Chord Energy Corp (CHRD) 2015 Q2 法說會逐字稿

Good morning. My name is Katherine, 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.

(Operator Instructions)

Please note that this event is being recorded.

At this time I would 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.

Thank you, Katherine. Good morning, everyone. This is Michael Lou.

Today we're 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 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.

Thank you very much. Good morning.

Thank you very much for joining us today on our second-quarter 2015 earnings call. I am 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 planned to lower well costs and live within cash flow.

I'll go into more detail on these items momentarily, but first I would 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 $10.6 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 slick water completions in the core. About half of the costs savings came from service costs 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 is measured by EBITDA less CapEx and cash interest was about $103 million. We projected that we'd be close to break-even on this metric for the remainder of the year. I'm happy to report that during the second quarter, we were actually positive my 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 with six 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 have 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 have elected to delay 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 in if oil prices improve considerably, we are currently planning on spending about $670 million on CapEx in 2015.

We have continued to experience out performance 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 out performance expected continued success in 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 46,000 to 49,000 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, we put together -- 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 pulled different levers or realized a different oil price.

While WTI topped our budget in the second quarter, we are back at levels similar to our original budget. The team has done a great job managing key drivers to cash flow. From production and capital costs, to LOE and differentials. We have positioned the Company well and in a less than stellar macro environment.

With that I would like to turn the call over to Taylor to go into a little more detail.

Thanks, Tommy. First I would like to remind everybody 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 825 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 eight to 10 years of inventory.

Not only does operating the core allow us to drill the highest EUR wells, it allows to us to capture efficiencies through high-well density pad operations and reduce costs through infrastructure, which you are seeing play out in both our well costs and LOE. Our focus in 2015 has remained on capital preservation, and solid operational execution, with an eye towards remaining flexible and opportunistic in the very volatile environment.

During the first quarter call, we talked about dropping from five rigs down to four as a result of efficiency gains, to moderate spending in the 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. And 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 have 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 out performance that when 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 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, and five wells to our first bench high intensity population bringing the total to nine. In Alger the well counts 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 costs 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's 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, and 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 slick water-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 slick water completions using ceramic, and both are materially outperforming the type curve for the area.

We believe we can complete the slick water wells for around $7 million to $7.5 million, which produces IRR's 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 at 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, slick water 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 costs. We plan on completing some all sand slick water 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.

Thank you, 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 19% 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 pick-up 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 million in EBITDA for OMS in 2015.

We have 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 ultimately be constructed next year.

On past calls, and in other discussions many of you have asked about our opportunities to monetize OMS. Both 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 potential monetize the assets and are exploring numerous options, and we'll give you an update when we have something more definitive.

As we have 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 Petroleum 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 the fall redetermination should not have a material impact on this number. Even though we expect things 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 have continued to see great pricing out of the Williston Basin. We were below our guidance range of $6.50 and $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 be $5.50 and $6.50 per barrel as we continue to benefit from flattening production and additional take-away 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 additional hedges for both the second halving of 2015 and in 2016. We have 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 security half of 2016.

On the G&A front we have managed costs down to all-time lows in the second quarter as 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 totalled $23.71 per BOE in the second quarter.

Taylor spoke about our efforts to remain flexible in the down-turn. You have 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&A costs.

For the second quarter and through the remainder of 2015, we expect to be cash flow positive, while continuing to grow annual productions 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 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 at 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 eight 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. The 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 of the hard work of our employees, we have 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 Katherine for questions.

(Operator Instructions)

Our first questions come from Neal Dingmann with SunTrust. Please go ahead with your question.

Good morning, guys.

Good morning, Neal.

Just a quick question. Liquidity-wise you are doing very good, but you have got obviously a big benefit when I look at the cash basis, or even the potential of the Oasis Midstream Services or all that infrastructure development you all have. I'm looking at slides 13 and 14. Your thoughts any time soon or down the line about potentially monetizing either of those?

On the Midstream Business, we have looked at a number of options, and like we said in the prepared remarks, we have got a lot of things that we're evaluating now. Obviously there are a number of options.

