Chord Energy Corp (CHRD) 2016 Q1 法說會逐字稿

Good morning. My name is Denise, and I will be your conference operator today. At this time, I would like to welcome everyone to the first-quarter 2016 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, Denise. Good morning, everyone. This is Michael Lou. Today, we are reporting our first-quarter 2016 financial and operational results. We are 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, 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 of adjusted EBITDA to the applicable GAAP measures can be found in our earnings release and on our website.

We plan on filing our 10-Q today, following this call. We will also reference our current investor presentation, which you can find on the home page of our website.

With that, I will turn the call over to Tommy.

Good morning, everyone, and thanks for joining our call today. The Oasis team continued its momentum and delivered strong results as we entered 2016. We completed 15 gross, or 12.8 net, operated wells during the quarter, all in our core Williston acreage, while producing over 50,000 barrels of oil equivalent per day, as a Company, for the sixth straight quarter.

Operating costs were basically flat compared to what we achieved in the fourth quarter of 2015, and well costs are in line with our $6.5 million expectations, as we remain confident in both our type curves and completion designs. Through the team's hard work, we see a tangible path towards reducing well costs by another 5% to 10%. And we continue to experiment with the latest industry completion technologies.

We were cash flow positive again this quarter, including $35 million of midstream capital, and have now generated $177 million of positive cash flow over the past four quarters. All of this combines to give Oasis substantial opportunity to further build upon the capital efficiency gains we have seen over the past year.

OMS had another quarter of record results, moving 78% of our produced water volumes through our system to our disposal wells, generating almost $20 million of adjusted EBITDA. Our increased utilization of OMS continues to have significant impact on our LOE and operating margins. As both Taylor and Michael will talk about in greater detail, our activity in the second quarter and beyond is now highly concentrated in our Wild Basin acreage.

Our 2016 Indian Hills completion program is now largely complete, and our internal frac crew is transitioning to Wild Basin. We expect to bring wells online in Wild Basin in the second half of this year, as our midstream infrastructure build-out remains on schedule and on budget. As we look forward, we remain focused on continuing our track record of solid execution and working to further improve our capital efficiency, all while continuing to retain optionality around acceleration and maintaining the ability to be opportunistic.

With that, I'll turn the call over to Taylor.

Thanks, Tommy. It was another great quarter for Oasis, and a strong start to 2016. All of our first-quarter completions were high intensity fracs within the core. We are seeing very strong results from high intensity wells, and continue to see performance in line with our updated type curves for high intensity fracs, as depicted on Slide 11 of our presentation. As a reminder, our core inventory is depicted on the map on page 9 of our presentation.

As you can see, we have over 600 locations remaining in the core, which translates to over 13 years of drilling at the current pace. The returns depicted at the bottom of slide 11 demonstrate the solid returns for these projects in the core and as prices have moved up over the past few months, we are approaching levels that make much of our extended core acreage economic, as well.

We completed 15 wells in the first quarter, or about one-third of our 2016 completions program, with all of the activity located in Indian Hills. We will be wrapping up our activities in Indian Hills in the second quarter, and as Tommy mentioned, focusing our development program in Wild Basin for the remainder of the year.

The Wild Basin infrastructure build-out is on track, and we expect completion in the fall of this year. This should allow us to load the gas plant and other infrastructure at that time.

The climate in Williston lends itself to a spring and summer construction season, so while we spent about $35 million on the Wild Basin infrastructure project in the first quarter, much of that was spent on progress payments for critical components. The second and third quarters of the year will see the majority of on site and infill construction. Contractors have been selected, materials have been ordered, and all parts of the project are underway.

If you look at slide 12 of our presentation, you can see the steel walls of the crew storage tanks currently under construction, and an updated picture of the gas plant. Our OMS budget for 2016 remains unchanged, at $140 million. As everybody knows, it was a relatively mild winter this year, and we clearly saw the benefit of that in both our production and LOE results for the first quarter. Production came in at 50,300 barrels of oil equivalent per day, generally in line with our production in the fourth quarter, and above the high end of our full-year 2016 guidance.

LOE was a similar story, coming in at $6.78 per Boe, slightly below our fourth quarter results, and also ahead of our full-year 2016 guidance. Both metrics were helped by the mild winter, which yielded less downtime on producing wells and allowed us to maximize our completion activities, all leading to increased production while maintaining an optimized cost structure. Our midstream services business, OMS, also had another tremendous quarter, moving a record 78% of our gross operated volumes through our pipeline network in the first quarter, up from 75% for the second half of last year.

We have also seen significant operating efficiencies within OMS, as the business continues to be a significant contributor to the LOE improvements I just mentioned. As we look forward, we now expect full-year LOE to be closer to the bottom end of our $7.75 to $8.50 full-year range, while our production guidance for 2016 remains unchanged, at 46,000 to 49,000 barrels of oil equivalent per day. Our capital program for the year is proceeding as originally planned. Our well costs are currently coming in at the $6.5 million estimate we provided in February.

