Good morning, ladies and gentlemen, and welcome to the Oasis Petroleum Third Quarter 2016 Earnings Conference Call. All participants will be in listen only mode today. Please note, this event is being recorded. Now, I'd like to turn the conference over to Michael Liu, Chief Financial Officer. Please go ahead.
Thank you, Nan. Good morning, everyone. This is Michael Liu. Today, we are reporting our Q3 2016 financial and operational results. We are 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 and other non GAAP financial measures. Reconciliations to our non GAAP financial measures to the applicable GAAP measures can be found in our earnings release and on our website. We will also reference our current investor presentation, which you can find on the homepage of our website. With that, I'll turn the call over to Tommy.
Good morning, everyone, and thanks for joining our call today. We entered this year knowing that 2016 would be a pivotal year for us as we focused on increasing capital efficiency and operational excellence, which have served as key drivers towards positioning us for organic growth within cash flow in 20172018. We made further progress in the Q3 as we completed 17 gross and 7.1 net wells in Wild Basin and brought on our gas processing plant in early October. That plant is now fully operational and we're moving oil and produced water volumes through their respective systems. We also have oil volumes moving through our pipeline to Johnson's Corner.
We began opening up the Wild Basin wells we had choked back as they waited on this infrastructure. Although most of the data is at restricted rates, those well results coupled with the white unit wells are included in the performance curves on Slide 11 of our presentation. It's this performance that led us to increase our Wild Basin Bakken type curve to 1,550,000 barrels of oil equivalent. This curve is based off of our £4,000,000 slickwater well, which now just costs $5,200,000 spud to rig release is down to 13 days in the Q3 and OWS's frac efficiency reached all time highs in the quarter. These well costs and EUR improvements in Wild Basin have combined to bring our single well F and D cost down into the $4 to $5 per BOE range, a reduction of 38% compared to our finding costs at the beginning of the year with $6,500,000 well costs and EUR expectations for Wild Basin at around 1,200,000 barrels of oil equivalent.
The team continues to optimize completion design with test programs including increased proppant loadings up to £20,000,000 and optimized proppant dispersion across the wellbore. Production on these design improvements is early time, so we don't have a lot of concrete results to share, but the early results from our wells supplemented by those of other operators in the basin give us confidence to continue to push our program with higher average proppant loads going forward. Our operational momentum in 2016 also transfers into our recently announced acquisition, which is expected to close December 1. This accretive transaction was a unique opportunity for Oasis continue to build on our large consolidated acreage positions in the Williston Basin at attractive valuations. With the company now in full development mode, we see significant synergies given the bolt on nature of that deal.
Our operational success combined with our October acquisition and equity offering provides further support to our ability to grow the business within cash flow in coming years, even in a relatively modest oil price environment. Oasis now has a very clear path towards meaningful delevering over the next 2 years down to a more normalized levels that we've spoken about in the past, and we expect to grow production at double digit rates through 2018 with oil prices in the mid-40s or above. Based on the strength of our team, our asset quality, the associated depth of our inventory and our strong financial position, we now anticipate a considerable increase in our E and P activity over the next 2 years. With that, I'll turn the call over to Michael.
Thanks, Tommy. As we reported 3 weeks ago, production for the quarter came in at 48.5 MBOE per day towards the high end of our implied 47 MBOE to 49 MBOE per day guidance range for the second half of the year. I would note that the range does not include our pending acquisition, which effectively adds 1 MBOE per day to the full year range. The midpoint of our revised full year guidance implies an estimated 4th quarter production of just over 50 MBOE per day on a standalone basis. When you add the 1 month of production from the pending acquisition, which is expected to close on December 1st, and implies total company production for the Q4 of just over 54 MBOE per day.
Crude differentials improved to the best levels of the year and moved to the bottom half of our $4 to $5 per barrel range as we recognize just $4.39 per barrel less than NYMEX. We've delivered basin leading differentials over the past couple of years by getting crude onto large gathering systems with many delivery options. We see strong fundamental support for our differentials to remain at these levels in 2017 with a bias towards growing even tighter when takeaway capacity increases next year. Depreciation improved by $2 per BOE in the 3rd quarter, driven by a combination of lower well costs and higher EURs. The significant work by our team on both the cost and productivity fronts is starting to really show up.
