Chord Energy Corp (CHRD) 2017 Q1 法說會逐字稿

Good morning. My name is Robert, and I will be your conference operator today. At this time, I'd like to welcome everyone to the First Quarter 2017 Earnings Release and Operation's Updates for Oasis Petroleum. (Operator Instructions) And 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. Mr. Lou, you may begin your conference.

Thank you, Robert. Good morning, everyone. This is Michael Lou. Today, we are reporting our first 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, 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 to file our 10-Q today, following this call. We will also reference our current investor presentation, which you can find on our website.

As you may have seen, we issued a press release yesterday indicating that we are -- that we have decided to move forward with an MLP IPO for a portion of our midstream assets. Due to securities law, restrictions and advice of our attorneys, we will be unable to discuss this development, and we know that you can appreciate that. If the transaction proceeds and becomes a public filing, you will be able to see more information with respect to the transaction on the SEC's website. At this time, we cannot provide further comment.

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

Good morning, everyone, and thanks for joining our call.

It was another great quarter for Oasis as we began to execute the 2017 plan we outlined in February, moving towards bigger completions and increased overall activity. Accordingly, the first quarter of 2017 was a notable pivot point for Oasis. Our team successfully integrated the acquisition we closed in December and returned to growth mode on our existing asset base. It was a significant undertaking, and the team did an impressive job. And to top it off, we were cash flow positive.

Volumes for the first quarter came in at 63,200 BOEs per day, a 19% increase from our fourth quarter production, and a 1,200 barrel a day -- barrel equivalent a day increase from our December pro forma exit rate. That implies an 8% annualized growth rate within cash flow from the end of 2016, an impressive metric given the production impact from our second frac crew is largely yet to be seen. We remain on pace to achieve the 72,000 BOE per day exit rate we discussed in February, with growth oriented toward the second half of the year. Operating costs are generally in line with the end of 2016. We should begin to work per unit operating costs down as we grow production more materially in the back half of the year.

Last time, we discussed our decision to transition to higher prop loadings across our 2017 completion program, averaging about 10 million pounds per well this year. Taylor will go into more detail shortly, but early well results continue to look fantastic, and we remain very confident in that decision. We look forward to results from these larger completion tests outside of Wild Basin in the coming months.

Oasis delivered substantial operational improvements and general capital efficiency gains over the last couple of years. Maintaining those efficiencies is at the core of our plan to grow the company and the pace at which is -- we intend to do it.

We completed 13 wells in the first quarter of 2017. Almost half of those came online in late March. Part of that is due to increased frac intensity leading to longer cycle times on pads, and part is due to the timing of our third party frac crew.

Vertical integration has been a key driver of our efficiency gains. And this, coupled with the frac market inflation concerns, has led us to make the decision to redeploy OWS 2. We expect the second fleet to return to service in the second half of 2017. OWS has been a meaningfully strategic asset to Oasis throughout the ups and downs of the cycle, and we're excited about its further impacts as we grow the business. I'll also note that we intend to continue utilizing external frac services to ramp up wells to first production throughout the year. This combination sets us up for greater success in 2018, with our 2 OWS fleets supplemented with third parties crews, leaving us ready for the addition of a fifth rig in 2018.

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

Thanks, Tommy.

It was a solid start to 2017 for the team as we worked to integrate over 200 newly-acquired wells from our December acquisition and began to ramp up activity. We completed 13 gross and 9.7 net wells in the first quarter, which all but one were completed by OWS and Wild Basin. As we discussed last time, our third-party crew began to work an our DUC backlog in the middle of the first quarter. Their efforts have been focused on DUCs in Indian Hills so far, and we should begin to see production from these wells in the second quarter.

As Tommy mentioned, we now expect our completion activity to be more weighted towards the back half of the year. We still expect to complete about 76 gross wells, likely 12-or-so wells in the second quarter with the remaining 50-or-so wells evenly split in the second half of the year. This ramp-up should coincide well with the addition of our second OWS fleet and should also set us up for a more efficient growth in 2018 as we operate at the 5-rig program we have discussed for next year. As part of this plan, we are still on track to add 2 rigs in the middle of 2017.

On the cost front, we budgeted around 10% inflation weighted average for 2017. And while we are beginning to see well cost increase from our February estimates, they continue to be in line with expectations.