OWS again completed 100% of our wells in the quarter, and that remains the plan for the balance of the year. Additionally, our drilling group was able to shave another day off their average cycle times in the first quarter, yielding an average spud rig release of about 15.5 days. The team continues to drill new pace setter wells, which remain about 4 days ahead of that average. In fact, we just released a rig on a Wild Basin well that took only 11 days from spud to rig release.

Oasis continues to look for ways to reduce capital costs through regular communication with our vendors, continuing to improve drill times and completion efficiencies, and optimizing how we utilize both OMS and OWS. We remain optimistic that if current conditions hold, there is a path to reducing well costs by another 5% to 10%. We are also testing new completion designs and technologies, including diverters, proppant suspension, and high stage count and high profit volume slickwater wells, just to name a few. All results are early time, and we will continue to closely monitor the progress as we move forward.

At quarter end, we had 83 gross wells waiting on completion. We continue to view this set of drilled but uncompleted wells as a strategic asset that provides us flexibility from a price recovery and operational standpoint, uniquely positioning Oasis to capitalize on a rebound. In closing, I want to commend the team for an outstanding first quarter and strong start to the new year, and I once again challenge them to maintain the momentum.

With that, I will now turn the call over to Michael.

Thanks, Taylor. The business continues to perform very well, and we were again cash flow positive for the fourth consecutive quarter, generating $10 million of positive free cash flow. Given that WTI crude spot prices averaged around $33.50 per barrel for the quarter, that's a remarkable accomplishment for the team. Especially when you consider that we spent $35 million of infrastructure capital in the quarter. We continue to expect the business to be cash flow positive for the full year of 2016, and that estimate excludes our OMS infrastructure project, which we still expect to be able to fund externally.

Oil realizations for the first quarter were in line with guidance, and with the fourth quarter of 2015. As we have said previously, we are optimistic that the current $4 to $5 range on differentials is the new norm, driven by the resilience we have seen from the rail market, increased pipeline capacity already in service, and additional larger pipeline projects expected to come online in the next 12 months. Gas realizations remain challenged, driven by both lower Henry Hub prices and by the continued oversupply in the NGL markets.

G&A for the quarter was in line with our 2016 guidance, and E&P G&A was a slight reduction compared to the fourth quarter of 2015. As we have worked to become more efficient, we expect G&A to further reflect those efforts throughout the year, especially as reflected in E&P G&A per Boe metrics. And we expect total Company G&A to come in at the lower end of our original guidance of $90 million to $95 million.

As a point of clarification, our clean EPS for the quarter was negative $0.18 per share, which includes a write-off of $2.3 million of a non-cash debt financing cost. If you back out that write-off, clean EPS was a negative $0.165 per share.

In the first quarter, given our undrawn revolver and our strong operational results generating positive free cash flow, we were able to repurchase an aggregate principle amount of $30 million of our outstanding senior unsecured notes, for a cost of $22 million. And all-in, year to date, we have repurchased $77 million of senior notes for $56 million, resulting in a $20 million reduction in outstanding debt and a net annual interest savings of more than $4 million. At the end of the quarter, we had only $65 million outstanding on our revolving credit facility, and total liquidity of $1.1 billion, with our next borrowing base re-determination not scheduled until October of 2016.

To close, our team had another fantastic quarter. As we move forward, we will continue to focus on driving capital efficiency, balancing CapEx and production growth, and preserving our strong liquidity position.

Thanks, everybody. And with that, I'll turn the call back over to Denise for questions.

Thank you, sir.

(Operator Instructions)

Your first question will come from Neal Dingmann of SunTrust.

Morning, guys. Just on that slide 3, Tommy, when you guys mention that, I agree, it seems like more areas becoming, certainly with these prices, more economic. How do you think about -- I think you or Taylor's comment about the extended core becoming more economic? How do you define that versus just the core of the three key plays? Wonder how I should look at that?

Do you want--

We address that, Neal, if you look on page 9, the inventory slide. And we break out the core, extended core and fairway. And the core we talked about, at $30 plus, depending where you are, very economic and resilient, at low pricing. Then the extended core, with the EURs being a little lower, 575 to 750 MBoe range, your breakeven at $45 plus. So as you get to $45, certainly into the $50 range, those things start looking pretty interesting.

Got it, got it. Okay, great slide there. Then just two onto that, my last two. Tommy, your thoughts, you guys have been great about continuing the positive free cash flow. Is that -- even if prices tick up a bit, is that still going to be -- when you and Michael think about it, is that still the strategic plan? Or at some point, does it make sense to become a bit more aggressive on the spend?

Yes, that's one, Neal, we'll just have to feel our way through it. We talk about free cash flow exclusive of OMS. And so we've done a really good job, even with the OMS capital, being free cash flow positive, or at least neutral, as we talked about. And so I think first order is, is we eat into that OMS capital. And so if you think about it, first order of business is, outside of external financing, if you set that aside for a minute, is being free cash flow positive on total capital. Now, that's -- as we go through the second and third quarter, that's going to be more of a challenge, as we get closer to completion on that facility. But I think that's -- absent external financing, I think that's a reasonable goal in the near term.

