Oasis Petroleum Inc.
Q3 2016 Earnings Call Transcript

Published: 8 Nov 2016

[Operator:]

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. After today's presentation, there will be an opportunity to ask questions. 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.

[Michael H. Lou:]

Thank you, Nan. Good morning, everyone. This is Michael Lou. Today, we are reporting our third quarter 2016 financial and operational results. We're delighted to have you on our call. I'm joined today by Tommy Nusz and Taylor Reid, as well as other members of the team. Please be advised that our remarks, including the answers to your questions, include statements that we believe to be forward-looking statements within the meaning of the Private Securities Litigation Reform Act. These forward-looking statements are subject to risks and uncertainties that could cause actual results to be materially different from those currently disclosed in our earnings release and conference call. Those risks include, among others, matters that we have described in our earnings release, as well as in our filings with the Securities and Exchange Commission, including our Annual Report on Form 10-K and our quarterly reports on Form 10-Q. We disclaim any obligation to update these forward-looking statements. During this conference call, we will also make references to adjusted EBITDA 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.

[Thomas B. Nusz:]

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 has 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 barrels of oil equivalent. This curve is based off of our 4 million pounds slickwater well, which now just costs $5.2 million. Spud-to-rig release is down to 13 days in the third quarter 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&D costs down into the $4 to $5 per Boe range, a reduction of 38% compared to our finding cost at the beginning of the year with $6.5 million well cost and EUR expectations for Wild Basin at around 1.2 million barrels of oil equivalent. 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 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 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 de-levering 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.

[Michael H. Lou:]

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 1 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 stand-alone basis. When you add the one month of production from the pending acquisition, which is expected to close on December 1, 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 cost 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 18 acquisition, the other notable transactions from the third quarter were our convertible notes offering and the subsequent Dutch tender auction in September. This combination of events was very much an opportunistic tray 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.

[Taylor L. Reid:]

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, but 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 on 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 two-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 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 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&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 asset 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.

[Operator:]

Thank you. We will now begin the question-and-answer session. Our first question comes from Jeanine Wai of Citigroup. Please go ahead

[Jeanine Wai:]

Hi. Good morning, everyone.

[Thomas B. Nusz:]

Morning.

[Jeanine Wai:]

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 projection of growing within cash flow. Is that midstream spend something that we should be thinking as outside of when you say within cash flow or would be included in the total?

[Taylor L. Reid:]

No, it would be fully inclusive. So, it would include the midstream expenditures as well.

[Jeanine Wai:]

Okay. And then how are you thinking about your free cash flow generation profile? I think some of it probably depends on ducks and things like that with capital efficiency. But just wondering what the governor on that is? We do have some (15

[Michael H. Lou:]

Yeah. Jeanine, the plan that Taylor laid out is a kind of think about a $50 world and that's basically spending cash flow on both E&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 62,000 Boepd exit for this year growing around 70,000 Boepd next year and then comfortably above 80,000 Boepd by the end of 2018, that's all spending kind of inside the 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.

[Jeanine Wai:]

Okay. Great. Thank you.

[Thomas B. Nusz:]

Thanks.

[Taylor L. Reid:]

Thank you.

[Operator:]

Our next question comes from Neal Dingmann of SunTrust. Please go ahead.

[Neal D. Dingmann:]

Morning, guys. Nice quarter. Say...

[Thomas B. Nusz:]

Hey, Neal. Thanks.

[Neal D. Dingmann:]

Maybe, Tommy, for you or Taylor, I mean, you mentioned in the prepared remarks about the $5.2 million in the – was it 1,550 Mboe on the Wild Basin, so I'm just looking to map, is that fair to say now, is that going to be kind of the general results – or general cost, I should say, in type curve, if you more over to what you got left in Indian Hills or if you move to the East, to Algar, or is that just – I'm just wondering, I guess, how specific is that to the Wild Basin versus your existing and then less even throwing there the acquisition as well?

[Taylor L. Reid:]

So, it's – the well cost is going to apply for that whole area and so it will be at $5.2 million as we said. We think we'll continue to get efficiencies and in 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 the type curve that we've talked about at 1.55 MMBoe 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, 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 shallow over there, GORs are a little lower as well.

[Thomas B. Nusz:]

Keep in mind, Neal, that that's – we continue to play with things and the data that we show is off of the four million pound, $5.2 million 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.

[Neal D. Dingmann:]

That's good point. And I was just going to ask that as a follow-up, on 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?

[Thomas B. Nusz:]

Yeah. Taylor's going to add some color, but 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?

[Taylor L. Reid:]

That's correct. Half of the completions this year will have enhanced completion techniques and as I've been talking about the proppant loadings are biased higher and we've tested 10 million pounds or as high as 20 million pounds like Tommy just 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 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, but half of that period was at restricted rates until we got the infrastructure online. So, we like to have a good four to six months of production without that restriction behind it.

