Morning. My name is Catherine and I will be your conference operator today. At this time, I'd like to welcome everyone to the 2nd quarter 20 15 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 Liu, Oasis Petroleum's CFO to begin the conference. Thank you, Mr. Liu. You may begin your conference.
Thank you, Catherine. Good morning, everyone. This is Michael Liu. Today, we are reporting our Q2 2015 financial and operational 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 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 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 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.
Good morning and thank you for joining us today on our Q2 2015 earnings call. I'm pleased to announce that we have 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 costs 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 will recall at the end of 2014 well costs for our high intensity completions were coming in around $10,600,000 and our goal was to decrease those to an average of $9,500,000 this year.
During the Q1, we were able to drive those costs down in the $9,000,000 range and we're now around $7,800,000 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 and will likely remain if we pick up the pace of activity. During the Q1, cash flow outspend as measured by EBITDA less CapEx and cash interest was about $103,000,000 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 Q2, we were actually positive by about $36,000,000 and we continue to expect to be neutral or more likely positive for the second half of twenty fifteen. For the quarter, we completed 21 gross operated wells in line with what we said we would do at 6 to 8 wells per month.
We expect to be at the low end of that monthly range for the remainder of the year completing about 6 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 $35,000,000 While we still have a board approved budget of $705,000,000 that gives us the flexibility to slot additional wells in if oil prices improve considerably. We're currently planning on spending about $670,000,000 on CapEx in 2015. We've continued to experience outperformance from our high intensity wells compared to what we originally modeled. Additionally, we have improved 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 to 50,000 barrels of oil equivalent a day, up from the to 49 from May. With the increase in production guidance in 2015, we're still forecasting relatively flat production throughout 20 16 versus the Q4 of 2015, which is about 5% higher than originally anticipated. As a reminder to everyone, we put together our 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 realize a different oil price. While WTI topped our budget in the Q2, we are 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've 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.
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 has about 8 25 locations, 701 of which are located in the Middle Bakken or the first bench of the Three Forks. At the current pace of completion, this equates to 8 to 10 years of inventory. Not only does operating 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 Q1 call, we talked about dropping from 5 rigs down to 4 as a result of efficiency gains to moderate spending in this low commodity environment. Likewise, in the Q2, we realized the opportunity to further reduce rig count from 4 to 3 as a result of higher efficiencies on the drilling side of the business. And we now plan to run 3 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 7 in Alger and 11 in Indian Hills, plus we had one completion in Montana and 2 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 is 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 9, you can see the updated outperformance relative to our type curves now averages between 34% and
Yes. Excuse me. This is the operator. We're having a private conversation. May I have your first and last name?
You are now rejoining the main conference.
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 $8,000,000 for high intensity completions and $7,000,000 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 costs to come down and for additional efficiency gains 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 $7,000,000 to $7,500,000 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 5 of our presentation, you can see that total costs for our 2 high intensity stock completions, slickwater and high volume proppant are now coming in at $7,800,000 $8,300,000 respectively, representing a 26 percent improvement to our year end 2014 cost. We plan on completing some all sand slickwater tests in the core during the second half of twenty fifteen, which has the potential to save another $500,000 versus current well cost. With that, I'll turn the call over to Michael.
Thanks, Taylor. To add to Taylor's comments 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 2nd 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 19% below our 2014 LOE per BOE levels coming in at $8.26 during the Q2.
As you know, we break out OMS as its own segment and we reported EBITDA of $10,700,000 in the Q1 of 2015. During the Q2, we grew OMS EBITDA to $17,400,000 primarily due to more saltwater volumes and a pickup in activity in our freshwater distribution business. While we do not expect to keep freshwater at these heightened levels for the remainder of the year, we're now targeting north of $55,000,000 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 2nd quarter with only $155,000,000 drawn on our $1,700,000,000 borrowing base. We have $1,500,000,000 of elected commitments and we expect that the fall redetermination should not have a material impact on this number. Even though we expect banks to run a 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 to $7.50 per barrel in the 2nd quarter coming in at $5.90 per barrel off of WTI. We expect the 3rd quarter to range between $5.50 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 3rd quarter in natural gas price realizations. We did see some oil price improvement in the 2nd quarter in WTI and we were able to layer in some additional hedges for both the second half of twenty fifteen and in 2016.