Got it. And then just lastly, on M&A, that -- looking at that slide 9 that Taylor pointed out, how do you think about, Tommy, just blocking things up? I guess two questions. One, your thoughts, or do you have intentions of adding more or blocking that up? And I guess I haven't heard of much in the way of Bakken deals recently. Any color you can give on how things are trading in that area?

We've actually done a few deals, all the way back into the fourth quarter of last year, where we've continued to consolidate in our core blocks, some of that, some straight purchases. And again, still within our cash flow, and then some of that trades with some of the usual suspects. And as we go into Wild Basin, we have a bit of a lower working interest there than what you've seen historically. So it provides us an opportunity to core up a little bit. And like I say, in a number of those cases, we're trading non-op acreage out. I mean, we're consolidating with the usual suspects. And we've done that for a long time, but even more so here over the last two quarters.

Got it, got it. Thanks so much. Nice quarter, guys.

Thanks.

The next question will come from Brad Carpenter of Cantor Fitzgerald. Please go ahead.

Good morning, guys, and thanks for taking my questions. Just a few quick ones for me. I guess we could touch on just Wild Basin quickly. Back on the third-quarter call, I think it was, you said that by year end 2017, the infrastructure should be running at nearly full capacity by then, and that the asset can generate around a $60 million run rate for EBITDA. I guess two-part question, is that still a good number to use, to help us build a standalone value for the asset? And then I was hoping to get your thoughts on external financing and potential timing around that for the asset?

I think what we said at the end -- on the third quarter was, is that $60 million EBITDA run rate. And then once the plant's up and running, and as we get into the end of 2017, that effectively doubles, right, Michael?

Yes, so on all of the infrastructure, we had $66 million of EBITDA last year. If you annualize the first quarter of this year, it's closer to $80 million. So the guys are doing a great job continuing to grow that business and use that asset to its fullest, and we expect them to continue to do that.

As you think about Wild Basin that you asked about, Brad, you're right on that. It's going to be more full-ish, in terms of capacity, going into the fourth quarter 2017 and the first quarter of 2018. With that, we were talking about $60 million of EBITDA. And it could do, potentially, a little bit above that, as well. But that's a good number to start with for now.

Okay, great. Thanks. And then if you wouldn't mind, do you have any thoughts around the potential for external financing for the asset? And any potential timing on that?

No. We said that we still think that we can -- that we're going to be able to fund that externally. But we've got -- other than that, we can't really comment on timing of the process.

Okay. All right, great. Thanks. And nice quarter, guys.

Thanks.

Our next question will come from Michael Rowe of TPH. Please go ahead.

Hi, good morning.

Good morning.

So I guess back to the question about the extended core, you show that there's a $45 plus per barrel breakeven price. How do you think about the trade-off between achieving those returns versus out-spending cash flow, potentially, and taking on some debt to do that? I guess where I'm going with this is, what's a price where you feel like you can get an adequate return on capital, while also not adding on more debt than you're comfortable with?

Yes, it seems like that's the question of the quarter, is at what price point do you increase activity? And it's a simple question, but not necessarily a simple answer, because as you know, there's a lot of moving parts. But similar to what you've heard from other operators, you start thinking about that in the $50 to $60 range. And as Taylor's mentioned, that's where that extended core really starts to come into the window. But you're always weighing that off, the very attractive economics against out-spending your cash flow.

So while the economics in the core are really attractive in that range, 40% to 50%, at $50, there's a number of things that we have to consider as we go further. And that's -- we can start drawing down the DUC inventory. We've got to take a look at availability and cost of services, and does cost of service start to move up as activity picks up, cash flow balance and overall capital allocation. So not to mention the condition of the macro market and the trajectory of the forward curve.

So we'll just have to feel our way -- I think it's a little bit early to start laying out commitments of, will we do exactly this at this price point? I think that's going to be a bit misleading. And I think we just have to feel our way through this, as we go. And it's not just price, but it's surety of price, whether that's a view or through hedging. But I think it's a little bit early to start being very specific about a plan, when the market's as volatile as it is.

Sure. That makes sense. I can appreciate that. And I guess my follow-up question is, you spent about $48 million on the E&P business in the first quarter, and on DNC specifically, about $37 million. So I was just wondering if you could help us think about the rate of E&P spending from here for the rest of the year, given the fact that you went through nearly one-third of your budgeted full-year completions during the first quarter?

So first, with the completion count, we did do 15 in the first quarter, and so that leaves us around 30 for the balance of the year. And we expect that at this point, we would think about it being pretty evenly dispersed, about 30 a quarter for the remaining quarters for the year. When you think about the 15 completions, and trying to line up completion count, and then having a proportioned amount of capital spend, keep in mind, you've got to think about carry in and carry out.