As depicted on Page 10 of our current presentation, a 10-million-pound slick water well is now $6.8 million, which is about 5% more than our February estimates. As you can see, the services market in the Williston is starting to tighten. There is sufficient equipment to cover demand for services, but the manpower required to run the equipment requires a little lead time to put in place. Well inventory is obviously important to command these services. As Tommy mentioned, we plan to activate OWS 2 in the second half in response to the tightness. We think both price escalation and efficiency justify the response.

Turning to well performance. Our 4-million-pound slick water completions in the core continue to produce in line with our respective type curves, as shown on Slides 5 and 6 of our presentation. The 10-million and 20-million pound Bakken jobs in Wild Basin had continued to perform with expectations. In the Three Forks, we are also seeing the bigger jobs differentiate themselves. All of the high proppant wells, depicted on Page 5, are now in artificial lift and continue to perform very well. Outside of Wild Basin on the east side, we have recently completed a high proppant well in northern part of our Alger position. The well is completed with about 2,000 pounds of proppant per lateral foot and has been materially outperforming all set wells.

As you can see on Page 6 of our presentation, the teal well is significantly outperforming our core well performance for 4 million-pound jobs outside of Wild Basin. Note that the teal is a 4,400-foot lateral that has been adjusted to represent the performance of a 10,000-foot lateral. Following its success, we plan to complete several more wells in Alger later this year with similar proppant loadings. Additional high proppant tests are currently in place, with 8 10-million-pound wells fracked and waiting on a cleanout both inside and outside of Wild Basin. Four of these wells are in Indian Hills. We look forward to reporting these results as the year goes on.

In the back half of 2017, we plan to move a frac crew into Red Bank, where we will test our high proppant slick water jobs in that acreage as well. Note that the DUC backlog in Red Bank is a combination of locations in our core and extended core. Several of our peers have tested larger jobs nearby with encouraging early time results. We expect to schedule further pilot programs for our extended core acreage in the coming months as well.

Keep in mind that our average frac size this year is projected to be about 10 million pounds. As a result, we have numerous tests across the position that will test proppant loadings from 1,000 to 3,000 pounds per lateral foot. Based on the early results both in and out of the core, we are really excited about the potential to impact our bottom line.

It's an exciting time for Oasis. The size of our position continues to grow, along with the potential to continue increasing recoveries across our inventory in the extended core and Fairway.

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

Thanks, Taylor.

Despite the erratic markets, we were free cash flow positive in the quarter again by $9 million and continue to be cash flow positive since the beginning of 2015. Our liquidity remains very strong, and on April 10, our lenders increased our borrowing base from $1.15 billion to $1.6 billion. However, we remain satisfied with our current liquidity and have chosen to keep elected commitments unchanged at the $1.15 billion at present.

Oil differentials were in line with the fourth quarter of 2016. More recently, we have begun to see the effect of Dapple in the second quarter, and differentials have tightened. Currently, we're seeing differentials at around $3.50 per barrel and are optimistic that they may continue to improve. We've delivered basin-leading differentials over the past couple of years by getting crude onto large gathering systems and maintaining maximum optionality amongst delivery points. While we certainly have direct access to Dapple on these gathering systems, the increase to basin takeaway has put significant pressure on basin-wide differentials, and specifically, for uncontracted barrels.

Gas realizations improved nicely in the first quarter as we realized $3.81 per Mcf, which was 125% of Henry Hub, a material improvement from where we were just a few quarters back. This is mainly driven by improved NGL pricing in the first quarter. Our view is that we should continue to realize, at least, Henry Hub in this price environment going forward.

As Tommy mentioned, while completions are a bit back-end loaded, we are confident we can hit our annual production guidance range as well as our 2017 exit rate of 72 MBoe per day and 2018 exit rate of 83 MBoe per day. Our oil production for the first quarter was 78% of total production, which was exactly in line with our full year guidance.

LOE for the first quarter came in at $7.71 per BOE. This was within our full year guidance range as well. We expect LOE per BOE to work its way lower as we grow production.

Our DD&A per BOE has also continued to come down. This reduction is driven by a combination of higher PDP reserve bookings, lower well costs and our acquisition late last year.

