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. Should you need assistance, please signal a conference specialist by pressing the star key followed by 0. After today's presentation, there will be an opportunity to ask questions. To ask a question, you may press star and then 1 on your telephone keypad. To withdraw your question, please press star, then 2. These instructions will be repeated. Please note, this event is being recorded. Now, I'd like to turn the conference over to Michael Lou, Chief Financial Officer. Please go ahead.
Thank you, ma'am. Good morning, everyone. This is Michael Lou. Today, we are reporting our third quarter 2016 financial and operational results. We are delighted to have you on our call. I'm joined today by Tommy Nusz and Taylor Reid, as well as other members of the team. Please be advised that our remarks, including the answers to your questions, include statements that we believe to be forward-looking statements within the meaning of the Private Securities Litigation Reform Act. These forward-looking statements are subject to risks and uncertainties that could cause actual results to be materially different from those currently disclosed in our earnings release and conference call. Those risks include, among others, matters that we have described in our earnings release, as well as in our filings with the Securities and Exchange Commission, including our annual report on Form 10-K and our quarterly reports on Form 10-Q.
We disclaim any obligation to update these forward-looking statements. During this conference call, we will also make references to adjusted EBITDA 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 2017 and 2018. We made further progress in the third quarter 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 1.55 million BOE. This curve is based off of our 4 million pound slick water well, which now just costs $5.2 million. Spud to rig release is down to 13 days in the third quarter, and OWS's frack 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&D costs 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 $6.5 million well costs and EUR expectations for Wild Basin at around 1.2 million BOE. The team continues to optimize completion design with test programs, including increased proppant loadings up to 20 million pounds and optimized proppant dispersion across the wellbore. Production on these design improvements is early times, 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 1st. This accretive transaction was a unique opportunity for Oasis to 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 two years down to 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&P activity over the next two years. With that, I'll turn the call over to Michael.
Thanks, Tommy. As we reported three weeks ago, production for the quarter came in at 48.5 MBOE per day towards the high end of our implied 47 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 one MBOE per day to the full-year range. The midpoint of our revised full-year guidance implies an estimated fourth quarter production of just over 50 MBOE per day on a standalone basis. When you add the one month of production from the pending acquisition, which is expected to close on December 1st, it implies total company production for the fourth quarter 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 recognized 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 third 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 third quarter 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 million 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 million annually. Given our focus on both capital discipline and living within cash flow, this interest savings alone would allow us to drill and complete four incremental net wells next year at our $5.2 million 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 million 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 million on OMS capital, including $42 million in the third quarter, which is in line with our 2016 plan. Including our midstream spend in the third quarter, we were basically free cash flow neutral, and our year-to-date outspend has totaled about $25 million compared to our planned outspend of $140 million. Our cumulative free cash flow since the beginning of 2015 remains positive by more than $40 million. 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. First 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. 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 crew supports our two-rig program and keeps us insulated against potential cost inflation. 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 afforded to us as 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 2017.
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 third rig next summer, and if prices cooperate, very likely a fourth 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 fifth rig into our program. Based on the strength of our assets, 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&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 one 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 would 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. To ask a question, you may press star then one on your telephone keypad. If you are using a speakerphone, please pick up your handset before pressing the keys. To withdraw your question, please press star then two. At this time, we will pause for a moment to assemble our roster. Our first question comes from Jeanine Wai of Citigroup. Please go ahead.
Hi. Good morning, everyone.
Morning.
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. It would include midstream expenditures as well.
Okay. How are you thinking about your free cash flow generation profile? I think some of it probably depends on DUCs and things like that with capital efficiency, just wondering what the governor on that is. We do have some midstream spend in our estimates, knowing that it's all price dependent, we have you generating some free cash flow in 2017 and 2018. Just wondering what the governor is on whether you would just spend everything you have or what's the meaningful underspend in the future?
Yeah. Jeanine, the plan that Taylor laid out is to think about a $50 world. That's basically spending cash flow on both E&P and midstream, all CapEx for the company, spending within cash flow growing to those rates that Taylor mentioned, which was, the 62 exit for this year, growing to around 70 next year, then comfortably above 80 by the end of 2018. That's all spending inside of cash flow, right? That's not really generating a lot of excess cash in that $50 world, it's not spending outside of the cash flow either.
Okay, great. Thank you.
Thank you.
Thank you.
Our next question comes from Neal Dingmann of SunTrust. Please go ahead.
Morning, guys. Nice quarter.
Hey Neal, thanks.
Maybe, Tommy, for you or Taylor, you mentioned in the prepared remarks about the $5.2 million and the, what is it? 1,550 MBOE on the Wild Basin. I'm just looking at the map. Is that fair to say now, is that going to be the general results or general cost, I should say, in type curve if you move over to what you got left in Indian Hills or if you move to the east to Alger? I'm just wondering how specific is that to the Wild Basin versus your existing and then let's even throw in there the acquisition as well?