[Thomas B. Nusz:]

And, Neal, 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, is from some of the other operators, they've seen some very encouraging results in what we call the extended core. So, we're pretty excited about that as well.

[Neal D. Dingmann:]

Tommy, would that cycle time and just some of these bigger completions you guys laid out very nicely here for the next couple of years of production, will that be a bit lumpy or could it still be kind of a bit linear into that?

[Thomas B. Nusz:]

I think it will 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 loudly. 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.

[Neal D. Dingmann:]

Got it. Thanks for the details, guys. Nice quarter.

[Thomas B. Nusz:]

You bet. Thanks.

[Operator:]

Our next question comes from Michael Hall of Heikkinen Energy Advisors. Please go ahead.

[Michael Anthony Hall:]

Thanks. Congrats on a solid quarter. I appreciate the time.

[Thomas B. Nusz:]

Thanks, Mike.

[Michael Anthony Hall:]

I guess, want to kind of zero in a little bit more on some of the things you already talked about, but in particular, I was trying to think through kind of 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 kind of modeling outlined on slide 9?

[Taylor L. Reid:]

Well, the well per rig per year is just – just for modeling, it's right around 25, maybe a little bit over that. And...

[Michael Anthony Hall:]

And is that drilled or completed, Taylor?

[Taylor L. Reid:]

It's really the same.

[Michael Anthony Hall:]

Okay. It's same at this point.

[Taylor L. Reid:]

Pretty much a balance.

[Michael Anthony Hall:]

Great. And in the past I believe you talked about the two frac spreads that you have that they could support five rigs, is that still a fair way to think about that?

[Taylor L. Reid:]

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 pace of – 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, so it could be just a bit over.

[Michael H. Lou:]

Especially with some of these higher intensity completions, Michael...

[Taylor L. Reid:]

Yeah.

[Michael H. Lou:]

...that's another thing that adds to the need for more frac capacity.

[Michael Anthony Hall:]

That makes sense. Well, suffice it 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?

[Michael H. Lou:]

You can be right around that 30% kind of neighborhood on base declines and then what we had historically said is – or for 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 kind of now you're in 62,000 Boe 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.

[Michael Anthony Hall:]

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 that it's much about near wellbore stimulation as it is just putting a bunch more proppant 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 got any thoughts on that?

[Taylor L. Reid:]

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, and ended up not seeing appreciable difference in spacing we don't think, just probably better recoveries. So, as we go these bigger jobs, the sand loading increased, 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'll be something we'll be talking about more as we get into 2017 and beyond.

[Michael Anthony Hall:]

Okay. Great. Well, appreciate the time and congrats on the good momentum, guys.

[Thomas B. Nusz:]

Thanks, Mike.

[Operator:]

Thank you. Our next question comes from John Freeman of Raymond James. Please go ahead.

[John A. Freeman:]

Good morning, guys.

[Thomas B. Nusz:]

Hey, John.

[John A. Freeman:]

The first question, on these much higher intensity frac jobs that you're starting to do through this preliminary account longer-term guidance that you've given, what sort of a mix would you think is appropriate for 2017 for these much bigger high-intensity jobs, above the kind of 4 million pounds. If we consider 4 million pounds now for the standard jobs, these 9 million pounds, 10 million pounds plus, what percentage do you think of the wells that would be in 2017?

[Taylor L. Reid:]

At this point, we don't have a good percentage. And what we're trying to figure out is that we think you're going to be on average larger than 4 million pounds going forward, you end up being a 6 million or 8 million or 10 million pounds, where do you fall out in that cost versus 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.

[John A. Freeman:]

And this may be early, but on the bigger ones that you've done, call it let's say 8 million pounds or something, what's been sort of the cost difference versus that standard 4 million pound job?

[Thomas B. Nusz:]

So, it is early on that front, but when you look at kind of the same well, same number of stages, 4 million pounds versus the 10 million pounds, it's about close to a 20% uplift in cost, around $1 million. 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 (28

[John A. Freeman:]

I appreciate it. Well done, guys.

[Thomas B. Nusz:]

Thanks, John.

[Taylor L. Reid:]

Thanks.

[Operator:]

Okay. Thank you. Our next question comes from Jason Smith from Bank of America Merrill Lynch. Please go ahead.

[Jason Smith:]

Good morning, everyone, and thanks for the color on the outlook.

[Thomas B. Nusz:]

Morning.

[Jason Smith:]

Coming back to Jeanine's question, I appreciate that's 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, 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?

[Thomas B. Nusz:]

Then you get into a place where you're trying to figure out where the best utilization is as the market and 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 instead of four rigs at the end of next year run up to six? I think we're going to kind of feel it as we go to try to do everything we can to maintain – to hold onto 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 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 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, but it – or maybe a little bit better.