Aside from the October 18th acquisition, the other notable transactions from the Q3 were our convertible notes offering and subsequent Dutch tender auction in September. This combination of events was very much an opportunistic trade for Oasis, allowing us to refinance the majority of our 2019 notes, which was our nearest term maturity. At the same time, we were also able to materially reduce cash interest expense by approximately $17,000,000 annually. When you couple that with the open market repurchases from earlier in the year, it implies a total interest savings of more than $21,000,000 annually. Given our focus on both capital discipline and living within cash flow, this interest savings alone would allow us to drill and complete 4 incremental net wells next year at our $5,200,000 well cost, which equates to approximately 11% of our 2016 net completion budget.
Let me also note that we have the option to settle our new convertible notes on a net share basis, meaning that we intend to settle the full $300,000,000 principal in cash. The result is that these new securities are much less dilutive than a plain vanilla convert as our share price runs above the conversion price. Lastly, year to date, we have spent $130,000,000 on OMS capital, including $42,000,000 in the 3rd quarter, which is in line with our 2016 plan. Including our midstream spend in the 3rd quarter, we were basically free cash flow neutral and our year to date outspend has totaled about $25,000,000 compared to our planned outspend of $140,000,000 Our cumulative free cash flow since the beginning of 2015 remains positive by more than $40,000,000 With that, I'll turn the call over to Taylor.
Thanks, Michael. I wanted to spend my time today talking about Oasis plans for the next couple of years. 1st and foremost, Oasis has a tremendous flexibility around the timing of acceleration and growth. As we look to resume activity outside of Wild Basin, we retain the option to further invest in our midstream and well services business. And I stress that any such investment would only be made if it came with a compelling increase in EBITDA and project level returns.
A good example of this would be OWS. It feels like we are approaching the bottom on the well cost front and our expectation is that the pressure pumping market could tighten next year. Although in the Williston, we haven't seen that happen yet. As operators increase proppant intensity on wells, there will be a natural increase in demand for pressure pumping that would be amplified if there is an increase in rig count. Our single OWS crude supports our 2 rig program and keeps us insulated against potential cost inflation.
So as we ramp activity, we'll decide if and when it makes sense to add a second internal crew. This is a great example of the options reported to us we look to grow the company. Because of our industry leading cost structure and the productivity of our wells, we are poised to grow low double digits in a $45 world and grow at least in the mid teens in a $50 world. Should oil pricing remain at levels that justify increased activity, we plan on starting the process of drawing down our DUC backlog in the first half of twenty seventeen. Incremental completion activity should begin early in the year, and we expect production from DUCs to have a meaningful impact on 2017.
From there, we plan to add a 3rd rig next summer, and if prices cooperate, very likely a 4th rig next fall. Aided by the additional cash flow from our acquisition, we would plan to continue that growth momentum in 2018 and again, if prices cooperate, add a 5th rig into our program. Based on the strength of our asset, the depth of our inventory and our strong financial position, this is a prudent development plan. Furthermore, at these elevated activity levels, we have nearly 15 years of high quality inventory across our core and extended core positions alone. Our confidence in our asset and our ability to execute has increased dramatically this year.
When you couple that with our cost structure improvement, we are positioned to deliver impressive shareholder returns while living within cash flow. Our 2016 exit, including the acquisition, should be around 62,000 barrels of oil equivalent per day. By the end of 2017 and in a $50 WTI world, our E and P activity would double on an annualized basis compared to our full year 2016 program, increasing production as we exit 2017 to around 70,000 barrels of oil equivalent per day. Looking out 1 more year and staying in a $50 WTI world, based on the plan I just outlined, we would exit 2018 comfortably above 80,000 barrels of oil equivalent per day. Not only will this plan grow the company, it will improve our balance sheet and return our leverage metrics to the 2.5 times debt to EBITDA level by the end of 2018.
I would like to congratulate our team for all the hard work and innovation that we have seen throughout the business. Our team has made our Bakken assets some of the most cost resilient and highest rate of return assets in the Lower 48. This has put the company in a great position to comfortably grow within cash flow for the years to come. With that, we will open the line up for questions.
Thank you. We will now begin the question and answer session. Our first question comes from Jeanine Wai of Citigroup. Please go ahead.
