Chord Energy Corp (CHRD) 2017 Q3 法說會逐字稿

Good morning. My name is Andrew and I will be your conference operator today. At this time I'd like to welcome everyone to the third quarter 2017 earnings release and operations update for Oasis Petroleum. (Operator Instructions.] Please note this event is being recorded.

I will now 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, Andrew. Good morning to everyone. This is Michael Lou. Today we are reporting our third quarter 2017 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 the team.

Please be advised that our remarks on both Oasis Petroleum and Oasis Midstream Partners, 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, our quarterly reports on Form 10-Q and on the Oasis Midstream Partners Form S-1. 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 of adjusted EBITDA to the applicable GAAP measures can be found in our earnings release and on our website. We will also reference our current 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 our call. It was a milestone quarter for Oasis as the team successfully increased E&P activity into an environment of improving oil prices and differentials, activated our second internal frac spread, OWS 2, bringing the majority of our completion activity in-house and completed the IPO of Oasis Midstream Partners, or OMP, which allows us to invest midstream capital in a more efficient manner and manage our product takeaway capacity in Wild Basin. We completed 24 gross or 15.1 net wells in the third quarter compared to 28 gross and 20.5 net in all of the first half of the year as we brought on OWS 2 during the quarter.

Production followed suit with the increased completion activity, as we averaged 66,100 BOEs per day in the third quarter, slightly above the midpoint of our 65,000 to 67,000 BOE per day guidance. Production increased 7% quarter-over-quarter as we executed within our plan, even with some in-basin processing issues. We're on track to hit our projected 2017 exit rate of 72,000 BOEs per day as October volumes exceeded 69,000 BOEs per day, which is all consistent with the operational plan we laid out at the beginning of the year.

We started working our 2018 plan that we will announce just after the first of the year but still expect the output of that plan to result in our projected 2018 exit rate of over 83,000 BOEs per day while living within our upstream cash flow, generating attractive returns and continuing to focus on capital and operating efficiencies.

OWS 2 returned to service during the quarter and has been an important tool for us in both optimizing operations and controlling stimulation costs. While we have seen higher stimulation costs in the basin, OWS remains an attractive way to mitigate the full impact of these increases. Other D&C costs have obviously increased throughout the year as well, but at this point it feels like service costs have started to level out a bit.

The commodity price volatility over the last 3 years has affected every operator's ability to manage their capital program and cash flows. And from our side, that has underscored the importance of programmatic hedging coupled with an ability to be opportunistic in stronger markets. Michael will talk more about this, but today's hedge book affords us a higher level of certainty and protection for our 2018 capital plan at an attractive price point while helping to preserve the balance sheet and capital efficiency. Lower differentials are having a meaningful impact as well.

We continue to be focused on capital efficiency that creates near- and long-term value growth. Oasis was one of, if not the first, mid-cap E&P companies to become cash flow positive during the downturn, and it's been a key focus of our company during this challenging cycle in our industry.

On a cumulative basis, our business has been cash flow neutral on capital spending of around $1.5 billion total since the beginning of 2015, excluding opportunistic acquisitions. We also continue to expect to be cash flow neutral on E&P spending during the remainder of 2017.

In late September we successfully completed the initial public offering of Oasis Midstream, a master limited partnership focused on the operation of our strategic infrastructure in and around our large contiguous operated blocks in the Williston Basin. The new public entity allows us to better recognize the value of our infrastructure investments and provides access to a true midstream cost of capital as we look to take advantage of new opportunities and expand that business overall.

One such opportunity is in increasing our gas processing capacity in OMP, which we formally announced last night. It's a project our team has been evaluating for a while and investing the seed capital in to provide us an attractive option. We have now made the decision to proceed with it. I'll let Taylor and Michael talk more about the logic and the details for this second plant, but it's a significant project for both OAS and OMP. This plant has been assigned to the Bighorn DevCo, which is 100% owned by OMP. The project offers the partnership an attractive return and a path to additional upside while mitigating capital spend at OAS and ensuring quality of service and availability of additional processing capacity as we grow our midstream business.

It's an exciting time for Oasis as we wrap up 2017 and continue to drive operational improvements across the company. With that, I'll turn the call over to Taylor.