So when you're coming over the year, it may not -- those 15 wells may not represent a full cost for a well. It could -- some of those are partials, because they are being carried in over the year. So you get a full well count, but not full cost, in terms of capital. In terms of overall projection for the year, we continue to project to be at $400 million of total capital, with $200 million of that being D&C capital and $200 million of it being OMS and the other capital.

Great. Thanks.

You bet.

Our next question will come from Mike Kelly of Seaport Global. Please go ahead.

Hey, guys. Good morning.

Good morning.

Follow-up on that last question, and I'm trying to get a sense for 2017. And I know there's a lot of variables in play here, but as it pertains specifically to the DUCs, and once you have the infrastructure online and ready to flow these things, how quickly can you work that down? And how should we think about, yes, just that DUC management there? And really what that means for your trajectory of production, as you go through 2017? Thanks.

So like we talked about, we've been keeping -- that DUC count has remained pretty flat, and we're at 83 currently. And when you look at the makeup of that well count, there's actually 60 -- about 65 of those wells are in the core. And then the rest are in that extended fairway, so close to 20 in the extended fairway.

We've got the ability to focus on those DUCs and do some incremental completions. And as Tommy talked about, as we get into a price recovery, that's one of the things that we're going to look at. And that's a pretty easy lever for us to pull. We can -- we've got infrastructure in place, for the most part, for all of those DUCs. So it's just a matter of lining up a frac crew and fracking them, and then getting them online. So something that we can do in pretty short order, it's just a matter of when we think the right time is in a price recovery.

I think the good news is, is having that DUC inventory that we've got is, is that we can pull that lever as we see some price improvement. And maybe not just stay flattish, as we've talked about and we've done in the current world, and staying within cash flow, but possibly jump starting some growth that's staying cash flow neutral.

And also, when you think about it, keep in mind there is always a cushion in that DUC inventory, which represents the cycle time with the completion rigs and the crews. So there's going to be 30 to 35 wells that you -- even if you start working them down, you're always going to have some backlog in there, 30 to 35 at this pace.

Got it. Appreciate that. And then follow-up question is just, wanted to get your sense on all this enhanced completion work that's being done in the Basin. You guys have been a leader on this front, and have shown really good results here. And I'm just curious what you're most excited about here, going forward, on this front? And are we at the point here where there's still potential step changes to be seen? Are we just incremental ticks higher? And what this could ultimately do for returns in the core part of the basin? Thanks.

Sure. As we talked about, the high intensity fracs continue to just deliver fantastic results, and the average type curve for the wells as we're doing them right now is 1,050 MBoe. And then also, we talk about in the presentation, on page 10, some of the things that we're testing. And it's very early time in some of these things we're looking at, but diverters are certainly interesting. We've worked with increasing the number of frac stages. That's still early time.

And we're just starting to do some of these slickwater fracs with larger volumes, so 10 million plus pounds of sand in a single well. So we're excited about the prospects for all of these. Are all of them going to work? Probably not. But I bet you end up with a handful of things that you'll implement, going forward, but it's just going to take us some time to fully test that and then implement it in a program.

Got it. Thanks, guys.

You bet.

And our next question will come from Michael Hall of Heikkinen Energy Advisors. Please go ahead.

Thanks. Good morning. Congrats on the solid --

Good morning.

I was just wondering if you could talk through a little bit more on the cost side of things, well cost side of things, as it relates to the 5% to 10% additional savings you guys touched on. Just maybe a little more color on how you get there, line of sight on that? And then as a follow-up to that, what's you all's view on, at this point, how much of the savings that you've delivered on, relative to the 2014 peak, will actually remain in a, call it $65 type world?

Okay. So --

Couple questions.

Yes, no, it's good questions. For the first one, the well cost, as we've talked about, we're at $6.5 million. So we've made a big move down from that $10.6 million that we came into 2015, and we think we'll get it down to $6.1 million like we talked about. Now, in terms of where that's going to come from, we think it will be mixed in between, really, the completion bucket and the drilling bucket. So both those, we think, will be able to continue to drive costs down.

And like it's been in the past, Michael, we think it will be mixed between service costs and efficiencies. The efficiencies continue to impress us. We talked about drilling days, for example. We started 2014 at around 21 days. We're now at about 15.5 days, on average, and like we talked about, we've seen wells spud to rig release in as little as 11 days. So we think the efficiency side, we're going to continue to get gains, and then some contribution on the service cost side, as well.

When we look at it in aggregate, the -- from that $10.6 million coming into 2015 to the $6.5 million now, it's split pretty much evenly between efficiencies and then service cost reduction, 50/50. So if you do get into a price rebound, say you're in a $65 world, and like Tommy talked about, service cost increases, we're going to want to really watch. But if we can retain that 50% of those improvements, from an efficiency standpoint, which we think we will be able to, it's going to put us in good shape.

The other piece that you'll want to keep in mind is on the service cost side, the biggest reductions have been in the completion side of the business. And given the fact that we've got internal frac services, it gives us protection or a hedge against those increases. So we get coverage on -- really on two fronts, both efficiencies and then that frac side of the business.