We've increased our position to 28 1,000 barrels of oil per day at an average floor of $75.61 in the second half of twenty fifteen to 8,000 barrels of oil per day at $63.20 in the first half of twenty sixteen and 3,000 barrels of oil per day at $6,394,000 in the second half of twenty sixteen. On the G and A front, we have continued to manage costs down to all time lows in the Q2. As cash G and 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 and A are down 25% to 2014 levels and totaled 23.71 dollars per BOE in the Q2. 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 costs and G and A costs. For the Q2 and through the remainder of 2015, we expect to be cash flow positive while continuing to grow annual production 7% to 9% year over year. As we look into 2016, we continue to remain flexible, especially given the uncertainty of the oil price environment. In 20 16 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 our 8 to 10 years of core inventory. Finally, we mentioned that the 2nd 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 and A costs, we expect to be able to continue to improve our balance sheet and capital structure in the second half of twenty fifteen, 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.
Our first question comes from Neal Dingmann with SunTrust. Please go ahead with your question.
Good morning, guys. Good morning, Neil.
Hey, just a quick question.
I mean, you guys obviously liquidity wise are doing very good. But you've got obviously big benefit when I look at the probably the cash basis or even potential of the Oasis Midstream Services or all that infrastructure development you all 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?
Yes. 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 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 bit more definitive.
Okay. And then just lastly one follow-up on that Slide 11. Certainly was the case this quarter and it's evident by stock price today about this improving economics with the higher recoveries and lower cost. I mean going forward, I mean is that higher intensity completion is that what we should kind of assume? I mean I guess how should we think about that versus that base completion economics?
Sure. So if you as we've talked about, we've continued to ramp up the percentage of our completions that are high intensity, 20% last year. First half, it was 60%. Second half, it will 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 100% in 2016.
Got it. Thank you.
Thanks, Neal.
Our next question comes from Steve Berman with Canaccord. Please go ahead with your question.
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?
And what are you thinking for spending next year based on comments you made earlier?
Yes, Steve, on the D and C side, what we've said about 2016 in this kind of an environment, kind of called it around $400,000,000 or just under $400,000,000 I think that with where costs are etcetera, 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 $350,000,000 to $400,000,000 range on the D and C side.
Okay. Thanks for that. And then just one follow-up. What are you seeing from your non operated working interest partners? I know there's been a lot 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?
So it's been a bit of a mix. Some 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.
All right. Great. Thanks guys. Thanks.
Our next question comes from Michael Hall with Heikkinen Energy Advisors. Please go ahead with your question.
Thanks. Good morning and congrats on the solid update. Thanks, Mike. 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 do you have what would you say maybe a target well cost might be for the first or the beginning of 2016 or by year end 2015 on the high intensity completions in the core?
So we're as we talked about, we're at 7.8 for slickwater in the core right now. 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.
Okay. And just on the slickwater versus the high volume proppant, I guess, how should we think about how you're evaluating between those two options currently?
So it's I think we can
take higher volume proppant to the slickwater, I guess, is also what I'm trying to think about.
Yes. Really, Michael, what we're 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 Algerian. We'll do the same thing in Wild Basin. And then based on the success of 1 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.
But I think it gets driven by the rocks, right? And some 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.
Okay. So it's not like you pick 1, it's more custom fitting it to the individual area that you're active in?
Yes.
Okay. And then the comments around 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 GAAP would be fully covered by the midstream monetization? Is that Was that the intention of that comment?
Just want to make sure.
Yes. No, I think that's exactly right that any midstream monetization, I think that of the ones that we're looking at can cover that gap on infrastructure spend, which will be just over $100,000,000 as well as a little bit of other non D and C capital.
Okay. And then the E and P capital itself would be fully funded internally? Correct. Okay. And
monetization
avenues you're looking at, what might how should we think about the potential for that to change cost structure down the road?