Thanks, Tommy. I want to commend the team for a great quarter, as we picked up the pace in the second half of 2017 and remain on pace to execute on our plan for the year. As Tommy mentioned, we completed a total of 24 gross wells in the quarter with about 60% of our completions being 10 million pounds or larger. If you turn to Page 10 of our slide deck, you can see that we continue to have success in Wild Basin from these larger jobs, especially in the Bakken Formation. As a result, we have moved to all 10-million-pound or larger fracs for Bakken wells in this area.

In the Three Forks, the 10-million-pound and 4-million-pound jobs don't show as much separation, so we continue to test wells with loading between 4 million and 10 million pounds with a few larger tests as well.

Additionally, we now have more meaningful production data on the wells we completed in Indian Hills, and again, the larger jobs continue to perform well. You can see on Page 9 of our presentation that we have added the new Indian Hills wells to our core ex Wild Basin type curve plots. As the wells continue to produce, we are beginning to see real separation between the base 4-million-pound jobs and the 2-million-pound jobs in this area. The wells with larger frac jobs in this area come on with a higher water count, but dewater in the first few months of production and then begin to outperform their counterparts. We are really excited by the results we are seeing from the larger jobs.

The majority of our completions this quarter were in Wild Basin and about 20% were in Red Bank, 2 of which were 10-million-pound tests. These were our first high-proppant and slick water jobs in Red Bank, and we're excited to see how they perform in the coming months. Peer data in the area is encouraging, and we have a few more big jobs in Red Bank that we expect to complete this year. We should have meaningful data on these well tests by mid to late next year.

In addition to the larger jobs, we continue to see the test spacing across the position with the focus on the core at the moment. We have tested through a combination of Bakken and Three Forks wells, spacing as high as 16 wells per spacing unit and as low as 11 wells per spacing unit. Based on the results so far, it looks like spacing at the upper end of the range may be too tight. At the mid to low spacing levels, the wells continue to perform in line with expectations. Remember that our core area inventory is based on 11- to 13-well spacing. We will continue testing and plan to report updated inventory in spacing in our year-end report and call. We added a fifth rig this quarter and are currently running 2 in Wild Basin, 2 in Alger, and 1 in Indian Hills.

The frac market in the third quarter tightened a bit and as a result, we saw costs increase in the quarter as older contracts rolled off. Our costs for a 4-million-pound and 10-million-pound 50-stage slick water well is now $6.8 million and $7.7 million, respectively, reflecting a 5% increase over last quarter. Going forward, we expect to offset further cost increases through OWS now that we have 2 frac fleets working internally.

Our performance on the midstream side of the business was good in the quarter and for the year in general. Our Wild Basin Gas Plant run times and process volumes continued to increase as we have brought on more wells during the quarter. We averaged throughput of about 60 million cubic feet per day for the third quarter. As we sit today, we're actually producing more than the plant's 80 million-a-day design capacity and are moving the excess gas through offloads with third parties.

As a result of bigger fracs outperforming our expectations on both oil and gas, combined with the general increase in GORs as seen on Slide 4 in our deck, both in the overall basin and in McKenzie County and Wild Basin, we have made the decision to build a second 200-million-a-day gas plant in Wild Basin. We expect the plant to come online at the end of 2018. We have some temporary processing capacity coming online shortly that is expected to fill in the gap as Oasis continues to grow gas volumes above the current 80-million-a-day processing capacity. Thus far we have spent about $67 million through October on the project. We are excited to partner with OMP on this project as it is developed.

With that, I'll now hand the call over to Michael to discuss the specifics of the assignment.

Thanks, Taylor. Overall, Oasis had an extremely successful third quarter, which sets us up for continued success in 2018. Despite some road closures due to weather and gas processing constraints in the basin in the third quarter, our team was able to deliver strong oil production growth and EBITDA growth.

As Taylor mentioned, we believe that the assignment of the second gas plant to OMP is strategic both at Oasis Petroleum and at OMP, with both entities significantly benefiting from the assignment. Oasis Petroleum will free up capital to fund upstream development on significantly higher-return E&P assets and maintain a stronger balance sheet in the path of lower leverage.