Turning quickly to OMS. Gross adjusted EBITDA was $25 million for the quarter, up 9% from the fourth quarter of 2016, and our gas line has been up and running since October of last year.

Oasis is off to a great start in 2017, and we remain on track to deliver strong production growth in the coming years. I want to thank the team for their hard work and continued innovation.

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

(Operator Instructions) The first question comes from Neal Dingmann of SunTrust.

Could you and Taylor just to talk about the cadence? You talked about the number of wells for the rest of the year. I'm just trying to get a sense of the size of the fracs. I mean, is it going to be largely kind of the 10 million, 20 million? I'm just trying to get a sense -- I look at that cadence for the rest of the year. How many of these will be on the higher side of the frac design versus kind of what's your kind of most recent average has been?

Yes. So Neal, we've -- this is Taylor. We've done, as we announced, 13 wells in the first quarter, which leaves us about 63 for the balance of the year. And to get away or split that up is there will be -- 8 of, what we'll call, the really much larger frac jobs and that will be split. Four will be 20-million pound jobs, and 4 will be 30-million pound jobs. And then the balance of the wells, the 55 that will get you the total of 63 is split pretty evenly between 4 million-pound and 10 million-pound jobs.

Got it. And then just one last follow-up, just on that bringing the frac crew out. You anticipate, besides kind of -- I guess, can you just talk about perceived expenses around that versus if you would go with a third party, how you -- Michael, I guess, for your tail, how you guys have sort of looked at that or the thought of bringing your own out when you sort of annualized that the rest of the year?

So as we bring our own out -- keep in mind, our frac services are market-based. And so from this, the base level estimate of expenses are going to be pretty similar between us and the third-party crew. Where we think we can probably do better is -- and this is what we're charging to ourselves and to partners. Where we can do better, probably a bit, is on the efficiency side. And we've seen that because we're so well aligned and integrated between our completion side of the business and our services side, and so those guys are actually supervised and sit together. So we realized really better efficiencies than third-party crews. Now as far as the internal benefit and credits, from the beginning -- really, the end of last year coming in the beginning into this year was pretty close to breakeven. But as the service costs are starting to ramp up, we'll start to see that benefit internally in the second half of the year as we bring our crew up.

The next question comes from Subash Chandra of Guggenheim.

So this, the cash flow neutrality, or I should say, even free cash flow that you highlighted since 2015, how does that get weighed as a priority as you look at these field level efficiencies? It sounds like the more activity you have, the better you'll get those efficiencies. And second, I don't know if you can talk about it, but a midstream spin, which might demand a higher growth rate for an optimal valuation.

Yes, Subash. So in terms of efficiency levels, I think that we're in full development mode. We're seeing very strong efficiencies kind of throughout our program. So I don't know that we need more activity to drive those same level of efficiencies. We are cash flow -- we have been cash flow positive since the beginning of 2015. I think that shows our capital discipline through a rougher patch. We have talked about that our capital program is based off of a program between $45 and $55. We're in the middle of there, the $50 neighborhood. We're going to be cash flow neutral this year, so we feel pretty good about our plan. We can't -- once again, we talked about we can't really talk about the ML -- anything on the MLP side of things.

Okay. Yes, I won't go into a follow-up on MLP. I just want to sort of flesh out. There are -- other companies have talked about sort of multiple strategies in maximizing MLP value beyond an IPO. I'm just curious in your file -- in your statement yesterday if you're going the IPO process. I know the statement is not definitive about it or there are other joint venture-type considerations you might think about.

Yes, no comment.

The next question comes from Mr. Michael Hall of Heikkinen Energy Advisors.

I guess just curious on -- maybe first on this Teal well. Boots said that was in the more northern part of Alger. Just curious kind of what -- like how this well is outperforming very nearby offsets, if you could quantify that, and then if you have any plans to potentially kind of further press -- test of enhanced completions for further north on the eastern side of the basin on your position.

Sure, Neal -- I mean, Michael. If you look at the map on Page 7, in -- over on the east side of the basin, where it says Alger, yes, that well is located north actually of where Alger's written on the map. So it's really in the north end of what we did consider to be in the core in that block. But it's really performing, well outperforming than any other wells that we've got in the area. So we're super excited about it. And like I said, we're going to do more of these across the position. In fact, as we pick up rigs, we're going to start drilling actually in the south of Alger. But from there, we'll move to the North, and we're hopeful that this will work into Cottonwood. We haven't tested it there, but that would be, really, the next big step out. And at some point, we'll have some pilots in that area to test the same techniques and frac sizes.

