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 1st quarter 2017 Earnings Release and Operations Update for Oasis Petroleum. All participants will be in listen only mode. Please note, this event is being recorded.
I will now turn the call over to Michael Liu, Oasis Petroleum's CFO, to begin the conference. Mr. Liu, you may begin your conference.
Thank you, Robert. Good morning, everyone. This is Michael Liu. Today, we are reporting our Q1 2017 financial and operational results. We're delighted to have you on our call.
I'm joined today by Tommy News and Taylor Reid as well as other members of 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 ks and our quarterly reports on Form 10 Q. We disclaim any obligation to update these forward looking statements.
During this conference call, we will also make references to adjusted EBITDA, which is a non GAAP financial measure. Reconciliations 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 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. We know that you can appreciate that. If the transaction proceeds and becomes a public filing, you will be able to see more information
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 Q1 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 Q1 came in at 63,200 BOEs per day, a 19% increase from our 4th quarter production and a 1200 barrel a day, barrel equivalent a day increase from our December pro form a 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 2nd 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 higher prop loadings across our 2017 completion program, averaging about £10,000,000 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 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 Q1 of 2017, almost half of those came online 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 3rd 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-two. We expect the 2nd fleet to return to service in the second half of twenty seventeen.
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 fleet supplemented with 3rd party crews leaving us ready for the addition of a 5th 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 work 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 Q1, of which all but one were completed by OWS and Wild Basin. As we discussed last time, our 3rd party crew began to work on our DUC back log in the middle of the Q1. Their efforts have been focused on DUCs in Indian Hills so far, and we should begin to see production from these wells in the Q2.
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 2nd OWS fleet and should also set us up for 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 costs increase from our February estimates, they continue to be in line with expectations. As depicted on Page 10 of our current presentation, a £10,000,000 slickwater well is now $6,800,000 which is about 5% more than our February estimates. As you can see, the services market in 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 II in the second half in response to the tightness. We think both price escalation and efficiency justify the response. Turning to well performance. Our £4,000,000 slickwater completions in the quarter continue to produce in line with our respective type curves as shown on Slides 56 of our presentation. The £10,000,000 and £20,000,000 Bakken jobs in Wild Basin have continued to outperform expectations.
In the 3 ports, we are also seeing the bigger jobs differentiate themselves. All of the high profit wells depicted on Page 5 are now on 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 the northern part of our Alger position. The well was completed with about 2,000 pounds of proppant per lateral foot and has been materially outperforming offset wells. As you can see on Page 6 of our presentation, the TIL well is significantly outperforming our core well performance for 4,000,000 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, 10,000,000 pound wells fracked and waiting on clean both inside and outside of Wild Basin. 4 of these wells are in Indian Hills. We look forward to reporting these results as the year goes on.
In the back half of twenty seventeen, we plan to move a frac crew into Red Bank, where we will test our high profit slickwater 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 £10,000,000 As a result, we have numerous tests across the position that will test profit loadings from £1,000 to £3,000 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 corn 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 $9,000,000 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 $1,150,000,000 to $1,600,000,000 However, we remain satisfied with our current liquidity and have chosen to keep elected commitments unchanged at the $1,150,000,000 at present. Coil differentials were in line with the Q4 of 2016. More recently, we have begun to see the effects of DAPL in the 2nd 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 DAPL 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 Q1 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 Q1.
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 Q1 was 78% of total production, which was exactly in line with our full year guidance. LOE for the Q1 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 and 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 $25,000,000 for the quarter, up 9% from the Q4 of 2016. And our gas plant 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.
We will now begin the question and answer session. The first question comes from Neal Dingmann of SunTrust. Please go ahead.
Good morning, gentlemen.
Good morning, Neal.
Could your Taylor just 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 $10,000,000 $20,000,000 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, is we announced 13 wells in the Q1, which leaves us about 63 for the balance of the year. And a good way to split that up is there will be 8 of what we'll call the really much larger frac jobs and that'll be split 4 will be £20,000,000 jobs and 4 will be £30,000,000 jobs. And then the balance of the wells, the 55, that will get you the total of 63 is split pretty evenly between £410,000,000 jobs.
Got it. And then just one last follow-up, just on that bringing the frac crew out, Do you anticipate besides kind of I guess, could you just talk about perceived expenses around that versus if you would go with the 3rd party, how you Michael, I guess, for you or Taylor, how you guys have sort of looked at that or the thought of bringing your own out when you sort of annualize 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 3rd 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've realized really better efficiencies in 3rd party crews.
Now as far as the internal benefit in credits, from the beginning, really the end of last year and coming into beginning of 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. Great. Thanks.
Thanks, Neil.
The next question comes from Subash Chandra of Guggenheim. Please go ahead.
Yes. Hi. Thanks. 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 steel level efficiencies that 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 $55 We're in the middle there of 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 anything on the MLP side of things.