OMP captures a highly economic project that is already permitted, designed and under construction, importantly at a build cost. This will allow OMP to both grow distribution coverage more quickly while also lengthening the tangible runway of its 20% annual distribution growth. With the help of temporary processing capacity about to come online, the project should be neutral to positive to OMP's discretionary cash flow per unit for the next year and highly accretive thereafter.

The plant has been assigned to Bighorn DevCo, which is 100% owned by OMP, and OMP reimbursed Oasis Petroleum for all capital spent to date, which as Taylor said, amounts to about $67 million. OMP will be responsible for all capital necessary to be spent on the plant going forward and OMP will benefit from a strong anchored project as well as any upside. The total cost of the project is estimated to be around $140 million, with the remaining capital being spent over the next 5 quarters. OMP will fund the remainder of Gas Plant 2 under its $200 million revolver. At these build cost levels, OMP should realize solid returns in line with our historical build multiples of 4x to 5x while still being able to manage leverage within the goal of 2x debt to EBITDA.

Year-to-date E&P capital expenditures of $342 million are in line with our budget and we expect infrastructure capital, excluding the new project, to be in line with our budget as well. We still expect full-year capital expenditures to be around $620 million when adjusted for the new gas plant and some small acquisitions done earlier in the year.

We cannot stress the importance of the symbiotic relationship between Oasis and OMP. The IPO of OMP in the third quarter allows for us to continue to significantly grow our E&P business within cash flow and fund strong returning midstream assets with the appropriate capital structure as well.

Tommy and Taylor mentioned earlier that we are on track to meet our 2017 exit rate of 72,000 barrels of oil equivalent per day as well as on track for our 2018 exit rate of 83 MBOE per day or higher, especially with increasing gas rates.

While we continue to watch realized oil price, well costs and well productivity before coming out with a full plan in 2018, given the strength of the current oil strip, we currently see being able to hit our 15% growth target next year while generating positive free cash flow on the E&P side of the business. Given our strong hedge book, we have partially locked in our financial capability to execute this plan next year and our ability to withstand future fluctuations in commodity prices.

Financial results improved markedly in the quarter, aided by improved differentials in the basin and our ability to access better end markets. The Dakota Access Pipeline, or DAPL, has continued to make a significant impact on basinwide differentials. We have seen differentials tighten from around $3.50 in the second quarter to under $2.00 per barrel in the third quarter.

Recently we had some in-basin spot sales in early fourth quarter flat to WTI. We expect future run rate differentials to be around $2.00 per barrel compared to about $5.00 this time last year. When you think about our 2016 year-end well inventory, this improvement in differential brings a significant portion of our extended core inventory into our core inventory as defined by breakeven below $40 WTI, lengthening our already robust core inventory.

Continuing to focus on capital efficiency, lease operating expense per BOE improved slightly, driven by increased production volumes and more normalized workover levels. Reflecting year-to-date actuals, we have revised our full-year guidance to $7.50 to $7.70 per BOE.

As a result of our efforts to take advantage of long-haul pipe capacity and improved pricing further downstream, MT&G increased slightly versus the second quarter but was more than offset by significantly improved differentials.

I want to close by reiterating our focus on strategic growth while also managing our balance sheet. The continued improvements in the performance of our wells and the depth of our core inventory has led to continued capital-efficient growth in 2017 and sets us up to continue that growth in 2018 while generating positive free cash flow on the E&P side of the business. We will continue to focus on financial discipline, capital efficiency and shareholder returns. Congratulations to our team, who have worked tirelessly this quarter to execute on the plan, deliver strong EBITDA, demonstrating rapid deleveraging capacity, successfully completing the OMP IPO and setting us up for strong production growth while generating free cash flow into 2018 and beyond.

With that, I'll turn the call back over to Andrew for questions.

[Operator Instructions.] The first question comes from Neal Dingmann of SunTrust. Please go ahead.

Tommy, for you or Taylor, just my question is, I think, looking at Slide 7. I like how you continue to lay out sort of your core, extended core, and Fairway. Being mindful of not having the full '18 plan out, I'm just wondering when you look at or think about the plan for next year, given the run we've seen in prices, will that cause you to think about doing potentially more of the Fairway versus just sticking into the core? I'm just wondering if that plan will still be the same next year as previously believed.