Okay. Great. So do you think you have potentially a South Cottonwood test later this year in the capital program? Or they're more likely next year?

Yes. It probably won't be this year. It's more likely next year. We do have, as we've talked about, Red Bank tests would -- over on the west side of the position. Some of that will be in the core, and some of it in the extended core. And we're also working on pilots, stepping out further from that, Painted Woods would be an example.

All right. Okay. And then, I guess, I was also just curious on Slide 5, the 4-million-pound Wild Basin jobs. That curve kind of seems to be tipping over on the back end. Just curious on what's kind of going on there from your perspective. And any additional color you could provide around that and how you think the bigger jobs might or might not take a similar trajectory later in their life?

Yes. It's a pretty small dataset at this point, and all the wells are now, on these pages, are on artificial lift. They're on gas lift, and so the exact shape and performance of the wells we're still understanding. But to us, it's still early time. It's still in line with expectations, so we feel good about the data we put out there. With respect to the larger jobs, you can see what they're doing. They are well outpacing, even the shaded portions that we've added to these graphs on Page 5. And so we're super excited about those, and we'll continue to monitor. Don't know the exact shape they're going to come in yet. But we've got, as we talked about earlier, a bunch more of these coming on. So it's -- the 63 wells for this year, there's about 28 of those -- 27, 28 at this point that will be 10-million-pound jobs, and you've got 4 that will be 20 million and another 4 that will be 30-million-pound jobs. So we're really excited to see what those results will look like.

Great. And then, I guess, just curious, I'm sorry if I missed this, but the first quarter, what was the average frac size? Do you have that by chance, of the 13 wells you -- turned on?

I don't have it, Michael, off the top of our head, but we'll get that to you -- hold on. It's -- so it looks like it's right about 5 million pounds average for the first quarter wells.

The next question comes from Graham Price of Raymond James.

So I know it's a bit early, but was just wondering kind of the effect of adding that second OWS crew as far as the 2018 outlook goes. I know you reiterated the 83 MBoe per day at year-end, but was just kind of wondering about how we should think about the rest of the year.

So with the second OWS crew, we're still going to have -- as we run 4 rigs this year and then go into 5 rigs next year, we're still going to have the need for third-party crews to fill in gaps. But we should be doing the majority of our wells with our own frac crews, which we think will just help from an efficiency standpoint.

Okay. Got you. That's helpful. And then quickly for a follow-up. I noticed that the oil mix in 1Q was down a little bit from 4Q and was just wondering if we could get a little color on that.

Yes. So the oil mix at 78% is exactly what we guided for the year. As we've talked about in the past in Wild Basin, it is a slightly higher gas cut. So while the first part of the program is a little bit more Wild Basin-focused, you're going to have a little bit of a shift towards a little lower oil cut and a little higher gas cut. As we -- throughout the rest of the program, you start completing in the core areas outside of Wild Basin, you'll start to see that normalize back. So we kind of expect that 78% kind of throughout the year.

The next question comes from John Nelson of Goldman Sachs.

What would be the intended use of proceeds for a potential midstream monetization?

We can't talk about that.

Does that imply it's for growth for the midstream? Or I guess, historically, you guys have talked about potentially using that for either debt paydown or E&P acceleration. Is it fair to still assume that?

John, when that filing comes out, you'll see it in there, and you can refer to the SEC filings for that. We can't talk about it.

Fair enough. And then the press release alluded to a more back-end weighted completion schedule. Does that mean we should be thinking about kind of a low end of production guidance for the full year? Or is that not necessarily the way to kind of read into that statement?

Yes. So 50 of the 76 wells being slated for the back half of the year, obviously, you got a lot more activity in 2 -- I mean, 3Q and 4Q. And as Michael talked about, we continue to think we'll be within the range, and we'll give more clarity and color on that as we go.

The next question comes from Ron Mills of Johnson Rice.

Just a real quick question. When you talk about the second half completion are being weighted towards that period and still hitting the exit rate, that would seem to imply potentially entering 2008 (sic) [2018] at a little higher trajectory than what may have been expected. Can -- is there any potential impact or flow through of that relative to the 83,000-plus exit rate that you have put out for 2018?