Yes, it depends on how we 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 like to keep control, obviously, most of that's going to stay within Oasis. So what we'll have to see at this point, we'll still continue to consolidate etcetera on a similar basis and any smaller minority partner it would come out below the line.
Below the line. Okay. It's very helpful. Appreciate it guys. Congrats again.
Thanks.
Our next question comes from Biju Perincheril of Susquehanna. Please go ahead with your question.
Hi, good morning.
Good morning.
I mean 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 if what is there an explanation of why that may be the case?
I don't know that we've necessarily seen a higher pickup at tighter spacing, but that those really are the 2 things we've got to understand. 1 is, what is the uplift as 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 the things we'll continue to work on is spacing with the high intensity fracs. And it's we think we've got a pretty good answer right now.
We'll continue to perfect that as we go. And every year, you'll see us modify that spacing plan a bit, but
we think we're in pretty good
shape. Deterioration or more interference?
Okay. Is it fair to say that, at the tighter spacing you haven't seen any deterioration or more interference?
At this point, the well results continue to show consistent uplift and so it wouldn't indicate interference.
All right. Great. Thanks.
Our next question comes from Ron Mills with Johnson Rice. Please go ahead with your question.
Good morning. Hey, guys. With another 3 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 across Indian Hills and Alger, how repeatable do you think those results are? Or within that core area, do you think is potential variability across that position?
So, Ron, based on what we're seeing right now and we've got a 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 uplifts. 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. Okay.
And as it relates to slide 10 and just with your production guidance, you obviously brought the low end up 6% or 7% this quarter. But to the extent that wells continue to perform, tracking the 1,000,000 plus barrel range at Indian Hills and call it 850,000 or 900,000 barrels at Alger, How much headroom would you have on future production guidance? Maybe it addresses your growth comment, Michael, based on additional production history in these areas?
So, Ram, 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.
Okay. And then from a relative just because of the way the wells have held up, you have the higher initial productivity and you talk about potential EUR uplifts of 10% to 30%. How much more history do you would you like to see before you feel more comfortable with that EUR uplift can be greater than that 10% to 30%?
So if you ask our reservoir engineers, they'll tell me 5 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, the 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, subsurface analysis and we got to pull all those tools together to make a final determination.
Okay. And then what seemed more impressive about the production growth as it's occurring as even as you continue to build your uncompleted well inventory. I know you had originally planned entered the year at 70 to 75, plan to exit around that same level, but I think you have more uncompleted wells in hand now. Where do you now expect to end the year in terms of uncompleted wells?
We're probably going to build that backlog of completions a bit. We entered 70 to 70 5. We're likely to end up into 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 in a few more wells piling up in that waiting on completion inventory.
Now relative to where we are at midyear, we're at 93% and we'll work that down obviously from now until end of the year being in the mid-80s.
Perfect. And one last one just Michael on the midstream assets. I know you have gone from 40% to 65% or 68% of your wells going through the system. I think 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 you just look at that EBITDA run rate of $50,000,000 to $55,000,000 today is on the existing OMS assets is that something that can grow on the order of to $60,000,000 $65,000,000 by the end of next year and then Wild Basin can add $40,000,000 to $60,000,000 in 2017? Or how do we think about the EBITDA growth potential?
Look, I think that your numbers are kind of generally in the right direction. The EBITDA like you said of 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% 80% connected or running through our pipelines on saltwater disposal. Hopefully, it's kind of in that range that you're talking about $60,000,000 to $70 ish million.
Thanks. Just looking for the color to try to apply how the KMI and Hess deals would look. But I appreciate it and look forward to next quarter.
Thanks, Ron.
Our next question comes from Gail Nicholson with KLR Group. Please go ahead with your question.
Good morning, everyone. Just kind of looking at 16.4, at what point do you guys start considering maybe further scaling back the drilling activity and putting more capital towards the completion front in order to work down that backlog of wells down?