So, Neal, the approach is to step out of the core and we talked a little bit about some of the pilots that we intend to do next year. So we're going to have pilots likely in more of the Red Bank area. And of course, I talked a little bit about some of the DUCs that we completed in Red Bank. That gives us a head start on that, but doing pilots potentially in Red Bank and then Painted Woods as well. So working into the extended core this coming year and then in future years, likely the Fairway.

The other thing that really helps us out is all the other operator activity in the basin. And there's these bigger jobs that are being tested by other operators as well, not only in the extended core, but there's also some really interesting tests going on in the Fairway. So we're keeping a close eye on all of that. And based on the results we see and as we get comfortable with the pilots, we'll keep stepping out more.

Okay, great details. And then just one last one, just on M&A. I know sort of earlier this year, you guys talked about looking both inside the Bakken and maybe outside of the Bakken. I guess my question around that is that -- number one, is that still the thought, to look in and out of the Bakken? And to me, sort of, if so, where would you look outside of the Bakken? And why not just focus just in sort of around your core area? Thanks.

Yes, Neal, nothing's changed. We continue to look for opportunities to bolt on in and around our core positions in the Williston, and that's always the case and always has been the case. We continue to work other basins between the Williston and -- Williston all the way down to the Permian -- to understand what's going on and put ourselves in a position to where if the time is right, we can be opportunistic. But that's hard to do without doing the work in advance. And at the same time, it gives us a lot of intelligence as to what everybody else is doing in those other basins. So that's always very helpful to us.

The next question comes from Brad Heffern of RBC Capital. Please go ahead.

You talked about being able to continue to maintain sort of a free cash flow positive plan. I'm just curious longer term how you think about the use of that cash. I assume in the near term it's going to be to pay down some debt and improve the balance sheet. But eventually is there a returning cash to shareholders sort of priority? How are you thinking about that?

Yes, Brad, we've talked about this before in terms of free cash flow and how we think about it. All we were trying to communicate was the 2018 plan that we had laid out previously is still intact in terms of our ability to execute it. We'll come out with specifically what we're going to do early next year when we roll out a full kind of 2018 plan. Where the commodity strip is as well as improving differentials, we're obviously going to be generating more cash flow than, call it the $50 environment that we had looked to kind of throughout most of this year. So we'll see how that actually plays out in terms of if you're generating free cash flow, what you do with it. Obviously, you can put it operationally to new projects on the E&P side, you can pay down debt, you could think about returning it to shareholders. We'll just have to see where we are when that occurs.

Okay, thanks for that. And then you guys talked through some of the larger Bakken frac jobs, so I'm wondering if there's any update that you guys have on sort of the really big ones, the 30-million-pound jobs?

So we've got a couple of 20-million-pound jobs and then a 30-million-pound as well. The 30-million-pound job is super early time. It's only been on for a few months, so we don't have good data to show on that yet. We'll get more updates on that later. The 20-million-pounds jobs, we just -- we've rolled into -- in the graph, it's everything greater than 10 million, but they continue to look interesting and perform well. And we'll update that. As we get more specific data on those wells by themselves, we'll show it. There is also the one Johnsrud well that you could see that actually is broken out, and it's the red well in the graph on Page 10 and you can see it. It's a great performer. So continue to be excited by the bigger jobs, and we'll optimize both around costs and what's the right size of the job as we go forward.

The next question comes from John Freeman of Raymond James. Please go ahead.

The first question I had was given the comments and the information you all showed on Slide 11 about just the gas volumes continuing to pretty meaningfully exceed expectations, just sort of how I should think about the oil mix going forward with sort of the tradeoff of those comments relative to increasing activity that's outside of Wild Basin and sort of some of these oilier areas relative to Wild Basin. Just sort of how I should think about the oil mix the next few years.

So first, with respect to individual wells, as you look at performance, one of the things we want to point out is that the oil volumes are really outperforming what our original projections were. So you're seeing great performance on the oil side that's either in line or above expectations. And then you just have this rising GOR that obviously can have the impact of increasing gas cut across the business. We reported 78% for the quarter and we talked about in the past as we drill, continue to drill more in the core, you're probably going to see that cut come down. I don't know if we've got a specific number to give you right now, but we'll have a better update on that when we talk about the budget at the beginning of next year.