Ron, at this point, it's -- we're just kind of holding to the previous guidance. We have said it's going to be a little bit more back-end loaded this year. We'll continue to watch the effects, but we're just holding to the guidance right now.

Okay. And then as it -- somewhat relates to Slide 5 and 6 and the amount of proppant you'll be using in the remaining completions. Given the strong early data on the 10-plus million pound frac jobs, just curious, is there something about those remaining 27 completions or the 4 million pounds that you're going to still use them? Is there -- are they in a different geologic area? Or is -- if you have more production data from the larger fracs, could some of those even transition to larger jobs?

Yes, it's really the latter. We're just continuing to understand the performance of these bigger jobs. And so if we continue to see strong results, then we've got the option of -- upping that weighting to a higher percentage of the bigger jobs. And at the same time, we're looking at what is the right spacing for these wells. And so we're trying not to move too fast to where we overcapitalize. We want to really understand the impact of these completions and then get them spaced in the right distances apart.

But I think a number of them are Three Forks wells that we've got at the 4-million pounds level of Three Forks DUCs. And then there's a few of them that aren't necessarily the mechanical setup isn't conducive to it. So we're clearly giving the higher prop loads where we can and where we think it makes sense.

And then lastly, just on the spacing on Slide 7. How many wells are you now expecting per DSU? And Taylor, maybe how much time would it take to determine whether or not the larger fracs result in not as tight spacing but greater recoverabilities per dollar?

So first, on the spacing side. The core of the basin, it's generally kind of 11 to 13 wells. The higher or closer density of the wells are very most tightly packed are really kind of Wild Basin in the south Alger. And then as you fan out into the Fairway at the bottom end, it's more like 7 or 8 wells per spacing unit. In terms of how much time do we need to understand the F&D costs, we've always said we like to, at minimum, get around 6 months to get a pretty good indication of how the wells are going to perform. But the longer amount of time that we have on these, you give it a year, you got a -- you're getting a pretty good view of where you're going to fall out. But it's going to be something that we'll continue to monitor and perfect over time in terms of spacing.

The next question comes from Gail Nicholson of KLR Group.

I'm just looking at the wells and how long they flow naturally. For the 4-million-pound jobs, did those wells flow naturally about for 180 days? And are you seeing the higher proppant loading jobs flow naturally longer?

So it depends on the area for the 4-million-pound jobs. But gosh, somewhere around 120 to 150 days, 180. It just depends on the well those 4-million-pounds jobs flow. And in general, the bigger jobs flow longer.

I think the one on Page 5 was over 200 days.

Yes.

So -- and it's a big prop job, but still early times.

And does that surprise you that they flow -- that the larger jobs flow longer? Or that's kind of anticipated?

No. Really, you're pumping more fluid volume and more sand into the rock, so you're just pressuring up the rock more. Plus, with that bigger frac, we think we're more effectively breaking up the rock. And so those 2 things combined induce pressure. And then more effectively, breaking up the rock, you would think would lead it to just flow for a longer period of time, which is a good outcome.

Plus, we're doing a lot of things on just getting better dispersion along the lateral, so it's contacting more rock consistently along the 10,000 feet, which should help.

Great. And then in regard to efficiencies with OWS. When you look at the current OWS crew, how many days does it take for the current crew to complete a well versus a third-party fleet? Just trying to understand kind of the delta and the efficiencies.

Yes, the -- It's early time on picking up a third-party crew, and we've got one, as I said, working in Indian Hills. And as we have gone to picking up the pace, bringing in a set of equipment and a group of guys that maybe haven't been working consistently together and certainly haven't been working on our properties, and so there's just the natural learning curve to try to get those guys up to what our expectations and kind of what we've been doing with our own crews. So it just takes a little bit of time for that to happen. In terms of the frac jobs for a 4-million-pound job, it's around 5 days per well.

Okay. Great. And then the $6.8 million well cost to the 10-million-pound job, that includes the cost savings regularizing OWS, correct?

No, it does not. That's just -- that does not include the credits for OWS that we've received internally.

Do you know what the well cost would be if you include the credits for OWS internally?