The well cost is going to apply for that whole area, we'll be at $5.2 million as we said. We think we'll continue to get efficiencies and then a non-service cost increase, and we'll 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. That 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 in Alger as well will likely have those higher EURs.
We don't have all the data on those wells yet, we would expect them to be more along those lines. 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. GORs are a little lower as well.
Keep in mind, Neal, that we continue to play with things and the data that we show is off of the 4 million pound, $5.2 million well cost. As we start to push proppant loads and efficient placement along the wellbore, we possibly can push that up a bit, across the entire position. A little bit early to tell.
Good point, Tommy. I was just going to ask that as a follow-up on the enhanced completions. I know you all have talked about it. I know some of your peers are doing, what, I guess even over 10 million pounds, et cetera. 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?
Yeah. Taylor can add some color, 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.
Yeah, that's correct. Half of the completions this year will have enhanced completion techniques. As we've been talking about the proppant loadings are biased higher, and we tested 10 or as high as 20 million pounds, like Tommy's talked about. We're just trying to find the right cost and intensity trade-off. As we get more data, we'll be better able to make that call. Keep in mind that the first wells that we tested with bigger loadings, the 20-million-pound job, has been on about four months. Half of that period was at restricted rates until we got the infrastructure online. We'd like to have good four to six months of production without that restriction behind it.
Yeah. Neal, keep in mind too that our cycle times in these full field development pads, our cycle time's expanding a bit, so it takes a little bit longer to get good data. The other encouraging thing is from some of the other operators, they've seen some very encouraging results in what we call the extended core. We're pretty excited about that as well.
Tommy, with that cycle time and just some of these bigger completions, 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 a bit linear into that?
It's always a bit lumpy, 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. Nice 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 zero in a little bit more on some of the things we already talked about. In particular, I'm just trying to think through cycle times like 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 modeling outline on slide nine?
The wells per rig per year is, as we're modeling, it's right around 25, maybe a little bit over that.
Is that drilled or completed, Taylor?
It's really the same.
Okay. It's the same at this point.
Pretty much the same.
Great. In the past, I believe you talked about those two frac spreads that you have, that they could support five rigs. Is that still a fair way to think about that?
Yeah, that's pretty close. Right now we've got the one frac spread with the two rigs. As you go to five with the increased pace of drilling, it may take you a little bit more than two frac crews because we're fairly balanced between the two rigs and the one frac crew. It could be just a bit over.
Especially with some of those higher intensity completions, Michael.
Yeah.
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. Any commentary around what your base decline assumption is? 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% neighborhood on base declines. What we had historically said is, over the last couple of years with a more flattish type production curve, if you're only running two rigs and you're staying at that now year-end 62,000 a day, your declines are going to decrease over time. As we start growing again, obviously, those decline rates are going to stay in the same range, in that 30% range.
Okay. The last one on my end, I'm just trying to think through 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 as much about near wellbore stimulation as it is just putting a bunch more proppant in the well. 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 have any thoughts on that.
Yeah, 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 million pound jobs, it ended up not seeing appreciable difference in spacing, we don't think. Just probably better recoveries. As we go to these bigger jobs, as 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, obviously you're doing, not only testing, but a lot of simulation and subsurface work to draw the conclusions on that front. It'll be something we'll be talking about more as we get into 2017 and beyond.
Okay, great. Well, I appreciate the time and congrats on the good 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 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 4 million? If we consider 4 million now sort of the standard job, these 9, 10 million+, what % do you think of the wells that would be in 2017?
At this point, we don't have a good percentage. What we're trying to figure out is that we think you're going to be, on average, larger than four going forward. Do you end up being at six or eight or 10? Where do you fall out in that cost versus benefit? 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.
This may be early, but on the bigger ones that you've done, call it, let's say, $8 million or something, what's been sort of the cost difference versus that standard 4 million pound job?
It is early on that front, but when you look at the same well, same number of stages, 4 million versus the 10 million, it's about close to a 20% uplift in cost, around $1 million. 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 timing, somewhere under, at 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, thanks for the color on the outlook.
Morning.
Just coming back to Jeanine's question, I appreciate that under a $50 scenario and the plans you've laid out, you're not generating much free cash flow. 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? I guess where I'm going is where does that first incremental dollar go?
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 instead of four rigs at the end of next year, run up to six? I think we're going to feel it as we go to try to do everything we can to maintain, to hold onto the efficiencies that we've gained, which you always run the risk of losing that as you really start to ramp up activity, and monitoring service costs. You're going to have a bit of a natural throttle in that, but then, you can always put it back into the balance sheet.