Okay, and then just a follow-up to a question that Neal had earlier. When looking at the Fairway acreage, given with oil prices now above $55, would potentially, given where it sits in the queue of your inventory and sort of drilling plans, if maybe some of that acreage might be considered being divested, as it might be more valuable to somebody else relative to you all's inventory?

Yes, John, we'll continue to look at that. Taylor touched on the fact that there's a lot of other operator activity, stuff that we don't even have an interest in that's in and around some of those Fairway positions. And so I think that we need to be a little bit flexible on that, especially with the quality of the inventory that we have in the core and the extended core, if it makes sense to bring some of that value forward.

The next question comes from Paul Grigel of McQuarie. Please go ahead.

I was wondering if you could speak to any potential changes in the management incentive plan to be more explicitly focused on corporate returns or per-share growth metrics for 2018.

I think, I mean, obviously, a topic of interest across the industry and a lot of people talking about it. And what I would tell you is I've worked on this every decade for the last 4 decades, and I think one of the things that people have to keep in mind is that we don't generate a plan that's around growth. We generate a plan that makes sense for us to develop our asset efficiently and focus on our margins. And as we develop the budget for the year, obviously, out of that we get volumes and unit costs that flow through to margins and we develop targets that we're measured against.

But that isn't to say that we're doing some work on whether some of that -- some other metrics may make sense. And so that's really -- about the only thing I can tell you is that we're mindful of that, we're working on it. It's not anything that's new to me. We did the same thing back at Arlington when I was working on it back in the late '90s, and so it's something -- and we're keeping track of what everybody else is doing as well. So stay tuned.

Okay. And then I guess a little more nuanced one here. As you guys expand the processing capacity using temporary facilities in 2018, is there any impact on LOE that we should be expecting to come through, or is that just a washout in the process?

Yes, the processing plant is going to affect, and the temporary plant is going to all affect realization on the gas side, so it's not going to affect LOE. And the way we account for OMP overall still doesn't affect. It's all consolidated, so you're not going to see any changes to LOE.

Okay, and would the change in realization on nat gas be material or just within the normal course of kind of seasonal volatility?

It's going to be very similar to what you'd expect on everything else. At this point, OMP is going to be processing everything in that Wild Basin area for Oasis.

The next question comes from Ron Mills of Johnson Rice. Please go ahead.

Hey, guys, just curious if you could talk about the upcoming fourth quarter completions. I think you had had -- or maybe break down your DUCs between Painted Woods, Red Bank and Wild Basin. I think at some point in the second half of the year you were going to start completing more in the extended core. Is that correct, and how can that point to potential conversion from extended core to core based on performance?

So Ron, as we talked about, we did 24 wells in 3Q and plan to do another 24 in fourth quarter. We actually did a number of wells in Red Bank in some of those -- or in the extended core. And so that's got the potential, because of the fracs we did, it was a combination of 4-million-pound, 10-million-pound and then one 20-million-pound job. And based on those results, it will have a direct impact on the ability to move more of that extended core into the core.

The other thing that I think is pretty interesting, and Michael talked about in his prepared comments, is with the improvement in pricing, the diffs alone have moved, depending on how you account for it, between $3 and $5, and if you remember, or if you look on our presentation on the inventory slide, you can see that the difference between the core and the extended core is really just $5. And so just on a pure price basis, there's some of that extended core that's going to come down into that core acreage of below $40. So both of those things working for you, along with the other operator activity that we continue to keep a close eye on because they're doing more wells in and around our acreage.

And is there any, just from a theoretical standpoint, is there anything about, say, an extended core completion versus a Wild Basin where you said, and you referenced still testing 4 million and 10 million pounds in some of the extended core versus a lot of 10 million pounds plus in Wild Basin. Is there something technical that would drive potentially to less benefit for larger fracs outside of the core?

No, no. It's just stepping out and testing the range of wells. In these jobs like we've done in the core, we're frac and pull spacing units. So we drill the whole things, and now we're going in and we're doing these fracs and spacing. So we're just testing a variety of sizes of jobs to see how they react and produce when done in spacing. But there's no reason why you can't see the same benefits of doing the 10 million or even the 20-million-pound job as you get into the extended core.

Great. And then the last on the technical side, are you seeing any real difference in terms of performance between Three Forks and Bakken with the higher-intensity fracs? Is one formation taking better to it?