We have 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 the near future, but well give you a little bit more when we get something a little bit more definitive.

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 those improving economics with the higher recoveries and lower cost. Going forward, is that higher intensity completion, is that what we should assume? How should we think about that versus that base completion economics?

Sure. As we've 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 will be 65% of our activity. If we continue to see this type of performance that we have seen in these wells, we'll push that up closer to 100% in 2016.

Got it. Thank you.

Thanks, Neal.

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

Good morning. Maybe a question for Michael, the comments surrounding flat to moderate production growth in 2016 and generating cash. 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?

Steve, on the D&C side, what we have said about 2016, and this kind of an environment, we called it around $400 million, or just under $400 million. 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.

Thanks for that. 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 if companies focused on their main areas it may be hard for the non-op partners to say no. What's been your experience lately with that?

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

All right. Great. Thanks, guys.

Thanks.

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

Thanks. Good morning. Congrats on the solid update.

Thanks, Mike.

I 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. 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?

As we talked about, we're at $7.8 million for slick water in the core right now. We continue to see reductions, and that's really going to be both on efficiency side and on service costs. 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 on the slick water versus the high-volume proppant, how should we think about how you're evaluating between those two options currently? (Inaudible) higher-volume proppant to the slick water is also what I'm trying to think about.

Michael, what we're doing is testing each of those high-intensity completions across the position and the core. We have got a mix in Indian Hills and Alger, and we'll do the same thing in Wild Basin. And 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.

By the end of this year, we're going to be in a better position to make that call, and then you will see us start to modify the completion design around that data.

I think it gets driven by the rocks, right, 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.

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

Yes.

All right. And then 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, the GAAP would be fully covered by the midstream monetization? Was that the intention of that comment? I just wanted to make sure.

That's exactly right, any midstream monetization, of the ones we're looking at, can cover that GAAP on infrastructure spend, which will be just over $100 million, as well as a little bit of other non D&C capital.

And then the E&P capital itself would be fully funded internally?

Correct.

And as we think about the midstream monetization avenues you are looking at, 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 provides some benefit on LOE, as well as some benefit on capital, but given that we like to keep control, obviously most of that is going to stay within Oasis. We'll have to see at this point, we will still continue to consolidate, et cetera, on a similar basis. And any smaller minority partner, it would come out below the line.

Below the line, okay. That's very helpful. Appreciate it. Congratulations again.

Thanks.

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

Looking at some of the in-hands completions for slick water and high profit 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 there's an explanation of why that may be the case?

I don't know that we necessarily have seen, a higher pick-up at tighter spacing, but those really are the two things we have to understand. One is, what is the uplift? As we do the high intensity completions, very importantly, what is the uplift when you do it in spacing? Drilling out a full DSU and doing all 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 we think we have a pretty good answer right now, 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.

Is it safe to say that at tighter spacing, you have not seen any deterioration or more interference?

At this point, the well results continue to show consistent uplift. And so it would not indicate interference.

All right. Great. Thanks.

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

Good morning. 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 Alger, how repeatable do you think those results are? Or within that core area, do you think there's potential variability across that position?

Rob, based on what we're seeing right now, and if you look on 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 see pretty consistent uplifts, and we're feeling good that you are going to see that same type of performance across, not only the whole core position, but if you get into areas like Montana, really seeing great uplift, as well.

Okay. As it relates to slide 10, with your production guidance, you obviously brought the low end up 6% or 7% this quarter. To the extent that wells continue to perform, tracking the million-plus barrel range at Indian Hills, and call it 850,000 or 900,000 barrels at Alger.

How much head room would you have on future production guidance? Maybe it addresses your growth comment, Michael, based on additional production history in these areas.

Ron, we have actually factored in that uplift in the high intensity wells, we modeled 25% to 30% uplift. 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 if that EUR uplift can be greater than 10% to 30%?

If you ask our reservoir engineers, they'll tell me five to 10 years, but by the end of this year and as we get a little more into the next year, we're going to get more comfortable. And I think that clearly it's at least the 10%, the 30% is feeling pretty good.

But we have 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 have to pull the tools together to make a final determination.