Yes. Like I said, for late last year and early this year with where pricing has been, it's -- there's not really an impact. It's kind of a breakeven. Now as we look forward with the price increases that we're seeing, you'll begin to see a credit, but we'll just have to tell you more about that when we get there.

The next question comes from Gregg Baby of Bank of America.

That's Gregg Brody. Can you guys hear me?

Yes.

Yes.

I was just wondering -- I know you can't talk about the [michelin] transaction. I was just curious if you talk to any restrictions with your -- per you indenture to pursue a transaction. It looks like you have a big RP basket, I was just wondering what your thoughts were.

Yes, Gregg, we're not talking about anything about the MLP right now.

Okay. And then maybe just one other question. You added a line item to your revenue and costs that's sort of this bulk purchases. I see it's pretty much a wash, so just wondering what that is and we should think about that going forward.

Yes. I think you can ignore the bulk purchases for the most part. That's essentially us doing some blending work, where we'll buy some crude and then -- and sell it. And so really it's a -- like you said, it evens out between the revenues and the cost side. So we broke it out, so it's easier to see that it's just a wash. But really, I think you can somewhat ignore that overall.

The next question comes from David Deckelbaum of KeyBanc.

Good luck on the pursue of the OMS, and congrats on sticking to your promise to not talk about today. But curious, I guess, as you see the proppant, I guess, in basin right now with going up to the 20-million-pound jobs, I guess I have 2 questions. One, when you evaluate performance, are you also sort of adding variables of choke management with these? Or I guess, as you compare, for instance, the Johnson or the [Rolleston] or other unconstrained wells, do you feel like you should be flowing these freely or choking them back in early stage? And then I'm curious to know if you're trying different grades of proppant and how the availability is right now in the basin.

So first on how we flow the wells back, we're -- the first one was facilities-restricted. And so it was -- really had some restrictions on it. In general, we're trying to be mindful of the reservoir and the proppant of wells, so not trying to pull them too hard. And we're actually working -- looking, because we got a number of these wells, trying to compare some different approaches to flowing back, but certainly not cranking them open. Trying to be fairly conservative. With respect to the proppant and grades of proppant, as you go to the bigger wells, you get into the 10s, 20s and 30 million-pound wells, the percentage of the overall proppant in general has more 100 mesh in it. But we're also -- have experimented with some wells that have mostly 40, 70 in them. And what we're doing there, and that's on 10-million-pound jobs, we're just trying to make sure that as we flow these wells longer term that we maintain the conductivity of the frac and keep the performance. But in general, the wells are a combination of 40, 70 and 100 mesh.

And then, I guess, Taylor, are you guys seeing any constraints with availability of sand in the Bakken? And has that cost changed materially in the last couple of quarters? And are you thinking about kind of securing that supply longer term with contracts directly from suppliers?

We've really been making sure we're staying plugged into the market on that side of equation. We got a guy who's dedicated just to sand procurement. And from an availability standpoint, we hadn't seen a problem. Now bigger -- the big thing around these larger frac jobs because you're -- it's all unit train sand loadings, it just requires more planning and logistics and making sure that you've ordered the sand far enough out in front and then that you got all the trucks to move it. So it's really a logistical and planning game. And so far, we haven't seen a problem with supply. Now on the cost side, from late last year to -- and early this year to current, we've seen it bump up a bit. And it's really on the mine gate, and it's manageable at this point.

The next question comes from Blaise Angelico of Iberia.

I believe you guys had previously expected to complete a well in Red Bank in the second quarter. It sounds like that is shifting until later in the year. And I apologize if I missed this, but what type of completion are you planning for the well in that Red Bank area and just a number of total completions for '17? Just trying to get an idea of how we should think about how that area fits into the equation over the rest of '17 and into 2018.

So in Red Bank, we've got a mix of completions, but it will be -- the total in that area have about 12 wells. And of that 12, there's 7 right now that are planned to be 4-million-pound jobs. There's a 3 that are 10 million and then 2 that are 20-million-pound jobs. So we're trying to, again, test the full range doing these 1,000-pound and 2,000 pound per foot loadings along with the 4-million-pound jobs. And timing-wise, it's moved back a little bit into second half.

The next question comes from Stark Remeny of RBC.