Hi, good morning, everyone.
Good morning.
So just going back to your prepared remarks there, you mentioned that you retained your option to spend on midstream if you choose. I'm just wondering how that fits into your projections of growing within cash flow. Is that midstream spend something that we should be thinking that's outside of when you say within cash flow or would that be included in the total?
No, it would be fully inclusive. So it would include the midstream expenditures as well.
Okay. And then, how are you thinking about your free cash flow generation profile? I think some of it probably depends on docs and things like that with capital efficiency, but just wondering what the governor on that is. We do have some midstream spend in our estimates and knowing that it's all price dependent, we have you generating some free cash flow in 2017 and 2018, but just kind of wondering what the governor is on whether you would just spend everything you have or look to meaningfully underspend in the future?
Yes. Janine, the plan that Taylor laid out is to kind of think about a $50 world and that's basically spending cash flow on both E and P and kind of midstream kind of all CapEx for the company spending within cash flow and kind of growing to those rates that Taylor mentioned was which was the 62 exit for this year growing to around 70 next year and then comfortably above 80 by the end of 2018. That's all spending kind of inside of cash flow, right? And so that's not really generating a lot of excess cash in that $50 world, but it's not spending outside of the cash flow either.
Okay, great. Thank you.
Thanks.
Our next question comes from Neal Dingmann of SunTrust. Please go ahead.
Good morning, guys. Nice quarter. Good
morning, guys. Thanks.
Maybe Tom for you or Taylor, I mean, you mentioned in the prepared remarks about the $5,200,000 in the was it 15.50 MBoe on the Wild Basin. So I'm just looking at the map. Is that fair to say now is that going to be kind of the general results or general costs, I should say, in type curve if you move over to what you've got left in Indian Hills or if you move to the East to Elgar or is that just I'm just wondering, I guess, how specific is that to the Wild Basin versus your existing and unless you even throw in there the acquisition as well?
So it's the well cost is going to apply for that whole area. And so we'll be at 5 point $2,000,000 as we said. We think we'll continue to get efficiencies and then a non service cost increasing world continue to bring that cost down. On the well EURs, as we've shown in the past, the Indian Hills area isn't quite as prolific as Wild Basin. So that the type curve that we talked about at 1.55 at this point is really more focused on Wild Basin.
However, as you continue to go to the east, when you look at some of the acreage that we just picked up from SM, most of that as you go to the east and then some of our properties Alger as well will likely have those higher EURs. We don't have all the data on those wells yet, but we would expect them to be more along those lines. And then as I said, as you go back to the West, it's going to drop off a bit in Indian Hills. It's a little shallower there. GRs are a little lower as well.
Keep in mind, Neal, that that's we continue to play with things and the data that we show is off of the £4,000,000 5,200,000 well cost. So as we start to push proppant loads and efficient placement along the wellbore, then we possibly can push that up a bit across the entire position, but a little bit early to tell.
And that's a good point, Tom. I was just going to ask that as a follow-up. On the hands completions, I know you all have talked about it. I know some of your peers are doing what I guess even over £10,000,000 etcetera. How quickly do you anticipate pushing that?
And do you think we're getting close to diminishing returns there? Or we're still a bit away from that?
Yes. Taylor can add some color, but I mean, we're already well down that path. It's just a point at which we can give you guys good feedback on what that looks like. I think, Taylor, half the wells for this year or for 2016 have some kind of enhancement over those base jobs?
Yes, that's correct. Half of the completions this year will have enhanced completion techniques. And as we've been talking about, the proppant loadings are biased higher and we've tested 10 or as high as 20,000,000 pounds like Tommy has talked about. So we're just trying to find the right cost and intensity trade off. And as we get more data, we'll be able to be better able to make that call.
Keep in mind that the first wells that we tested with bigger loadings, the 20,000,000 pound job has been on about 4 months, but half of that period was at restricted rates until we got the infrastructure online. So we like to have just 4 to 6 months of production without that restriction behind it.
And Neil, keep in mind too that our cycle times in these full field development pads, our cycle time is expanding a bit. So it takes a little bit longer to get good data. But the other encouraging thing is from some of the other operators, those they've seen some very encouraging results in what we call the extended core. So we're pretty excited about that as well.