Okay. Yes, thanks. I won't go into a follow-up on MLP. I just wanted 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.
No, Tom.
Got you. Thanks.
Thanks.
The next question comes from Mr. Michael Hall of Heikkinen Energy Advisors. Please go ahead.
Thanks. Good morning. Appreciate the time.
Hi, Colin.
I
guess just curious maybe first on this Teal well. I believe you 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 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, over on the east side of the basin where it says Alger, that well is located north actually of where Alger is 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 any of the 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 these same techniques and frac sizes.
Okay, great.
So do
you think you'd have potentially the South Cottonwood test later this year in the capital program or is that more likely next year?
Yes, it probably won't be this year. It's more likely next year. We do have, as we talked about, Red Bank test over on the west side of the business 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.
Right. Okay. And then I guess I was also just curious on Slide 5, the £4,000,000 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? 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 the life?
Yes. It's a pretty small data set 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 this is 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 £10,000,000 jobs and you've got 4 that will be £20,000,000 and another 4 that will be £30,000,000 jobs. So we're really excited to see what those results look like.
Great. Makes sense. And then I guess, I'm just curious on I'm sorry if I missed this somewhere, 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, Mike, off top of our head, but we'll get that to you. Hold on. It's so it looks like it's right about £5,000,000 average for the Q1 wells.
The next question comes from Graham Price of Raymond James. Please go ahead.
Hey, good morning guys and thanks for taking the question. 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 and as we run 4 rigs this year and then go into 5 rigs next year, we're still going to have the need for 3rd 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. Thanks. 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 Wild Basin, you'll start to see that normalize back.
So we kind of expect that 7% to 8% kind of throughout the year.
Okay, got you. That's it for me. Thanks guys.
Thanks.
The next question comes from John Nelson of Goldman Sachs. Please go ahead.
Good morning and congratulations on the update.
Thanks. 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 pay down or E and P acceleration. Is it fair to still see
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 the 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 with 50 of the 76 wells being slated for the back half of the year.
Obviously, you got a lot more activity in 2 and 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. Fair enough. I'll let somebody else hop on.
All right, John. Thanks.
The next question comes from Ron Mills of Johnson Rice. Please go ahead.
Good morning.
Hey, Ron. I have a quick question. When you talk about the second half completion, being are being weighted towards that period and still hitting the exit rate, that would seem to imply potentially entering 2,008 at a little higher trajectory than what may have been expected. Is there any potential impact or flow through of that relative to the 83,000 plus exit rate that you've 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 the guidance right now.
Okay. And then as it somewhat relates to Slides 56 and the amount of proppant you'll be using and the remaining completions, given the strong early data on the £10 +1000000 frac jobs, Just curious, is there something about those remaining 27 completions with £4,000,000 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. Are just continuing to understand the performance of these bigger jobs. And so if we continue to see strong results and we've got the option of up and out waiting to a higher percentage of the bigger jobs. 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 over capitalize.
We want to really understand the impact of these completions and then get them spaced in the right distances apart.
Well, I think a number of them are 3 Forged wells that we've got at the £4,000,000 level on 3 ports 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 moving to 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 or really kind of Wild Basin in 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 we need to understand the F and D cost, we've always said we'd 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 to 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.
Great. Thank you so much.
The next question comes from Gail Nicholson of KLR Group. Please go ahead.
Good morning. I'm just looking at the wells and how long they flow naturally. For the £4,000,000 jobs, do 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 4,000,000 pound jobs, but
gosh,
somewhere around 120 to 100 and 50 days, 180, just depends on the well, those 4,000,000 pound jobs flow. And in general, the bigger jobs flow longer.
Yes. Yes. And it's a big prop job, but still early times.
Does that surprise you that they flow that the larger jobs flow longer? Or is that 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 two things combined, induced pressure and then more effectively breaking up the rock would you 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 in regards to efficiencies with OWS, when you look at the current OWS crew, how many days does it take the current crew to complete a well versus a 3rd party fleet? Just trying to understand kind of the delta and the efficiencies.
Yes.
It's early time on picking up a 3rd party crew and we've got 1, as I said, working in Indian Hills. And as we've 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 natural work curve to try to get those guys up to what our expectations are kind of what we've been doing with our own crude. So it just takes a little bit of time for that to happen. In terms of the frac jobs for a £4,000,000 job, it's around 5 days per well.
Okay, great. And then the $6,800,000 well cost, the £10,000,000 job, that includes the cost savings by utilizing OWS, correct?
No, it does not. That's just it does not include the credits for OWS that we receive 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.
Okay, great. Thank you.
The next question comes from Greg Beatty of Bank of America. Go ahead.
Hey, guys. I think that's Greg Brody. Can you guys hear me?
Yes.