Great. That's helpful. And I guess on the frac side, given you all have the -- your own internal capacity, maybe an interesting view on the Basin, as it relates to excess capacity in the Basin currently. Like how many -- do you have any data or color around how many crews or spreads remain in the Basin? And what capacity utilization looks like these days?

Yes, Michael, I don't have the exact number of crews, but a good way to think about it is, the equipment and then the people operate the equipment. So there's plenty of equipment on the ground, quite a bit that's been idle. And you've actually seen, gosh, in the last quarter of last year and the first quarter of this year, a few of these guys either leave the Basin or go out of business. But even with the loss of that equipment, there's plenty of equipment on the ground.

It's just -- the interesting thing is going to be the crews to run that equipment. In an orderly progression of increasing capacity, I think we're going to be in good shape. People will be able to man that equipment. If everybody tries to pile on and pick up a bunch of crews real fast, which I think is not real likely, that could be more of a challenge.

Okay. Great. That's helpful color. And I guess couple more of mine. One was just on the -- getting back to the timing of well completions, if I'm reading this right, I think almost 45% of your net completions were in the first quarter. Should we expect a march down in working interest over the rest of the year?

Yes, so you're right. You are going to see some march down in working interest. And again, like we talked about on the growth completions, those will be spread out evenly at this point, over the last three quarters.

Yes, keep in mind that the bulk of those completions in the first quarter were in Indian Hills, where we've got that higher working interest. And as we move into Wild Basin, that working interest goes down a bit.

Okay. Makes sense. And then last one of mine is, can you just remind me how the -- you mentioned the OMS [is the] thing drives operating cost structure improvements. I guess, can you talk about how we should think about how much of the improvement has been driven by OMS? And how that would look in a monetization, or as you call it, external financing scenario? How that level of cost item might be impacted?

I'll let Michael touch on the second part of that question. But if you go back, and of course, a bit of a different price environment, WTI price environment. But if you go back and look, when we did the acquisition back in 2013, remember, our per barrel LOE cost went up to $10 plus, $10.50, maybe even $11 during that time period. Because we brought in -- one, our infrastructure was immature. And we brought a bunch of production in that was -- basically had very little infrastructure, and so you've seen that come down.

Now, some of it driven by service costs. But you've seen it come down from $10.50 to $11, down to the $8 range. So at a high level, if you are just looking at what the impact would be of not having that, it's pretty significant.

Yes, it's a couple dollars impact from the OMS side. And in terms of, how will it look in an external financing situation, obviously, we don't -- it depends on how that financing comes in, so there could be a number of different ways. And we don't have -- we can't really talk about any clarity on that right now.

Okay. Fair enough.

But we're also not looking at a full monetization there, so you still will get a lot of that benefit.

Okay, great. Thanks, guys.

Thanks.

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

A lot has been asked. Just a couple questions on the DUCs versus activity. And what's the impact of -- that OWS has on that? In other words, if you complete 10 wells a month, is that just utilizing one of your two spreads? Or how flexible -- how much flexibility does that second spread offer you?

Yes, Ron, we do have some additional flexibility in the crew that we're running for the rest of the year. We do have a little bit of incremental capacity. And then like you mentioned, we do have equipment for a second frac spread. When we decide to go into more activity level, we'll actually have that ability, as well. But right now, we do have some incremental capacity that we can continue to use OWS.

Okay. And then not to belabor the DUC versus activity thought process, but is there some sort of breakpoint where you think putting another rig back to work is preferable over DUCs? Or do you think that the DUCs may be a better entree into increased activity?

I think it's -- when you're focused on cash flow and cash flow neutrality, I think you're always going to go to the lower cost alternative, which is going to be the DUCs. That's going to be your first order of business, right? It's -- especially if you think that you might be in an improving price situation.

Great. Makes sense. And then maybe for you, Michael, on OMS, the increase in EBITDA run rate to $19.5 million, what were some of the drivers behind that? And are those sustainable to -- it sounds like they were more sustainable, as you talked about an $80 million annual run rate?

I think that -- so a couple things. One, the team just did a very good job of continuing to leverage our large infrastructure position on the saltwater side, and continuing to connect a higher and higher volume of water across that side of the business, which drove very good, strong financial performance. We do think that -- we hope that they can continue to do so, and carry that throughout the year. And then with Wild Basin coming on in the second half of the year, you're going to start to get some incremental cash flow or EBITDA from that business, towards the end of the year.

Keep in mind that as we do more of these high intensity fracs, your liquid loads are greater. And so you probably get more flow-back, as well.

(multiple speakers) So as you're thinking about the slickwater jobs, we've talked about slickwater jobs being 4 times the amount of fluid that you're pumping down versus our old base jobs. And so as you recover some of that load, that's going to come back to you early time.