Tommy, with that cycle time and just some of these bigger completions, I mean, you guys laid out very nicely here for the next couple of years the production. Will that be a bit lumpy or could it still be kind of bit linear into that?
I think it'll be more I don't think it will be I mean, it's always a bit lumpy, but I wouldn't expect it to swing wildly. I think that as you think about trajectory, what I would do is go back to the timing of incremental activity that Taylor laid out in terms of when we bring additional rigs on.
Got it. Thanks for the details guys. Next quarter.
You bet. Thanks.
Our next question comes from Michael Hall of Heikkinen Energy Advisors. Please go ahead.
Thanks. Congrats on a solid quarter. Appreciate the time.
Thanks, Mike.
I guess, I want to kind of zero in a little bit more on some of the things you already talked about. But in particular, I'm just trying to think through kind of cycle times that you started to get at. What would you say is a fair assumption around the number of wells that can be completed per rig per year, based on your current thinking and on the kind of modeling outline on Slide 9?
Well, the wells per rig per year is, it's just as we're modeling, it's right around 25%, maybe a little bit over that.
And And is that drilled or completed, Taylor?
It's really, really the same.
Okay. It's the same at this point. Pretty much the talent. Great. And in the past, I believe you talked about the 2 frac spreads that you have that they could support 5 rigs.
Is that still a fair way to think about that?
Yes, that's pretty close. It's right now, we've got the 1 frac spread with the 2 rigs. As you go to 5 with the pace of increased pace of drilling, it may take you a little bit more than 2 frac crews because we're fairly balanced between the 2 rigs and the 1 frac crew. So it could be just a bit over.
Especially with some of those higher intensity completions, Michael. That's another thing that adds to the need for more frac capacity.
That makes sense. Suffice to say, covered through 2017, it sounds like. And then any commentary around like what are your base decline assumption is or what you're modeling around base decline coming out of 2016 and then again out of 2017 within that long range outlook you provided?
You're going to be right around that 30% kind of neighborhood on base declines. And then what we had historically said is over the last couple of years with a more flattish type production curve, if you're only running 2 rigs and you're staying at that kind of now year end 62,000 a day, your declines are going to decrease over time. But as we start growing again, obviously, those decline rates are going to kind of stay in the same range, in that kind of 30% range.
Okay. And then last one on my end, I'm just trying to think through kind of broadly for the basin, but obviously specifically for you all as well. As you move towards these new completion designs, our understanding is it's much about near wellbore stimulation as it is just putting a bunch more profit in the well. And in that context, I'm wondering if you guys are revisiting spacing assumptions at all given that a lot of the pilots that were done in the Williston were on older completion technologies. Just curious if you had any thoughts on that?
Yes, Michael, we continue to look at the spacing as we go to these higher intensity frac jobs. So far, we made the shift from the hybrid completions to these high intensity 4,000,000 pound jobs and ended up not seeing appreciable difference in spacing, we don't think, just probably better recoveries. So as we go to these bigger jobs, the sand loadings increase, that's one of the things that we're going to continue to keep an eye on. Don't have a view just yet. We need more data and obviously doing not only testing, but a lot of simulation and subsurface work to draw the conclusions on that front.
And so it will be something we'll be talking about more as we get into 'seventeen and beyond.
Okay, great. Well, I appreciate the time and congrats on the momentum, guys.
Thanks Mike.
Thank you. Our next question comes from John Freeman of Raymond James. Please go ahead.
Good morning guys.
Hey, John.
The first question, on these much higher intensity frac jobs that you're starting to do, through this preliminary kind of longer term guidance that you've given, what sort of a mix do you think is appropriate for 2017 for these much bigger high intensity jobs above the kind of $4,000,000 If we consider $4,000,000 now sort of the standard job, these 9,000,000, 10,000,000 plus, what percentage do you think of the wells that would be in 'seventeen?
At this point, we don't have a good percentage. And what we're trying to figure out is that we think it's going to you're going to be on average larger than 4 going forward. You end up being at 6 or 8 or 10. Where do you fall out in that cost first benefit? But I would think about, as I said, we've tested 50% of our wells with enhanced completion techniques.
I would think we'd do at least that amount next year, but probably focused on the things that are working for us.