So I think as Mike kind of 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. We'll be likely at something more like a 3 rig scenario and you're completing wells at 6 about 6 a month a little faster than you're drilling. So might pull that down by kind of 20 range, but still early for us working on that program for next year.
Okay, great. And then just kind of looking at the high intensity completions, especially in the Lower Three Forks Bed 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 versus just not in the core? Or is it kind of too early to tell?
Still a little early to tell. We're doing half of our completions in the Three Forks and were 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 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.
Just for clarification, the 100 percent sand slickwater test in the core, will that be $500,000 less than the $7,800,000 with 100 percent ceramic?
Yes, that's correct.
Okay, great. Thank you.
Our next question comes from Dave Kinstler with Simmons and Company. Please go ahead with your question.
Good morning, guys.
Hey, Dave.
One last one on the DUCs. Can you just break out for us when you think of your $7,800,000 well cost, what percent of that is drilling? What percent of that is completion just in terms of thinking about working that inventory down in 2016 potentially and the costs associated with that?
So it's about 30% of that is drilling on the order of $2,500,000 something like that of the 7.8
percent. Okay. And then if we think about it in terms of if the sand actually works in terms of 100% sand that $500,000 would apply directly to the completion component?
Correct.
Yes.
Okay. And then just one on the credit facility. Obviously, ample liquidity, you set your facility below what was the approved level. Any early discussions? 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. Yes, Dave.
What we said about the credit facility is that we do have the 1 borrowing base, 1.5 is the committed level. We do feel like that that's not going to materially change that 1.5 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 higher better differentials, better LOE and well costs, etcetera.
So all the work that we've been doing for the last 6 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 remains strong.
Outstanding. Thanks for that clarification. Sorry if it was duplicative. 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 front that might also increase recoveries per well?
Dave, we continue to work it 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.
Okay. I appreciate the color and sorry for pushing on something you're not ready to talk about yet.
Thanks, Dave.
Our next question comes from Dan McSpirit with BMO Capital Markets. Please go ahead with your question.
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 midyear and at year end in light of the change in the applied completion technique?
Hey, Dan, what we talked about on previous calls is that kind of at the beginning of this year, we were kind of 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, continued to go down, which sets us up well to if we have a $50 or call it strip pricing for longer, where we've taken our well costs and operating costs, etcetera, 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.
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.
Yes. Look, I don't have perfect visibility into kind of 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 would suggest more like a 16 to 20 times multiple, as well as private equity money that came in at a very similar type valuation of call it 16 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 assets are going to be positioned. So that's kind of where the most recent markers were.
Got it. Thanks again. Have a great day. Thanks.
Dan, thanks.
Our next question comes from Brad Carpenter with Cantor Fitzgerald. Please go ahead with your question.
Hey, good morning everyone and congrats on the quarter.
Just a few quick ones
for 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. Would you be comfortable if the 16 strips at $51 now? Or would you like to see a little bit higher before layering on additional hedges?
Yes. 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 do we are we have been able to put in some good hedges into 16 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.
But I would say that with cost structure coming down the way that it has, what used to look like $60,000,000 looks like something maybe a bit less than that. I don't know exactly at this point what that is, whether it's $55,000,000 or $56,000,000 $57,000,000 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 SLA a little bit in somewhere in that 55 to 60 range.
Okay, great. That's very helpful. And then my second question, I'm a bit hesitant to ask, but I figure might as well go ahead. You obviously have great liquidity. 2H is supposed to be cash flow 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?
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, if there are opportunities to continue to core up, but at a minimum, I think you got to consider that or things that there are ways that acquisitions not only from an NAV standpoint, from a balance sheet standpoint help us out, 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.
Okay, great. I appreciate it and congrats again on the quarter.
Thanks.
Our next question comes from Marshall Coltrane with Guggenheim Securities. Please go ahead with your question.
Hey guys, good morning. Thanks for taking my call. 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?
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 a slightly higher gas content. But overall, kind of across our program, it's going to be in that kind of 12% range.
This concludes our question and answer session. I would like to turn the conference back over to Oasis Petroleum for closing remarks.
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 us on the call today.