To commit on how I think about that at the end of 2017, it's a little bit early with all the moving parts. Certainly, given the way we've modeled it. We've got a very real option to be able to 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. It may be a little bit better.
Got it. Appreciate that. 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?
OMS is going to be really building out our gathering systems, connecting more wells as you go. In Wild Basin, it's going to be all the gathering systems, oil, gas, and water. 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. 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.
Morning.
Quick question. When looking at the newer completions, have you tested wells on the western side of your acreage in what you would characterize as the fairway acreage, and give a view on what kind of upside you could see from the numbers that you're showing on slide 10?
We have tested our 4 million pound slick water jobs in that area, in the fairway and also in the extended core. If you look in the back of our presentation on page 20, you can see the results for those wells in those areas. We haven't tested in those areas the higher proppant loading, so these 10 million 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. That's one of the things as we move forward into 2017 and 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?
Yeah, it's hard to tell at this point. What I can tell you is, for example, in Montana, when we were doing a Crosslink hybrid job there with a 4 million pound job, and then when we stepped that up to a 4 million pound slick water, or we also did a larger high volume proppant version of a job, we saw the increase in the EURs in those wells go from around 4 to 450 up to 625 MBOE. A nice uplift just on that first step in intensity. We'd be hopeful that we'd see another increase. 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 quick ones. On the cycle time, as you potentially move to 10-plus million pounds of proppant, Taylor, any ideas in terms of what that can mean to cycle times? I assume they take longer to complete, how much time do you think that could add?
Doing a 10 million pound job is going to add probably one to two days onto the completion. To do our base job is around four to five days. You're going to add some time, but it's not a huge increase.
Okay. 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?
In the core, it continues to be evenly spaced between Bakken and Three Forks wells. The density that we've been testing has generally been between about 11 and 15 wells per spacing unit. 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, 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. When you look at 2017, two questions on the DUCs and just drilling plans. How much of your ±80 DUCs are located in your core and extended core, and even fairway, if you have that? If you look at the two rigs going to four rigs, is the plan to really keep all four of those rigs in your core area versus rather even the extended core?
Okay. 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. The other 80% are all in the core. As far as the rig activity, as you pick up, as we go from two to four rigs, we're going to move those additional two rigs into core areas. It'll 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.
Good. Thanks.
Our next question comes from Kashy Harrison of Simmons Piper Jaffray. Please go ahead.
Good morning. Thanks for taking my question. Great color on 2017 and 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.
Yeah. Kashy, what we talked about was still sub 40. You're going to probably stay more at a 2-rig level. Production's going to keep flat in that scenario, spending within cash flow. In, call it $45 range instead of mid-teen type growth, it's going to be more like call it 10-ish% type growth. You're going to scale it back just a little bit, stay within cash flow once again. What we've talked about this time is further tightening and getting a little bit better. We had historically said mid-teens growth at $55. Now we're talking about that in a $50 world. Obviously, if it goes higher than that, 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, if you can keep that kind of efficiency, that's where you'll spend it most likely first. We're going to keep a keen eye on making sure that we can keep the efficiencies and well cost down.
Got it. Thanks for that. Just for clarification, the longer-term forward guidance does not incorporate the higher intensity in completions, right, in your production estimates?
Yeah, for the most part, we're looking at just the 4 million pound 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 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.
Thank you.
Thanks.
Our next question comes from David Deckelbaum of KeyBanc. Please go ahead.
Morning, guys. Thanks for fitting me in.
Hey, David.
Congrats on all the improvements you guys have made in the road DUC to getting to 2.5 times leverage.
Thanks.
Just curious. As you guys model it, you talked about the rig additions. I just wanted to get some color, if I missed it, on where the third, fourth, fifth rig would be going. In conjunction with that, how do you guys model with your pace of midstream investments in Wild Basin, what the max rig program would be in that specific area?
If we add the rigs, going to four and five rigs, one of those rigs would be over in the Indian Hills, City of Williston area. That would be the third rig. The fourth rig would be in the Alger area. Likely when we bring the fifth rig in, it'd be in the core, either in Alger or in that Indian Hills, 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. Some of that's going to be mixed into that count as well. As we add them back initially, all of them will be in the core.
I guess, Taylor, can you quantify in terms 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?
As you look at the, as we talked about, 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, hadn't seen quite the impact on high-intensity completions, but the rest of the acreage we have. As you go to even larger high-intensity completions, so the base job I'm talking about is 4 million pound slick water. As you go to a 10 million pound, and we'll see where we fall out, as we talked about or bigger, it could be a little bit smaller than the 10. We still don't have all the data in the core. We're encouraged by what we've seen so far and by what we've seen by other operators.