And in the past, too, you talked about testing slickwater, and about testing higher proppant loading. It sounds like one of the options now is combining the two. Are there any other industry results? Or have you started the process? I'm assuming that comes at a higher cost, so therefore your expectation of improved EURs?

Yes, you're right. It is combining the two. So it's taking a slickwater job and just making it a bigger job, with higher prop loads. Like I said, 10 million pounds plus. Definitely comes with a higher cost, but we're hopeful we're going to see a commensurate increase in production and EUR. We just -- still early time.

And the increased EURs you came out with, those are exclusive of the list of the new four or five things you're testing, correct? That's just -- that's primarily the increased proppant loading?

Correct, yes. The 1,050 EURs are the old high intensity fracs.

Great. Everything else has been asked. Thank you so much.

Thanks, Ron.

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

Good morning. Just a quick question. The [white wells] in Wild Basin, are those the only high intensity well completions to date that you've brought online in Wild Basin?

That's correct. Those -- we've got three wells, one Bakken well and two Three Forks wells. And those were the only ones that we tested with high intensity fracs that we've got on production. But all of the activity right now is with those high intensity fracs, and we'll be bringing on those wells later on this year.

And there are other operators -- Gail, there are other operators in the area that have done high intensity completion. So we have got a lot of confidence in what we're going to be able to get out of those fracs.

I guess I was curious, if those wells have outperformed the core high intensity type curve that you put out, do you think that's a one-off in that DSU of the white DSU? Or do you think that is a potential repeatability across the entire Wild Basin area?

So we're excited by the results in those wells, and our hope is that we're going to see repeatability of that kind of performance as we frac these other wells. And that's why we've come in and done these high intensity fracs, and then are experimenting with some even larger jobs, to see if we can get even improved results from what we're seeing there.

Great. And then looking at the further improvements that you continue to achieve on a quarterly basis on that spud to rig release, what's the biggest driver there? Is it just pad drilling? Less [mob] time? Employee personnel on the rigs? Can you quantify that?

So one of the things you talked about is certainly important, which is the personnel side of the business, getting the right guys focused on the right things on the rig. One of the other ones is equipment, and really good quality control has helped us to stay on bottom. So less trips during the drilling of these wells.

Some of the best ones we've done have been where we're drilling our full lateral with one trip. And so just focusing on all of the key things we need to do in the drilling operations, and proving that through having the right people there, and then really good QC on the equipment.

Okay, great. Thank you.

Thanks.

Our next question will come from John Nelson of Goldman Sachs. Please go ahead.

Good morning, and I appreciate the thoughtful responses to the DUC questions that have come up.

You bet.

I'm curious, as we think about 2017, are there a minimum number, or an optimal number of Wild Basin wells that you guys would like to get down, just from the standpoint of filling that nat gas processing plant capacity? As we try and think about the wedge for the number of DUC completions you might get after?

Yes, we've got -- the program will continue to run in 2017, two rigs there, and keep a completion crew busy. When you get further out in time, you're not going to need -- once the plant is loaded, need as many completions to do that as you're seeing in 2016, 2017. It's really 2018 and beyond where you begin to see a little bit of a reduction to keep the plant loaded. And that's an 80 million cubic feet per day plant by design.

And, John, one other thing. One way to think about a 2017 program is, if you had around the same amount of D&C capital as this year, call it in that $200 million-ish range, you can probably -- in this price environment, that could be a likely scenario. Most of your activity's going to be in Wild Basin for 2017, to do exactly what you're talking about, which is load the infrastructure and get it to where the fourth quarter and into 2018, you're at more capacity in the infrastructure.

That will keep overall production relatively flat for the Company. And so that's a -- call it a base level program at that $40 to $45 oil price. And then I think around the DUCs, as Tommy and Taylor have been talking about on the call, is around that potential for acceleration someday, is that you can use those DUCs as very low cost inventory, to bring forward some of that activity level, very capital efficient dollars to spend for us.

That's very helpful and very clear. I appreciate that. Just on the OMS potential monetization, would you consider [hiving] off any of that to put towards the DUCs? Or is that earmarked more for debt repayment or for you to keep on the balance sheet?

We'll see where we are on that OMS. Obviously, as Tommy mentioned, we're doing -- our guys are doing such a good job on the capital efficiency side. The price of oil has rebounded a little bit, so we're able to generate more and more cash flow and actually be cash flow positive, taking into account OMS.

And so if we can continue to do that, we'll just have to see where that capital goes. Obviously, capital -- or cash, at the end of the day, is a bit fungible, so it's still going to take all those other things that we've been talking about, in terms of forward look at oil prices and capital efficiency, and all of those other things, to figure out acceleration. But you're right, if we get capital in, it will just continue to bolster our already-strong liquidity position and balance sheet.

That's fair. And then just one housekeeping for me. Taylor, in your earlier comment about industry labor, I think you made the comment that you think the industry can handle it if we see an orderly ramp. Just curious -- I know it's not a quantified number -- but what is your characterization of orderly? Is it 5 rigs a quarter, 10 rigs a quarter, 20 rigs a quarter? Just general thought? Not what we'll go to, just what an orderly ramp is.

