance you're seeing.

[Ronald E. Mills:]

Okay. And then from a relative – just because of the way the wells have held up, you have the higher initial productivity and you talked about potential EUR uplifts of 10% to 30%. How much more history would you like to see before you feel more comfortable with that EUR uplift can be greater than that in the 30%?

[Taylor L. Reid:]

So if you ask our reservoir engineers, they'll tell me 5 years to 10 years, but I think it's – by the end of this year and as we get a little more into the next year, we're just going to get more comfortable. And I think that clearly it's at least the 10% to 30% is feeling pretty good, but we got to continue to do the work. And that's not only seeing this production history, but also we're doing a lot of work on modeling, simulation, sub-surface analysis, and we got to pull all those tools together to make a final determination.

[Ronald E. Mills:]

Okay. And then what's even more impressive about the production growth is it's occurring as even as your – you've continued to build your uncompleted well inventory. I know you had originally planned – entered the year at 70 wells to 75 wells plan to exit around that same level, but I think you have more in completed wells in hand now. Where do you now expect to end the year in terms of uncompleted wells?

[Taylor L. Reid:]

We're probably going to build that backlog of completions a bit. We entered 70 wells to 75 wells. We're likely to end up end of the year in the 80s, maybe kind of mid-80s range. And as we talked about, we've been a lot more efficient on the drilling side. And so that pace of drilling has just resulted in a little – and a few more wells are piling up in that waiting or completion inventory. Now, relative to where we are at mid-year, we're at 93 wells and we'll work that down obviously from now till end of the year being in the mid-80s.

[Ronald E. Mills:]

Perfect. Then one last one just, Michael, on the midstream assets. I know you've gone from 40% to 65% or 68% of your wells going through the system. I think, we had talked about potentially getting to 75% or 80% through the system by the end of next year and then the Wild Basin assets really starting to contribute a full year of EBITDA in 2017. If we just look at that EBITDA run rate of $50 million to $55 million today is – on the existing OMS assets, is that something that can grow on the order of – to $60 million, $65 million by the end of next year, and then Wild Basin can add $40 million to $60 million in 2017 or how do we think about the EBITDA growth potential?

[Michael H. Lou:]

Look, I think that your numbers are kind of generally in the right direction, the EBITDA, like you said at Wild Basin production will start in the latter part of next year. It does take a little while to get kind of fully up to speed. So on a run rate end of 2017 basis you're probably in the right ballpark on that front. And then like you mentioned, the saltwater disposal side, while we're at 55% for this year, we can continue to grow that and as we get to that 75% and 80% connected or running through our pipelines on saltwater disposal, hopefully, it's kind of in that range that you're talking about $60-ish million to $70-ish million.

[Ronald E. Mills:]

Thanks. Just looking for the color to try to apply how the KMI and Hess deals would look. But I appreciate and we'd look forward to next quarter.

[Michael H. Lou:]

Thanks, Ron.

[Operator:]

Our next question comes from Gail Nicholson with KLR Group. Please go ahead with your question.

[Gail Nicholson:]

Good morning, everyone. I'm just kind of looking at 2016 forward. At what point do you guys start considering maybe further scaling back at the drilling activity and putting more capital towards the completion front in order to work down that backlog of wells down?

[Taylor L. Reid:]

So, I think as Mike mentioned in his comments, if we stay in this price environment kind of $50 price world, you're going to see us work down some of that in 2016, will be likely it's something more like it a three rig scenario and your completing wells at six – about six a month a little faster than your drilling. So Mike pulled that down by kind of $20 range, but still early for us working on that program for next year.

[Gail Nicholson:]

Okay, great. And then just kind of looking at the high-intensity completions, especially in the lower Three Forks bench results, when you look at that data, do you feel more confident about the high-intensity completion potentially unlocking more lower Three Forks potential across your entire acreage because this is just not in the core or is it a tad too early to tell?

[Taylor L. Reid:]

Still a little early to tell. We're doing half of our completions in the Three Forks and we're at high intensity. When you look at the lower benches, we've really pulled back that inventory in the lower benches to a more limited area now and some of that being in Alger and some of it within kind of Wild Basin area and we've actually continued to see good results in those areas even in the second benches and the third benches. So we'll continue to look at those results and apply some of the high-intensity completions as we do those.