I was just hoping you guys might be able to provide additional color on how we should think about the activation of the second OWS crew and how, I guess, changes your flexibility to adjust to various oil prices. Or maybe, said another way, does this kind of lock you in at a new base level activity? Or is there a point in which you look to slow your completion pace?

So in terms of activity, it's -- obviously, it's allowing us to flex up and, we think, lock in some cost improvements and efficiencies as we pick up the pace. Now as you look at the downside of -- you're in -- getting to a protracted lower price environment, where we need to pull in our activity. From the planned activity levels at 76 completions for this year, a part of that is third parties, and so that would be the first thing that would drop if we pull an activity. If we need to, we can optimize just on the 2 crews. And in general, our approach to contracts across the business has really been to keep them shorter term. So that if we get in a, like I said, a protracted pullback, we'll match our activity with our cash flow, and we can make those adjustments pretty quickly. We feel like we're in pretty good shape this year from a hedging standpoint. We've got over 60% of our volumes hedged. So it gives us a bit of a buffer, where we can plan that change in activity and implement it in an orderly manner.

And one last thing to remember on that side is, if you'll remember last 2 years in that lower price environment, we had kind of one frac crew running. Given the acquisition, we'll be at a higher base load of production, so we'll actually be able to keep more activity running. On top of that, we're doing higher-stage completions, which will take more frac capacity. So we think that we're going to be in good shape keeping both of those crews busy.

Excellent. And I guess, what's your view on potentially adding another OWS crew in the future given the ramp in oil prices or desire for a greater growth? What's the lead time cost and interest level?

I think at this point, we're going to be comfortable with 2, and we'll flex with third-party and see where things go. I'm really not looking to add a third crew at this point. But it's probably -- I would guess to add, I mean, on that original frac spread, we spent $25 million. But that was with a much smaller horsepower requirement. Today, to build a frac spread is probably more like $35 million, something like that. We've actually got about -- from an equipment standpoint, about $1.5 million. Maybe a little bit more than $1.5 million from an equipment standpoint. So that's the -- we've got $12 million to $15 million to get the supplemental equipment with sufficient backup to provide 2 crews.

The next question again comes again from Michael Hall of Heikkinen Energy Advisors.

I was just curious. I was thinking as you were discussing the -- just the oil mix with the front part of the program being pretty Wild Basin-focused. You talked about what you think the exit mix might look like as you kind of March concentrically out from Wild Basin over the course of the year in 2017-2018 exit rate.

Yes. Michael, right now, we're looking at kind of 2017 being pretty flat because of the balance going forward of completions inside and outside of Wild Basin, kind of pretty flat at that 78% range. That's the same thing going on in '18.

The final question comes from Jeanine Wai of Citi.

Apologies if I missed it. I got disconnected, but back to the completions being a little more back half-weighted than originally expected this year. Can you just clarify whether you're able to maintain the production guidance purely based on well outperformance ? Or is there some component of just moving the schedule around a little bit in the back half and supplementing with maybe a third-party frac crew every once in a while to get things moving?

Yes. Like I said, the back half-weighted nature, we've got 76 completions total, 50 of those in the second half. We'll be using bringing up our crew, our second crew in the second half. And we'll be using third-party crews along with that when needed. Obviously, that's going to -- with that much of a weighting of completions in the back half, it's going to move the production out a little bit. But right now, we're -- we still think we'll be within our guidance and are maintaining that guidance.

Okay. And then lastly, I guess, in terms of adding the fifth rig next year, is there any change in the thinking on the timing of that rig given either efficiencies or well performance or any of the testing that you're doing?

The main consideration around the fifth rig is activity that we can support with our cash flow. And as we look to the growth in volumes, we think that'll make sense for us in next year, and we'll bring it up. It'll help to increase frackable inventory and then, obviously, help the volume growth in 2018.

Okay. And then the 2 rigs that you plan on adding midyear, are those contracted yet?

I don't know that they're assigned. But if they're not, they're super close. We've got both those rigs secured and will be available for us shortly.

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

Thanks.

Across the board, the team is off to another great start in 2017 in what continues to be a choppy market. I'm excited for the opportunities in 2017 and what that will bring to Oasis. And we remain a firm believer that our underlying asset quality, strategy of vertical integration, investment in infrastructure and the proven track record of our team will position Oasis to continue to differentiate ourselves in this next chapter.

Thanks for joining us today.

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