And this may be early, but on the bigger ones that you've done, call it, let's say, dollars 8,000,000 or something, what's been sort of the cost difference versus that standard £4,000,000 job?
So it is early on that front, but when you look at kind of the same, same well, same number of stages, dollars 4,000,000 versus the $10,000,000 it's about
close to
a 20% uplift in cost around $1,000,000 And so we think that, like you said, this isn't normalized. We haven't done a large group of these. They're test wells. So we'll have better uplift numbers going forward. But early time, it's somewhere under at or around a 20% increase in cost.
I appreciate it. Well done, guys.
Thanks, John. Thanks.
Okay. Thank you. Our next question comes from Jason Smith from Bank of America Merrill Lynch. Please go ahead.
Good morning, everyone, and thanks for the color on the outlook. Just coming back to Janine's question, I appreciate that under a $50 scenario and the plans you've laid out, you're not generating much free cash flow. But if hypothetically oil does move higher and you do generate free cash flow, how do you balance future production growth midstream spend and paying down debt? And I guess where I'm going is, where does that first incremental dollar go?
Then you get into a place where you're trying to figure out where the best utilization is as the market environment changes, and it's hard to predict what that is. I think we may be throttled a bit just based on the plan that we've got laid out at this point. Can we go and and instead of 4 rigs at the end of next year, run up to 6. I think we're going to kind of feel it as we go to try to do everything we can to maintain to hold on to the efficiencies that we've gained, right, which you always run the risk of losing that as you really start to ramp up activity and monitoring service costs. So you're going to have a bit of a natural throttle in that, but then and I mean, you can always put it back into the balance sheet.
And so to commit on how I think about that at the end of 2017, it's a little bit early with all the moving parts. But certainly, given the way we've modeled it, we've got a very real option to be able achieve this kind of growth rate, maintain our efficiencies, plus also then reduce some of the debt load even further than what we've already talked about, which is very attractive on a metric basis in 2018, but more maybe a little bit better.
Got it. Appreciate that. And then just coming back to the comment around growing OMS and OWS, Taylor, you talked a little bit about OWS. But with Wild Basin online, what other opportunities are there on the OMS side right now?
So, OMS is going to be really building out our gathering systems, connecting more wells as you go. So in Wild Basin, it's going to be all the gathering systems, oil, gas and water. And then on top of that, you've got some opportunities with the new acquired assets, the SM assets. If you look on the map on Page 10 of the presentation, you can see the properties in blue that are really close to Wild Basin. So those give us some opportunities to expand the footprint for Wild Basin and capture some incremental volumes there.
Thanks. Congrats again, guys.
Thanks.
Our next question comes from Biju Perincheril of Susquehanna. Please go ahead.
Hi, good morning. Good morning, Sebastian. When you're looking at this, the newer completions, have you tested wells on the western side of the acreage and what you would characterize as the Fairway acreage and what kind of view on what kind of upside you could see from the numbers that you're showing on Slide 10?
So
we have tested our £4,000,000 slickwater jobs in that area in the fairway and also in the extended core. And if you look on on in the back of our presentation on Page 20, you can see the results for those wells in those areas. Now we haven't tested in those areas the higher profit loading. So these 10,000,000 pound jobs, we haven't tested. We've seen some of our competitors have tested some bigger jobs in those areas and we've looked at the results and they're encouraging.
So that's one of the things as we move forward into 2017 2018 as we pick up the pace of activity, we're likely to try some pilots with some of these higher intensity completions in those areas.
In that area, would you expect similar uplift as you're seeing in the core? Or do you think the uplift would be something lower because of the rock quality? Yes.
It's hard to tell at this point, but what I can tell you is, for example, in Montana, when we were doing a cross link hybrid job there with £4,000,000 job and then when we stepped that up to £4,000,000 slickwater or we also did a larger high volume prop version of a job. We saw the increase the EURs and those wells go from around 4 to 450 up to 6.25 MBOE. So nice uplift just on that first step in intensity. So we'd be hopeful that we'd see another increase. But we just got to try the pilots to confirm it.
Got it. Thank
you. Thanks.
Our next question comes from Ron Mills of Johnson Rice. Please go ahead.