[Gail Nicholson:]

Just for clarification, the 100% sand slickwater test in the core, will that be $0.5 million less than the $7.8 million with 100% ceramic?

[Taylor L. Reid:]

Yeah, that's correct.

[Gail Nicholson:]

All right, great. Thank you.

[Operator:]

Our next question comes from Dave Kistler with Simmons & Company. Please go ahead with your question.

[David W. Kistler:]

Good morning, guys.

[Thomas B. Nusz:]

Hey, Dave.

[David W. Kistler:]

One last one on (39

[Taylor L. Reid:]

So it's about 30% of that is drilling, on the order of $2.5 million, something like that of the $7.8 million.

[David W. Kistler:]

Okay. And then if we think about it in terms of the sand, actually works in terms of 100% sand, that $500,000 would apply directly to the completion component.

[Taylor L. Reid:]

Correct.

[Michael H. Lou:]

Yeah.

[David W. Kistler:]

Okay. And then just one on the credit facility. Obviously, ample liquidity. You set your facility below what was the approved level. I know that it doesn't expire for quite some time. But any thoughts, color you can provide on that? And if I missed that early in the call, I apologize.

[Michael H. Lou:]

Yeah, Dave, what we said about the credit facility is that we do have the $1.7 billion borrowing base, $1.5 billion is the committed level. We do feel like that that's not going to materially change – that $1.5 billion committed level is not going to change drastically. We do expect the banks to have a lower price deck. We think we can partially offset that with better differentials, better LOE and well costs, et cetera. So all the work that we've been doing for the last six months here setting us up in a better price environment also helps us on the bank deck. So we feel like that liquidity position still will remains strong.

[David W. Kistler:]

Outstanding. Thanks for that clarification, sorry it was duplicated. And then last one just in terms of productivity improvements that you guys have been seeing from slickwater and from high proppant. What are the other things you guys are working on as well, lateral landings, tighter perf clusters and any kind of progress you can talk about on that front that might also increase recoveries per well?

[Taylor L. Reid:]

Dave, we continue to work really on both sides, the completion side of the business to improve performance and so there's a number of things that we're looking at. Stages are definitely one of those and so we've done higher stages in some wells and we'll continue to test the potential impact of that. The other piece is just on the cost side and really working to come up with some step changes in how we drill and complete the wells and there are some things that we think could really make an impact on that side, but still too early to talk.

[David W. Kistler:]

Okay. I appreciate the color. Sorry for pushing on something you're not ready to talk about yet.

[Thomas B. Nusz:]

Thanks, Dave.

[Operator:]

Our next question comes from Dan McSpirit with BMO Capital Markets. Please go ahead with your question.

[Dan E. McSpirit:]

Folks, good morning and thank you for taking my questions. First one, what is the decline of base production today and how does it look at next year at mid-year and at year end in light of the change in the applied completion technique?

[Michael H. Lou:]

Yeah, Dan, what we talked about on previous calls is that at the beginning of this year, we were in a 35% decline rate. When you look at the 2016 number, it's going to be more like 25% to 30%-ish. And by the end of 2016, obviously, it continue to go down, which sets us up well, if we have a $50 or call it strip pricing for longer, where we've taken our well cost and operating cost, et cetera, it gives us even that much more ability to continue to drill within cash flow and grow that production. Because that decline is coming down, it's very helpful for us.

[Dan E. McSpirit:]

Got it. And then as a follow up, you mentioned in your prepared remarks that infrastructure capital was coming into the Basin, whether that's the Hess deal or others. Under what valuation or multiple do you see this capital being put to work? I'm just asking in an effort to get a better handle on what to expect in terms of value for your own business.