Yes, so certainly not at the pace that we saw coming down. If you're having to support that, it's going to be a challenge. And what is the amount? Hard to say. 10, 10%, something like that, 20%. So we're just going to have to see. But as long as it's not doubling capacity in a year, something that's more orderly, 10%, 20% range or a little higher, I think it can be supported. But we'll see.

Yes, on the way down, if you think about it, we were close to 200, and we've gone to 25. So you were about 20 rigs a quarter on the way down. So just like what Taylor said, if you go to 20 rigs a quarter on the way up, things are going to get a bit dicey. But I can't imagine that it's -- that it's going to be that way coming out the back side. It's probably going to be more in the five range or so a quarter.

That's very helpful. Thanks, guys. I'll let somebody else hop on.

Our next question will come from David Deckelbaum of KeyBanc. Please go ahead.

Good morning, Tommy, Michael and Taylor. Thanks for taking all the questions today.

You bet.

Taylor, I was hoping that maybe you could walk through again. I wasn't clear on -- as you go through Wild Basin, understand the density theoretically. But how are you guys going to be drilling through Wild Basin on a unit-by-unit design currently? In terms of how many -- are you going to start with just no Bakken wells, and putting four or five down per section and then coming back to do Three Forks? Or are you going to do a full development suite all at once?

So we're actually doing full development. We talk about this as corridor development. We'll start at the southern, south to southwestern portion of Wild Basin, and drill out -- as we go, we're drilling out full spacing units. And we're putting all the wells, at this point, in the Bakken, in the first bench of the Three Forks. So no lower benches at this point. We feel like we can drain the full Three Forks section with those wells just in the Bakken and in the first bench. And then the density, we will perfect that as we go.

Okay. That's helpful. And Michael, I know you had mentioned earlier about the Wild Basin midstream capacity getting full at the end of next year, and as you go into 2018 conceivably, you would have some build-outs.

I guess backing into your $200 million program, if you had like a similar 35 to 40 gross well program to fill Wild Basin, I guess how quickly could you expand the infrastructure there in 2018? To satisfy perhaps 50% more wells on an annual basis, if you did have another financing partner in there towards the end of next year, beginning of 2018? Once you got things broken, how quickly could we expect to see some sort of expansion there?

David, we could certainly expand the infrastructure in Wild Basin, or what we also could do is go to areas outside of Wild Basin. We've got great returns throughout the core and extended core, and even into our fairway acreage. With what our guys have been able to do on the cost side, as well as on the EUR side, really, all 500,000 acres are starting to get to be very cost resilient.

So we just need to, at that point, weigh, is it better to spend infrastructure dollars in Wild Basin and continue to increase that capacity? Or spend the capital to basically keep it at more of a capacity level, and continue to grow it -- grow, for us, outside of that area. So there's a lot of things to balance there, but we're looking at all of them.

So I guess if we're in an intermediate environment, or $50, $60 oil, if not materially better than that, you would be maxed out at Wild Basin. So your incremental growth capital would be just in other areas of the core? Is that fair?

That's right.

Okay. And then the last one I had, I know in talking about all of the different high intensity completions and some of the benefits, we've seen those uplifts in EURs. And obviously, this quarter, you guys showed the best improvement in Montana. Is that -- would you boil that down to just 100% silt sand, slickwater, with the proppant loading there?

And I guess as you look like across the areas, it seems like Montana's been the one to show the most continued improvement. Is that one of the areas, or the area, that you would be most excited about, in terms of improvement over time, just considering perhaps some of the favorable royalty environments there, and other factors?

So you're talking about the slide where we're showing Montana at 625?

Yes.

Yes, so it's 625 MBoe, and really had good performance. And those wells are -- they are all high intensity. It's a mixture of slickwater and high volume prop jobs that we've talked about in the past. So we're excited about that area. Given where the well costs are, we think in Montana, we can drive costs lower than these -- the $6.5 million high intensity numbers that we talk about. We have substantially lower costs there. And so that's a great example, that extended fairway acreage that, as you're getting into the $50s, start looking pretty interesting.

Okay. That's all helpful. Thanks, guys.

Thanks.

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

Hi, guys. Just one remaining question for me. When I look at the efficiency gains you all have got, where we talk about now we've got some wells on spud rig release, like 11 days. When I think about in a normalized environment, what we're not trying to maintain DUCs or anything, what would be the proper rig count, or rigs to frac spread ratio we should use?

So right now, it's close to about 2.5 rigs per frac spread. As Michael talked about, we've got two rigs running. We've got a little extra capacity with the frac crew. So a good number right now is probably more like 2.5 rigs per spread.

But would that be -- I guess what I'm trying to get at is if -- is that -- would that ratio allow you to draw down, basically, your DUCs? Like if -- does that allow you to keep up with the number of wells you're bringing online?