Hey, thanks for all the comments. Just a couple of quick ones. On the cycle time, as you potentially move to
£10 +1000000 of propane,
Taylor, any kind of ideas in terms of what that can mean to cycle times? I assume they take longer to complete and just does that how much time do you think that could add?
So you do a £10,000,000 job is going to add probably 1 to 2 days on to the completion. And to do our base job is around 4 to 5 days. And so you're going to add some time, but it's not a huge increase.
Okay. And then from a development standpoint, you've always talked about full unit development. What's your current plan in terms of Bakken versus Three Forks as you move on to a DSU?
So in the core, it continues to be evenly spaced between Bakken and 3 fourth wells. And the density that we've been testing is generally between been between about 11 15 wells per spacing unit. So whichever it is, you can think about it, as I said, being evenly split between Bakken and Three Forks. We have continued to test some lower benches along the way. And so we're still doing a few second bench wells.
And based on that, we may elect to add a few more of those going forward, but we'll get more results before we do that.
Okay. And then when you look at 2017, two questions on the DUCs and just drilling plans. How much of your plus or minus 80 DUCs are located in your core and extended core and even fairway if you have that. And if you look at the 2 rigs going to 4 rigs, is the plan to really keep all 4 of those rigs in your core area versus rather even the extended core?
Okay. So as far as the DUCs are concerned, there's 80 wells now. We brought it down a little bit from last quarter. We were at 83. The ratios are about the same.
You still have about 20% of those that are outside the core. And most of that 20% is in the extended core. You got a handful that are in the fairway. And then the other 80% are all in the core. As far as the rig activity as you pick up, as we go from 2 to 4 rigs, we're going to move those additional 2 rigs into core areas.
So it will be one likely in Indian Hills, City of Williston area and another rig in the Alger area over on the east side.
Perfect. All right. I appreciate all the help. Thanks.
You bet. Thanks.
Our next question comes from Kashy Harrison of Simmons Piper Jaffray. Please go ahead.
Good morning and thanks for taking my question. Great color on 2017 2018. I was just wondering if you all could provide some sensitivities for if commodity prices are either better or worse than you anticipate going forward?
Yes. Kashy, what we talked about was still sub-forty percent. You're going to probably stay more at a 2 rig level. You're going to stay production is going to kind of keep flat in that scenario spending within cash flow in call it $45 range instead of call it mid teen type growth. It's going to be more like call it 10 ish percent type growth.
And so you're going to scale back just a little bit, stay within cash flow once again. And then what we've talked about this time is further tightening and getting a little bit better. We had historically said kind of mid teens growth at kind of $55 Now we're kind of talking about that in the $50 world. Obviously, if it goes higher or not, Tommy mentioned that we'll just have to see if we continue to accelerate or if we go with one of the other options. Obviously, with our projects and the rate of return that you have, that's if you can keep that kind of efficiency, that's where you'll spend it most likely first.
But we're going to keep a keen eye on making sure that we can keep the efficiencies and well costs down.
Got it. Thanks for that. And then just for clarification, the longer term forward guidance does not incorporate the higher intensity and completions, right, in your production estimates?
Yes. For the most part, we're looking at just kind of the £4,000,000 job and that's what we have some good certainty around in terms of well productivity. If we go to these higher proppant loadings and we see a large increase and we decide to go with that on a kind of fulsome basis, we'll build that into both the capital expenditure side, the increases there as well as the productivity side.
All right. Thank you. That's it for me.
Thanks. Thanks.
Our next question comes from David Deckelbaum of KeyBanc. Please go ahead.
Good morning, guys. Thanks for fitting me in.
Hey, David.
And congrats on all the improvements you guys have made in the road deck to getting that 2.5 times levered.
Thanks.
Just curious on the as you guys model that, you talked about the rig additions. I just wanted to get some color, if I missed it, on where the 3rd, 4th, 5th rig would be going. And then in conjunction with that, how do you guys sort of model with your pace of midstream investments in Wild Basin sort of what the MAX rig program would be in that specific area?
Okay. So the as we add the rigs going to 45 rigs, one of those rigs would be over in the Indian Hills City of Williston area. And then, that would be the 3rd rig. The 4th rig would be in the Alger area. And likely, when we bring the 5th rig in, it would be also over in the it'd be in the core, either in Alger or in that Indian Hill City of Williston area.