[Jason Smith:]

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?

[Taylor L. Reid:]

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 asset, that 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.

[Jason Smith:]

Thanks. Congrats again, guys.

[Thomas B. Nusz:]

Thanks.

[Operator:]

Our next question comes from Biju Perincheril of Susquehanna. Please go ahead.

[Biju Perincheril:]

Hi. Good morning.

[Thomas B. Nusz:]

Morning.

[Biju Perincheril:]

When looking at the newer completions, have you tested wells on the western side of your acreage on 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.

[Taylor L. Reid:]

So, we have tested our 4 million pound slickwater jobs in that area, in the fairway and also in the extended core. And if you look 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 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. So, that's one of the things as we move forward into 2017 and 2018, as we pick up the pace of activity, we'll likely to try some pilots with some of these higher-intensity completions in those areas.

[Biju Perincheril:]

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 body? (34

[Taylor L. Reid:]

Yeah. It's hard to tell at this point, but what I can tell you is for example in Montana, we were doing a crossing hybrid job there with a 4 million pound job and then when we stepped that up to a 4 million pound slickwater or we also did a larger high volume prop version of the job, we saw the increase in the EURs in those well go from around 400 Mboe to 450 Mboe up to 625 Mboe. So, a 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.

[Biju Perincheril:]

Got it. Thank you.

[Thomas B. Nusz:]

Thanks.

[Operator:]

Our next question comes from Ron Mills of Johnson Rice. Please go ahead.

[Ronald E. Mills:]

Hey, thanks for all the comments. A couple of quick ones. On the cycle time, as you potentially move to 10-plus million pounds of proppant, 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?

[Taylor L. Reid:]

Well, since you're doing a 10 million pound job, it's going to add probably one to two days on to the completion, and to do our base job is around four to five days. And so, you're going to add some time, but it's not a huge increase.

[Ronald E. Mills:]

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?

[Taylor L. Reid:]

So, in the core, it continues to be evenly spaced between Bakken and Three Forks wells, and the density that we've been testing is generally been between about 11 and 15 wells for 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.

[Ronald E. Mills:]

Okay. And then when you look at 2017, two questions on the ducks and just drilling plans. Just how much of your plus or minus 80 ducks are located in your core and extended core and even fairway, if you have that, and if you look at that 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?

[Taylor L. Reid:]

Okay. So, as far as the ducks are concerned, there's 80 wells now, we brought it down a little bit from last quarter where it was 83. If 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 two to four rigs, we're going to move those additional two rigs in the core area. So, it will be one likely in Indian Hills City of Williston area and another rig in the outer area, around the East side.

[Ronald E. Mills:]

Perfect. All right. I appreciate all the help. Thanks.

[Thomas B. Nusz:]

Thanks.

[Taylor L. Reid:]

Thanks, Ron.

[Operator:]

Our next comes from Kashy Harrison of Simmons Piper Jaffray. Please go ahead.

[Kashy Harrison:]

Good morning and thanks for taking my question. Great color on 2017 and 2018. I was just wondering if you all could provide some sensitivity if commodity prices are either better or worse than you anticipate going forward.

[Michael H. Lou:]

Yeah, Kashy, what we talked about was, still sub-40, you're going to probably stay more into two rig level, you're going to stay. Production is going to kind of keep flattened out that scenario, spending within cash flow. In, call it $45 range, instead of call it mid-teen type of growth, it's going to be more like, call it, 10-ish percent type growth. And so, you're going to scale it back just a little bit, you 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'd historically said kind of mid-teen's growth at kind of $55, now we're kind of talking about that in a $50 world. And 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 cost down.

[Kashy Harrison:]

Got it. Thanks for that. And then, just for clarification, the longer-term forward guidance does not incorporate the higher intensity completions, right, in your production estimates?

[Michael H. Lou:]

Yeah. For the most part, we're looking at just kind of 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, then 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.

[Kashy Harrison:]

All right. Thank you. That's it from me.

[Michael H. Lou:]

Thank you.

[Thomas B. Nusz:]

Thanks.

[Operator:]

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

[David A. Deckelbaum:]

Morning, guys. Thanks for fitting me in.

[Thomas B. Nusz:]

Hey, David.

[David A. Deckelbaum:]

And congrats on all the improvements that you guys have made in the road back to get in that 2.5 times levered.

[Thomas B. Nusz:]

Thanks.

[David A. Deckelbaum:]

Just curious on the – as you guys modeled 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? And then in conjunction with that, have 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?

[Taylor L. Reid:]

Okay. So, as 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, and then – that would be a third rig. The fourth rig would be the Alger area. And likely, when we bring the fifth rig in, it would be also over in the – it will be in the core either in Alger or in that in 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 rig back up is doing some test outside the core, testing some of these completion techniques or some of that's going to be mixed in to that that count as well. But as we had in the back initially all of them will be in the quarter.