We think, if you see good reactions in the core, that those should apply to the other areas. We'd like to apply those in the extended core, for example. As Tommy talked about earlier, there's some third-party data with some of these bigger completions in our extended core that's pretty darn encouraging. Like I said, we will be testing those in other areas as well.
Just the last question from me, just to clarify, the way that you guys present type curves right now, you gave the one and a half million plus equivalent curve for Wild Basin, then just over one million has been sort of your, I guess, base high volume, 4 million pound completion within the core. Does that include the impact of the higher EUR Wild Basin curve as well, right? Or should we think about the average between Alger, Indian Hills, and portions of South Cottonwood being a million barrel equivalent?
That million barrel equivalent type curve, it was 1,050, and that does not include the new uplift, the 1.5 million barrel wells. When we did that originally, it was based on Wild Basin at 1.2 million barrels. That type curve across the core, it's forward-looking at our inventory with what we anticipate for the 4 million pound frack jobs, not the larger jobs. We will update that here going forward at the end of the year, you can expect that to go up.
Perfect. Thanks, guys.
Thanks.
Our next question comes from David Tameron of Wells Fargo. Please go ahead.
Good morning.
Hey, David
a good quarter. Actually a good string of quarters.
Thanks.
Just everything's been asked on the upstream side, so let me just hit something on the midstream. Actually two things. In midstream, any thoughts around, I know monetization was on the table for a while. How should we be thinking about that? 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 type of magnitude we should be thinking about?
You want me to talk about it? Yeah. 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, we've done really well on it and it's helped us to manage our business risk. That is very important to us. 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 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. The thing's 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.
I would say that it gives you a lot more certainty around it, which provides more optionality. It's not something that we're running out to do right now.
Okay.
All right.
Sorry, go ahead.
Sorry, go ahead.
I was just going to ask any quantification on the margin side then, Tommy, or whoever wants to take that.
Yeah. As far as the margin expansion, I assume you're talking around net backs. 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 for the deduct being in the $4 to $5 range. We're in the low fours for this quarter, we expect that to tighten as DAPL comes online, which we hope will be in the first half of 2017.
Margins across the whole business should continue to get better, Dave. As you think about a growing production profile, G&A per BOE goes down. Taylor mentioned differentials go down, realized price better. LOE should continue to go down, across all pieces of our business. With OMS online, you're going to get slightly better realized pricing as well. You're going to get pieces across the board that are going to be positive from a margin standpoint.
Okay. Michael, you're going to get some BOE as well, volumes coming into that?
Yeah. Right now, on the OMS side, obviously, it's just our operated wells, but we do have BOE on that. That adds to that midstream EBITDA.
Okay. I know you guys talked a little bit about this with the recent acquisition, can you talk about your thoughts as far as potentially any divestments? I know there's been some talk around, or 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?
Yeah. We haven't really spent a whole lot of time on that at this point. We have done some already, as you know. I think it's important for us to now look at the entire asset base and see if there is anything that makes sense. There's nothing that's on the plate at this point. With the SM deal, maybe we got some small cleanup stuff, but it's $tens of millions, not $hundreds 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. Thanks for all the detailed commentary. Always very thoughtful.
Thanks, John.
My question is there a commodity price at which either rigs three, four, or five 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 and $55 and certainly $60, the economics, and again, you can look back on page 20, for those areas become really compelling. 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. 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. Just, we talked a little bit about midstream spending earlier. Is there a ballpark that we should be thinking about for 2017 on the midstream side?
What we've said historically, John, is in that $50-$70 range right now. As Taylor and Tommy have mentioned, we're going to continue to look at the SM acreage, look at our development plans, and see if we need any additional spending. Obviously, any additional spending on top of that is going to come with returns on that capital. If we decided to do something, it would come with higher EBITDA levels. We don't have any definitive plans yet.
Great. That's all I had. Congrats again.
Thanks, John.
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 Bakken at Wild Basin versus the pay zone at Indian Hills?
The thickness in the Middle Bakken between Indian Hills and Wild Basin is not a lot different. Wild Basin is deeper, and as you look at the whole column, and so as you get into the Three Forks and the lower benches of the Three Forks, the charge is going to be a little better in Wild Basin. As I said, you got higher pressure because it's deeper. All those things combined, we're seeing better wells.
When you look at the 30% outperformance versus your initial expectation at Wild Basin, what's your thought 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?
Yeah. 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. 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 11-15 wells per spacing unit.
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 with these type of completions and the density of spacing that we're talking about, we think they're probably in the generally 15%-18% range. We'll continue to monitor some areas that it's lower than that, could be closer to 13%. 15%-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 third quarter 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.
The conference has now concluded. Thank you for attending today's presentation. You may now disconnect your line.