Okay. What's even more impressive about the production growth is it's occurring even as you continue to build your uncompleted well inventory. I know you had originally entered the year at 70% to 75%, planned 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 75%, we're likely to end up into the year in the 80%s, maybe kind of mid-80%s range. As we talked about, we've about been a lot more efficient on the drilling side, so that pace has resulted in a few more wells piling up in that waiting-on-completion inventory.

Now, relative to where we are at mid-year, we're at 93% and we'll work that down obviously from now until the end of the year, being in the mid-80%s.

Perfect. One last one, Michael, on the midstream assets. You have gone from 40% to 65% or 68% of your wells going through the system. I think we talked about potentially getting to 75% or 80% through the system, by the end of next year. 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 million to $55 million today, 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? 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, you know, production, will start in the latter part of next year. It does take a little while to get fully up to speed. 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 million 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 are talking about, $60 million to $70 million-ish.

Thanks. Just looking for the color to try to apply how the KMI and Hess deals would look. I appreciate it. I 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, everybody. Just looking at 2016 forward, 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?

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. We'll be likely at something more like a three-rig scenario, and you are completing wells at about six a month, a little faster than you are drilling. So you might pull that down by, you know, the 20 range, but it's still early for us working on that program for next year.

Great. 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 that the high intensity completion potentially unlocking more lower Three Forks potential across your entire acreage position, not in the core? Or is it too early to tell?

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 have 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% sand slick water test in the core, will that $0.5 million less than the $7.8 million with 100% ceramic?

Yes, that's correct.

Great. Thank you.

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

Good morning, guys.

Hello, Dave.

One last one on the decks. Can you break out for us when you think of your $7.8 million well costs, what percent of that is drilling and what percent of that is completion, 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 order of $2.5 million, or something like that, of the $7.8 million.

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 it doesn't expire for quite some time but any thoughts or color you can provide on that? If I missed that early in the call, I apologize.

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 higher -- 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 remain strong.

Outstanding. Thanks for that clarification. Sorry if it was duplicated.

Then last one, just in terms of productivity improvements that you guys have been seeing from slick water and from hot proppant. What are the other things you 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?

Dave, we continue to work at really on both sides, the completion side of the business to improve performance. And so there's a number of things we're looking at. Stages are definitely one of those, and so we have 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's some things that we think could make an impact on that side, but it's still too early to talk.

Okay. Appreciate the color. Sorry for pushing on something you are 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.

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?

Dan, you know, 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. By the end of 2016, continued to go down.

Which sets us up well to -- if we have a $50 or call it strip pricing for longer, if where we have taken our well costs and operating costs, 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.

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 asking in an effort to get a better handle on what to expect in terms of value for your own business.

You know, look, I don't have perfect visibility into all the data. But it seems like from what is 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 to 20 times multiple.

As well as private equity money that came in at a 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 positioned. That's where the most recent markers were.

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

Dan, thanks.

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

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. 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 2016 strips at about $51 now, or would you like to see a little bit higher before layering on additional hedges?

On the hedging side, we are 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 opportunistic times to be able to go back into the market and get a little bit more.

But I would say with cost structure coming down the way it has, what used to look like $60 looks like something a bit less than that. I don't know exactly at this point what that is, whether it's $55 or $56, $57. With the movement we have 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.

We're kind of under-hedged at this point, so I wouldn't be surprised to see us lay a little bit it 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 I might as well go ahead. You obviously have great liquidity, 2H is supposed to be cash flow positive and 2016 more or less neutral.

On top of that you do have substantial inventory within your current footprint, but have you 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 see what's in the market at all times. And you know, first order for us is, if you look in and around our core positions, if there are opportunities to continue to core-up, at a minimum I think you have got to consider that. Or things that, if there are ways that acquisitions not only from an NAB standpoint, from a balance sheet standpoint, help us out, then you have to look at that as well. I think you always have to keep your head up and your eyes open.

Okay. Great. I appreciate it. Congrats, again, on the quarter.

Thanks.

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

I 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. I wanted to see how you 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 12% range.

Great. That's very helpful. Thank you.

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 or 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.

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