[Michael H. Lou:]

Yeah, look, I don't have perfect visibility into all the data. But it seems like from what is kind of publicly disclosed, it looked like there was acquisitions that were done on a, call it, 10 times EBITDA multiple but off of a 17% or 18% EBITDA number which, if you start backing that into what kind of an EBITDA multiple on today's EBITDA would suggest more like a 16 times to 20 times multiple. As well as private equity money that came in at a very similar type valuation of, call it, 16 times to 20 times current EBITDA. But obviously, there's significant growth in those assets. We do feel like our infrastructure assets have a similar amount of growth potential and pretty visible growth potential based on where we know we're going to be drilling and where our infrastructure assets are going to be positioned. So that's where the most recent markers were.

[Dan E. McSpirit:]

Got it. Thanks again. Have a great day. Thanks.

[Thomas B. Nusz:]

Dan, thanks.

[Operator:]

Our next question comes from Brad Carpenter with Cantor Fitzgerald. Please proceed with your question.

[Brad Carpenter:]

Hey, good morning, everyone, and congrats on the quarter. Just a few quick ones from me and I apologize if I missed it in the prepared remarks. But it was good to see a little bit of hedging activity on 2016 production at reasonable levels, and I was curious how you guys think about hedging additional production as we head into year end? Should we be comfortable at the 16 strips at $51 now or would you like to see a little bit higher before layering on additional hedges?

[Michael H. Lou:]

Yeah. On the hedging side, we're going to continue to monitor kind of where we see it playing out. Typically, when we see big movements in prices over short periods of time, we try to stay a bit out of it, and then as it moderates a bit, we'll continue to look to layer in. We have been able to put in some good hedges into 2016 and we'll continue to look for kind of opportunistic times to be able to go back into the market and get a little bit more.

[Thomas B. Nusz:]

But I would say that with cost structure coming down the way that it has, what used to look like $60, looks like something maybe a bit little less than that. I don't know exactly at this point what that is whether it's $55 or $56, $57, but with the movement we've seen in cost structure relative to where we were before, it gives us a little bit more comfort and maybe pulling that down a bit or I mean we're kind of under hedged at this point. So I wouldn't be surprised to see us lay a little bit in somewhere in that $55 to $60 range.

[Brad Carpenter:]

Okay, great. That's very helpful. And then my second question, I'm a bit hesitant to ask, but I figure I might as well go ahead. You obviously have great liquidity 2H is supposed to cash flow positive and 2016 more or less neutral and on top of that you do have substantial inventory within your current footprint, but have you guys been looking at any potential acquisitions given all this either within the Williston or outside the Williston or are you not comfortable looking at acquisitions at this point in the cycle?

[Thomas B. Nusz:]

I think it's prudent to kind of see what's in the market at all times and first order for us is if you look in and around our core positions, there are opportunities to continue to core up, but at minimum I think you got to consider that or things that the ways that acquisitions not only from an NAV standpoint, from a balance sheet standpoint helps us out and then I think you got to look at that as well. So I think you always have to keep your head up and your eyes open.

[Brad Carpenter:]

Okay, great. I appreciate it and congrats again on the quarter.

[Thomas B. Nusz:]

Thanks.

[Operator:]

Our next question comes from Marshall Coltrain with Guggenheim Securities. Please go ahead with your question.

[Marshall R. Coltrain:]

Hey, guys. Good morning. Thanks for taking my call.

[Thomas B. Nusz:]

Good morning.

[Marshall R. Coltrain:]

Just wanted to get a little bit of color on the gas ratio moving forward, we saw it move up to about 12% this quarter from 11% in 1Q. Just wanted to see how you kind of see that developing moving forward and in the context of the increased production guide?

[Michael H. Lou:]

Overall, our gas rate kind of across our reserves is about 12%. There are certain areas that have a little bit more gas content, so like Wild Basin has slightly higher gas content. But overall kind of across our program it's going to be in that kind of 12% range.

[Marshall R. Coltrain:]

Great. And that's very helpful. Thank you.

[Operator:]

This concludes our question-and-answer session. I would like to turn the conference back over to Oasis Petroleum for closing remarks.

[Thomas B. Nusz:]

We're very pleased with how our organization has responded to a lower price environment and continue to focus on solid execution across the board. Some of that comes from the organizational planning and being prepared for the downturn. We feel we're very well-positioned to continue to deliver in a depressed price environment and maintain tremendous optionality for the future. Thanks for joining this on the call today.

[Operator:]

The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.