Yes, that ratio, the -- that would be balanced. So you would -- if you had 2.5 rigs and 1 spread, you're completing all the wells that you're drilling, so your DUC backlog is staying the same.

Perfect. That's all I had. Nice quarter, guys.

Thanks, John.

And the next question will come from Jon Wolff of Jefferies. Please go ahead.

Good morning, guys.

Good morning.

Question on the pipeline outlet. Can you maybe give a little more color on how much of a benefit -- you gave -- it sounds like you were talking about absolute differentials of $4 to $5, not percentages, is one clarification. But I was wondering how much of the benefit has come from just the overall declines in the Basin versus new pipeline capacity? And then maybe talk about some of that new pipeline capacity? And I'm pretty sure Oasis hasn't committed to anything too much directly, but if you could talk to that, it would be helpful.

Sure, Jon. Yes, I think it's a combination of everything. Obviously, the -- everybody's seeing that the Basin, the production numbers have come in a little bit from its peak. So that's certainly helpful. There's a lot of great transport out of the Basin, both on rail and on pipe, and that continues to expand with the number of pipeline projects that continue -- are going to continue to come on.

Energy transfers, Dapple 1 is certainly a very large one that should be coming on in the next 12 months, let's say. And so when that comes on, we think that you're going to continue to have a lot of really strong options on where to move the crude, and how to move the crude, and that's just going to be good for all the producers in the Basin overall. You're right that we have historically had very little of our production in long-term agreements. That continues to be true.

We think that there's a lot of capacity, and when you're in a situation when there's more capacity than there is production, typically it's better for producers to be a little bit on the shorter-term side rather than longer-term side on contractual obligations.

Okay. And then the rail providers probably aren't liking this so much. Are they coming to the table a little bit more with a little better pricing? Or are they flexible?

Yes, I think the rail guys have --are continuing to do well. A lot of them are still bidding strong, are good partners for us, and we continue to have a lot of dialogue. So I think it's continuing to work on both fronts.

Got it. And your $4 to $5, does that come out of an economic argument, or is it supply/demand balancing, or is that the cost of transportation as you see it?

That's just where we've seen it for a little while now. And we think that, unless there's a large move on the production side, where it's going to drive a tightness in that capacity, we think that it could stay there for a little while.

Thanks a lot. Very helpful.

Thanks.

And our next question will be from Jason Smith of Bank of America Merrill Lynch. Please go ahead.

Good morning, everyone. Congrats on the results.

Thanks.

So just a quick follow-up on the DUCs. You gave a lot of color. And I was just curious on the actual location of your DUCs. Are they all within the core? Or are they spread throughout your acreage? And to your point earlier, is there infrastructure setup that you can bring essentially all of them on when you're ready? Or is there any infrastructure spend that has to go with bringing them on?

There's 83 DUCs, like we talked about, and 65 of those, or about 80%, are located in the core. And we've got just under 20, about 18 wells, that are outside the core. And they are in Red Bank and in Montana, so they are all within the extended fairway. Great to have that big percentage that's all in the core, that 80%.

And then like we've talked about, fortunately, because these are all drilled in areas where we had had development going on in the past, we've got good infrastructure in those areas. So we're well positioned, and we don't need to do a bunch of infrastructure work. We can frac the wells and bring them on production in pretty short order when the timing is right.

And outside the core, it varies a bit. Some of those are Red Bank, where we have good infrastructure. Montana, we probably need a little bit of infrastructure work for those. But that's a pretty small population of wells.

Got it, thanks. And then the last one for me is, you talked last quarter about Wild Basin being a big gas area, you talked it being a bit deeper. Can you remind us, first of all, what is the oil mix there? And I guess as we look into the rest of 2016 and into 2017, how should we think about that trajectory for the Company as a whole?

So it is a big gas area in Wild Basin. And so the GURs are more in the 2,000 to 2,500 range in that area. Depending on where you are in the rest of the Basin, you can be 750 to more like 1,500. And so you are going to see a bit more gas, as we bring those wells on, you can see a tick-up in gas.

But keep in mind, the overall productivity, when you look at those wells, from the few that we've done with high intensity fracs, they are just much bigger wells. And we talked about that in the presentation. The three wells that are high intensity fracs, relative to the base, are really outperforming. So you can see, on page 11, the performance of the white wells.

Thanks, guys. That's all for me. Appreciate the color, and congrats again.

Great. Thanks.

And ladies and gentlemen, at this time, we will conclude the question-and-answer session. I would like to hand the conference back over to Tommy Nusz for closing remarks.

Thanks, Denise. The Oasis team continues to deliver positive results in spite of the current storm. We were free cash flow positive again in the first quarter of 2016, our fourth in a row, including the funding of OMS CapEx of $35 million. We continue to execute financially and operationally, and will remain focused on improving our capital efficiency while continuing to retain optionality around activity levels and all capital allocation alternatives. Thanks again for joining us today.

Ladies and gentlemen, the conference has now concluded. Thank you for attending today's presentation. You may now disconnect.