The other thing that we talked about just a little bit earlier, we'll be doing as we are ramping those rigs back up is doing some tests outside the core, testing some of these completion techniques. So some of that's going to be mixed into that count as well. But as we add them back initially, all of them will be in the core.
I guess, Taylor, can you quantify in terms of sort of a percentage impact from the higher intensity completions? I know that you have data and maybe you have smaller samples in certain portions, but where have you seen the best response so far across the entire acreage position?
Well, as you look at the talk about, as you look at going from hybrid completions, the older style, the high intensity, really saw a good reaction across the whole acreage position. The one exception to that is in North Cottonwood on the east side. So the far northern part of that position haven't seen quite the impact on high intensity completions, but the rest of the acreage we have. Now as you go even larger high intensity completions, so the bait job I'm talking about is £4,000,000 slickwater. As you go to a £10,000,000 and we'll see where we fall out as we talked about or bigger, it could be a little bit smaller than the 10.
10. We still don't have all the data in the quarter. We're encouraged by what we've seen so far and by what we've seen by other operators. And we think if you see good reactions in the in in the extended core, for example. And as Tommy talked about earlier, there's some third party data with some of these bigger completions in our extended core that's, it's pretty darn encouraging.
So, that said, we will be testing those in other areas as well.
And then
just the last question for me, just to clarify. The way that you guys present type curves right now, you gave the $1,500,000 plus equivalent curve for Wild Basin and then just over $1,000,000 has been sort of your, I guess, base high volume £4,000,000 completion within the quarter. Does that $1,000,000 include that includes the impact of the higher EUR wild basin curve as well, right? So the or should we think about the average between Aounser, Indian Hills and portions of South Cottonwood being 1,000,000 barrel equivalent?
So that 1,000,000 barrel equivalent type curve, it was $10.50 and that does not include the new uplift, the 1,500,000 barrel wells, and we did that originally. It was based on Wild Basin at 1,200,000 barrels. And so that type curve across the core, it's forward looking at our inventory with what we anticipate for the £4,000,000 frac jobs, not the larger jobs. We will update that here going forward at the end of the year. And so you can expect that to go up.
Perfect. Thanks guys.
Thanks.
Our next question comes from David Tamarin of Wells Fargo. Please go ahead.
Good morning. And like I said, that's been a good quarter, a good actually a good string of quarters. Thanks. Just everything has been asked on upstream side, so let me just hit something on
the midstream.
And actually 2 things. Midstream, any thoughts around monetization was on the table for a while. How should we be thinking about that? And then can you quantify I think Taylor you alluded to it, but can you quantify what would drive the margin expansion in kind of 2017, 2018 like the different pieces or what kind of magnitude we should be thinking about?
Yes. What I would say on the midstream business is that I think you always want to consider all of the options with respect to that business. Obviously, it's we've done really well on it. It's helped us to manage our business risk and that is very important to us. And it's versus if you were to step back a year ago, when you start talking about the Wild Basin project and you're going to get all of the, what I call, the yeah, buts, whether that's with respect to cost, whether that's with respect to timing of the project and all those things.
That's all behind us now. And so the thing is up and running. We've got it there, spending in line with our original budget outside of a few scope change items that we've done. And so I would say that it gives you a lot more certainty around it, which provides more optionality. But it's not something that we're running out to do right now.
Okay. Sorry, go ahead. Sorry, go ahead. Well, I was just going to ask any quantification on the margin side then, Tommy, or whoever wants to take that?
Yes. As far as the margin expansion, the thing we're talking around netbacks. And so one of the things we have talked about is, we think the advantage of getting connected to DAPL when DAPL does come online and that could really improve pricing in the basin. We've seen it, the margins or the deducts being in the $4 to $5 range. We're in the low 4s for this quarter.
And we expect that to tighten as DAPL comes online, which we hope will be in the first half of twenty seventeen.
And margins across the whole business should continue to get better, Dave. As you think about a growing production profile, G and A per BOE goes down. Taylor mentioned differentials go down. So realized price better, LOE should continue to go down. So across kind of all pieces of our business and then with OMS online, you're going to get slightly better realized pricing as well.
So you're going to get pieces across the board that are going to be positive from a margin standpoint.