That's -- I made one comment, Ron, about the performance of the Three Forks versus the Bakken and Wild Basin. So if you look on the slide on Page 10, you can see that in the Bakken, the bigger jobs are really outperforming, some of them a little earlier date, are really outperforming the 4-million-pound jobs, whereas in the Three Forks at this point, the bigger jobs look pretty similar to the 4-million-pound jobs. Still monitoring and you're seeing different results in different wells, but on average we haven't seen as much separation. So that's where we're continuing to test both the -- anywhere from the 4 million to the 10 million in the Three Forks. In the Bakken we've gone to all bigger jobs. So we'll continue to work on the Three Forks and update that as we go.

And then, Michael, just one last for you. On LOE, I know for the full year the guidance ticked up a little bit, and I know you've talked about everything that's happened that has driven cost, your LOE down over the course of the year. What's driving kind of that near-term tick-up for the full year cost guidance?

Yes, Ron, we're just taking the full year guidance and obviously, as you move through the quarters, we've been on the upper side of that guidance range. And so just narrowing the range because of where we've been. Obviously, in the front part of the year it was slightly lower volumes as we were waiting for the OWS 2 to come in. It should start to lower here more dramatically, as volumes in the back half of the year are going up quickly. But with that last quarter, it's hard to move the average range too much.

The next question comes from Biju Perincheril of Susquehanna. Please go ahead.

Something on Slide 10, when you're looking at the performance of the Bakken wells, can you talk about looking at the 50-stage wells versus the 50-stage and 4 million pounds versus the 10-million-pound jobs, what kind of uplift you're targeting to justify the higher well cost?

So, yes, you can see on -- see what the performance looks like. But if you just look on a straight cost basis, as we talked about, the 4-million-pound job is $6.8 million, the 10-million-pound job is $7.7 million, so that's really, that's just a 13% cost increase. So really, anything above that looks pretty darn attractive. And we're seeing uplifts in the 30% range with the bigger jobs, depending on the well. So it really looks attractive at this point for the Bakken.

And Taylor did mention that what you're seeing on that page, that orange line, the recent wells aren't differentiating yet, but it's still under a constrained period, largely. So we'll have to see how that continues to perform as you get a little bit longer dated and outside of that constrained period for a meaningful period of time.

Got it. And when you're looking for that 13% or so minimum outperformance, so that's -- what time period are you looking at? It looks like for the -- for 6 months or so, there, I guess the wells are constrained. Do you want to see that outperformance in the next year?

Yes, we'll continue to watch the wells, but you made a good point. During that constrained period, we're flowing them back pretty much the same way regardless of the size of the well that it is. And you've seen it in a number of these. As you get out beyond 150 to 200 days, you start seeing more separation. A great example of that is the Johnsrud 20-million-pound well. So we think you'll start to see more separation. We'll continue to update it as we go.

The next question comes from Gail Nicholson of KLR Group. Please go ahead.

Just going back to kind of the Three Forks and you guys talked about you'll be testing different volume tweaks across Three Forks, is there anything else that you might be testing within the Three Forks formation to see if you could unlock incremental productivity versus the type curve?

Sure, yes. We're actually testing a range of different things. So it's size of the job just overall, intensity, number of stages, so we're testing above the 50 stages. We've done a fair amount of work with diverters and we continue to use diverters to see if we can get better distribution of our stimulation. Then on top of that, we're also working with water volumes in addition to sand volumes. So we're pumping larger amounts of fluid because there's been some indications that may have a positive correlation. So really, a number of different things. We're always looking at ways to improve the results. We're encouraged by some of the things that we're working on but just not ready to talk about them yet.

Okay, great. And then just looking at the dramatic improvement in that oil differential, when you look at '18 forward, is that something that you guys might try to hedge out to lock in? Kind of what's your thoughts about that, the longer-term oil differential now?

Yes, diffs are a little bit harder to hedge, but we are doing some things on the physical side to try to make sure that we lock some of that in as we go forward. So we are playing around with that a bit to try to lock in. Like you said, it's at a good level and we'd certainly like to keep it here. We do think that it will stay. Obviously, while we're seeing diffs that are closer to WTI here in the fourth quarter, we're still projecting kind of that $2.00 longer term, given that you have access to premium markets. I think as DAPL came in, there is a fundamental shift that it just changes it for a longer period of time.