Okay. I was just wondering, I know you can talk about the Michelin transaction. I was just curious, if you thought there were any restrictions with your per year indenture to pursue a transaction. It looks like you have a big RP basket. I was just wondering what your thoughts were?
Yes, Greg, we're not talking anything about the MLP right now.
Okay. And then maybe just one other question. You added a line item to your revenue and cost, it's sort of this bulk purchases. I'd say it's pretty much a wash. I was just wondering what that is and
how 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. We'll buy some crude and then sell it.
And so really, it's 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.
That's it for me. Thanks guys. Thanks.
The next question comes from David Deckelbaum of KeyBanc. Please go ahead.
Good morning, guys. Thanks for taking my questions. And good luck in the pursuit of the OMS and congrats on sticking to your promise to not talk about it today. But curious, I guess, as you see the proppant, I guess, basin right now with going up to the £20,000,000 jobs, I guess I have two questions. 1, when you evaluate performance, are you also sort of adding variables of choke management with these?
Or I guess as you compare, for instance, with Johns Rood, the Rolts in there, 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 pull the wells back, 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 in the prop in the wells, so not trying to pull them too hard. And we're actually working, looking because we've got a number of these wells, trying to compare some different approaches to falling back with. Certainly not cranking them open. I'm trying to be fairly conservative.
With respect to the profit and grades of profit, as you go to the bigger wells, you get into the 10,000,000,000, 20,000,000 £30,000,000 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 Fortyseventy in them. And what we're doing there and that's on £10,000,000 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 Fortyseventy100 mesh.
And 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
the the market on that side of the equation. We've got a guy who's dedicated just to sand procurement. And from an availability standpoint, we hadn't seen a problem. Now the bigger the big thing around larger frac jobs because 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've got all the trucks to move it. And so it's really a logistical and planning game.
But so far we haven't seen a problem with supply. Now on the cost side, from late last year to in 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.
Thanks for the color guys.
Thanks. Thanks.
The next question comes from Blaise Angelico of Iberia.
Hey, good morning everyone. Appreciate the update. Good morning.
I believe you guys had previously expected
to complete a well in Red Bank in the second quarter. It sounds like that is shifting to later in the year. And apologies if I missed this, but what type of completion are you planning for the wells in that Red Bank area and just a number of total completions for 'seventeen? Just trying to get an idea of how we should think about how that area fits into the equation over the rest of 2017 and into 2018? Thanks.
So in Red Bank, we've got a mix of completions, but it will be it's a total in that area of about 12 wells. And of that 12, there's 7 right now that are planned to be £4,000,000 jobs. There's 3 that are £10,000,000 and then 2 that are £20,000,000 So we're trying to again test the full range, doing these £1,000 and £2,000 per foot loadings along with the £4,000,000 jobs. And timing wise, it is moved back a little bit in the second half.
Got you. Thanks. Appreciate it.
The next question comes from Stark Reni of RBC. Please go ahead.
Hey, guys. Thanks for taking my questions today.
You bet.
I was just hoping you guys might be able to provide a little additional color on how we should think about the activation of the second OWS crew and how it, I guess, changes your flexibility to adjust to various oil prices? Or maybe said another way is, does this kind of lock you in at a new base level activity? Or is there a point in which you'd 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, if you look on the downside, if you're in a get into a protracted lower price environment where we need to pull in our activity, From the planned activity levels at 76 completions for this year, part of that is 3rd parties. And so that would be the first thing that would drop if we pull in activity. If we need to, we can optimize just on the 2 crews. 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. 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 1 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. Thank you. And I guess what's your view on potentially adding another OWS crew in the future given there are ramping oil prices or desire for 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 3rd party and see where things go. I'm really not looking to add a 3rd crew at this point. But it's probably, I would guess to add, I mean, on that original frac spread, we spent $25,000,000 but that was with a much smaller horsepower requirement today to build a frac spread. It's probably more like $35,000,000 something like that. We've actually got about from an equipment standpoint about 1.5, maybe a little bit more than 1.5 from an equipment standpoint.
So that's the we've got $12,000,000 to $15,000,000 to get the supplemental equipment with sufficient backup to provide 2 crews.
Excellent. Thanks for the color, Jeff.
You bet.
The next question comes again from Michael Hall of Heikkinen Energy Advisors. Please go ahead.
Thanks for the follow-up. Yes, 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. Same thing going on in 2018.
Okay. Thanks guys.
The final question comes from Jeanine Wai of Citi. Please go ahead.
Hi, good morning, everyone.
Good morning.
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 3rd party crews along with that when needed. Obviously, that's going to with that much of a waiting of completion into 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 5th 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 5th 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 fracable 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 signed, but if they're not, they're super close. We've got both those rigs secured and will be available for us shortly.
Okay, great. Thank you for taking my call. Thanks.
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 proven track record of our team will position Oasis to continue to differentiate ourselves in this next chapter. Thanks for joining us today.