Okay. And Michael, you're going to get some OBO as well, volumes coming into that?
Yes. Right now, on the OMS side, obviously, it's just our operated wells, but we do have OBO on that, that adds to that midstream EBITDA.
Okay. And I know you guys talked a little bit about this with the recent acquisition, but can you talk about your thoughts as far as potentially any divestments? I know there's been some talk around, but there has been some JVs up there, I guess, from other players. How should we think about something similar to what Continental did or something along those lines?
Yes. We haven't really spent a whole lot of time on that at this point. I mean, we have done some already, as you know. And I think it's important for us to now look at the entire asset base and see if there is anything that makes sense, but there's nothing that's on the plate at this point. With the SM deal, then we got some small cleanup stuff, but it's tens of millions, not 100 of millions.
Okay. Thanks for the additional color. You bet.
Our next question comes from John Nelson of Goldman Sachs. Please go ahead.
Good morning and for all the detailed commentary. Always very thoughtful.
Thanks, John.
My question is, is there a commodity price at which either rigs 3, 4
or 5 would go to the extended core?
Right now, the way we're thinking about it is, as we pick those rigs back up, we're going to put them in the core. One of the things that continues to become more interesting as you get into 50, 55 and certainly 60, the economics, and again, you can look back on Page 20, for those areas become really compelling. And as we do pilots in some of those areas with some of these enhanced completion techniques, Our hope is we just drive those economics up even further. So improve the economics, which as you're suggesting would mean extending into some of those areas earlier. But we'll, as I said, start out in the core, test in those other areas and confirm what we think we'll see in terms of returns and then fan out from there.
Okay. And then just we talked a little bit about midstream spending earlier. Is there kind of a ballpark that we should be thinking about for 2017 on the midstream side? What we've said historically, John, is kind of in that 50 to 70 range right now. And then, Taylor and Tommy have mentioned, we're going to continue to look at the SM acreage, look at our development plan and see if we need any additional spending.
But obviously, any additional spending on top of that is going to come with returns on that capital. So if we decided to do something, it would come with higher EBITDA levels,
but we
don't have any definitive plans yet. Great. That's all I had. Congrats again.
Thanks, Chad.
Our next question comes from Gail Nicholson of KLR Group. Please go ahead.
Good morning. I'm just curious how thick is your pay zone in the middle of Bakken at Wild Basin versus the pay zone at Indian Hills?
The thickness in the middle Bakken
Bakken, between Indian Hills and
Wild Basin, it's not a lot different. Wild Basin is deeper. And if you look at the whole column and so as you get into the Threefour and the lower benches of the Threefour, the charge is going to be a little better in Wild Basin. And as I said, you got higher pressure because it's deeper. So all those things combined, we're seeing better wells.
And then when you look at the 30% outperformance versus your initial expectation that Wild Basin, do you feel like what's your thoughts about taking a potential EUR haircut in order if you wanted to down space that and go tighter spacing at Wild Basin versus saying no, we'll just take the higher EUR and current inventory versus taking a lower EUR and increasing the inventory?
Yes, that's the analysis we're working on, which is around what is the proper spacing. As you get into higher pricing, you've always got that lever and option of going at higher density and accelerating reserves. But that's an analysis that we're going to continue to make as we're doing these completions in Wild Basin. Like I said, currently, we're spaced at around 11 to 15 wells per spacing unit.
And then just lastly, when you look at the enhanced completion techniques that have been employed in the basin, where do you think oil recovery factors are today? And where do you think they could potentially go with, the further enhancements that everyone is testing out?
Recovery factors are With these types of completions and density of spacing that we're talking about, we think they're probably in generally kind of 15% to 18% range. And we'll continue to monitor some areas that's lower in that, could be closer to 13, but 15 to 18 in the core with the density we're talking about, we think are pretty good numbers.
Great. Thank you.
Thanks, Gail.
This concludes our question and answer session. I'd now like to turn the conference back over to Tommy Nusz for any closing remarks.
Thanks. Our success in the Q3 and everything else we've done throughout 2016
leaves us in
a position of considerable strength, both financially and operationally. It is truly an exciting time for Oasis and we look forward to continuing to demonstrate the strength of our team, the quality of our asset base and the associated growth potential of our company for years to come. Thank you.