The next question comes from Dave Kistler of Simmons/Piper Jaffray. Please go ahead.

So talk a little bit, maybe, about the fresh water project that you guys brought in-house. Obviously, you've made comments that higher water volumes are having a correlation to better production, et cetera. But a couple of things around this: one, is it indicative that you're bringing that in-house, that we should continue to see that trend towards higher water volumes? What does that maybe mean for EBITDA generation for the fresh water project going forward? And then how do you think about recycling as well all those vehicles to kind of maximize returns?

So Dave, in terms of the pumping larger volumes of water, we're testing that on a small number of wells at this point, so no conclusion about whether we'll do that on a broader basis. But obviously, something that could add to the EBITDA of that business. It's been, and I'll let Michael talk a little bit more about it here in a second, but it's been a great addition. We're now supplying a big part of our Wild Basin volumes ourselves, and then also having the opportunity to do third-party as well. So it's a business that we think we can really grow on our assets, but also from a third-party standpoint as well.

Yes, and water volumes, fresh water's, access to fresh water is very strategic. There's not many permits out of the river in the area, and so having access to that is extremely important. As you think about where we've come from just a few years ago, almost everybody operator-wise are moving to slick water jobs. That in general increases your need for fresh water volumes. Before we start talking about even adding volumes from there, that already increases your fresh water needs by 4x. And so the need for fresh water is extremely important. Recycling's very difficult in the basin right now, given regulations. So it looks like you'll need that fresh water, a very strategic asset for us, not only for Oasis-operated volumes, but as you think about it from the midstream perspective, Taylor mentioned that the ability to go get third parties is very viable as well.

And Michael, do you have any kind of thoughts in terms of what the EBITDA would look like on that? Obviously, with OMP in place and the various entities that you're utilizing to potentially drop down, just trying to think about kind of accretion on that.

Yes, you can think about that deal as being very similar to the way we think about midstream projects. And as we acquire that asset and building it out a little bit, we're going to look at kind of that build multiple of 4x to 5x. And so as you've spent -- you can see, kind of call it around $20-ish million on that asset. Think about a 4x to 5x longer-term build multiple.

Okay, appreciate that. And then one other one, just kind of looking at the G&A trend that continues to go down in a favorable fashion, with cash flow a little bit higher, potentially, next year, kind of thinking about the 3 different things, one of which being increasing activity slightly, can you talk about what optimal rig count might be relative to G&A trends and how that G&A may continue to work its way down until whatever rig count level or, I guess in some respects we should probably talk in well count, but just given that rigs are kind of the closest association to it right now, if you could give any color on that would be great.

I'm not sure we think about it exactly the way you're talking about it, Dave, but you're right. G&A per BOE is definitely trending down. You're seeing kind of our assets being super capital efficient and we don't need to add as many rigs to continue to grow production levels, so that means that overall, as our production grows rapidly, our G&A won't be growing on an absolute basis in line. So our dollars per BOE should continue to go down. I don't know exactly how to think about it in some of the ways you referenced it, but you're right that it's trending down.

Yes, I was thinking about it absolutely the way you're thinking about it, but also in terms is there a rig level at which you have to bring in more people or completion level and where that might skew it to a different direction.

Yes, but all that growth is going to come with additional production as well, and so overall, where we are is that you're going to see continued efficiencies and that G&A is going to continue to go down. As we grow faster, I think it's just going to go down even faster.

This concludes our question-and-answer session. I would like to turn the conference back over to Tommy Nusz, CEO, for any closing remarks.

Thanks. It was a great quarter for Oasis, underpinned by operational execution coupled with improving commodity prices and differentials. We also achieved significant milestones in activating our second frac spread and the IPO of Oasis Midstream Partners.

Looking a little further back, I can't say enough about how the entire Oasis team has navigated the downturn in our industry over the last 3 years. The team has done a tremendous job across the board, improving margins by significantly improving capital and operating efficiencies, managing business risk through hedging and infrastructure and actively managing and improving the balance sheet in a tough environment. I won't claim that we're completely through the cycle yet, but we're very well positioned as a company through the significant accomplishments of our organization. Thank you again for joining the call today.

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