[David A. Deckelbaum:]

I guess, Taylor, can you quantify in terms of sort of a percentage impact from the higher intensity completions, I know that you've had data and maybe you have smaller samples in the certain portions, but where have you seen the best response so far across the entire acreage position?

[Taylor L. Reid:]

Well, as you look at the – as we talked 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 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 to even larger high-intensity completions, so the base job I'm talking about is 4 million pound slickwater, as you go a 10 million pound, and we'll see where we fall out, as I talked about, are bigger or could be a little bit smaller than the 10 million pounds, 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 core, that those should apply to the other areas. So, we'd like to apply those 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 pretty darn encouraging. So, as I said, we will be testing those in other areas as well.

[David A. Deckelbaum:]

And just the last question from me, just to clarify. The way that you guys present type curves right now, you gave the 1.5 million plus equivalent curve for Wild Basin, and just over 1 million has been sort of your I guess base high volume 4 million pound completion within the core, does that 1 million 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 (45

[Taylor L. Reid:]

So, that 1 million barrel equivalent type curve it was 1,050 Mboe 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. And so, that type curve across the core, it's forward-looking at our inventory with what we anticipate for the 4 million pound 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.

[David A. Deckelbaum:]

Perfect. Thanks, guys.

[Thomas B. Nusz:]

Thanks.

[Operator:]

Our next question comes from David Tameron of Wells Fargo. Please go ahead.

[David R. Tameron:]

Good morning.

[Thomas B. Nusz:]

Hi, David.

[David R. Tameron:]

And I'd like to congrats on the good quarter, actually good stream of quarters.

[Thomas B. Nusz:]

Thanks.

[David R. Tameron:]

Just everything's been asked on the upstream side, so let me just hit something on the midstream, and actually two things. In the midstream, any thoughts around monetizations (46

[Thomas B. Nusz:]

Let me take that? (47

[Taylor L. Reid:]

Yeah. What I would say on the midstream business is, 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 and 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 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.

[David R. Tameron:]

Okay. And then – Sorry, go ahead.

[Taylor L. Reid:]

That's all right. Go ahead.

[David R. Tameron:]

Well, I was – any quantification on the margin side then, Tommy, or whoever wants to take that?

[Thomas B. Nusz:]

Yeah. 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 for 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 2017.

[Michael H. Lou:]

And 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, 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.

[David R. Tameron:]

Okay. And Michael, are you going to get some OBO as well volumes coming into that?

[Michael H. Lou:]

Yeah, right now the – on the OMS side, obviously, it's just our operated wells, but we do have OBO on that, that adds to that midstream EBITDA.

[David R. Tameron:]

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, well, 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?

[Thomas B. Nusz:]

Yeah. 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 maybe we got some small cleanup stuff, but it's tens of millions, not hundreds of millions.

[David R. Tameron:]

Okay. Thanks for the additional color.

[Thomas B. Nusz:]

You bet.

[Operator:]

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

[John Nelson:]

Good morning and thanks for all the detailed commentary, always very thoughtful.

[Thomas B. Nusz:]

Thanks, John.

[John Nelson:]

My question is, is there a commodity price at which other rigs, three, four, five would go to the extended core?

[Taylor L. Reid:]

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. And as we do pilot in some of those areas with some of these enhanced completion techniques, our hope is we just drive those economics up even further. So, improved economics which is here suggesting would mean extending into some of those areas earlier, but 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 span out from there.

[John Nelson:]

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?

[Michael H. Lou:]

What have said historically, John, it's kind of in that $50 million to $70 million 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 plans, 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.

[John Nelson:]

Great. That's all I have. Congrats again.

[Thomas B. Nusz:]

Thanks, John.

[Operator:]

Our next question comes from Gail Nicholson of KLR Group. Please go ahead.

[Gail Nicholson:]

Good morning. I'm just curious, how big is your pay zone in the middle of Bakken at Wild Basin versus the pay zone at Indian Hills?

[Taylor L. Reid:]

The thickness in the middle Bakken between the Indian Hills and Wild Basin is not a lot different. Wild Basin is deeper, and if 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. And as I said, you got higher pressure because it's deeper, and so all those things combined we're seeing better wells.

[Gail Nicholson:]

And then, when you look at the 30% outperformance versus your initial expectation at Wild Basin, do you feel like – or what's your thoughts about taking a potential EUR haircut in order – if you want to downgrade that into tighter spacing at Wild Basin versus saying, no, just take the higher EUR and current inventory versus taking a lower EUR and increasing the inventory?

[Taylor L. Reid:]

Yeah. That's the analysis we're working on which is around what is the proper spacing. As you get into higher price and you've always got that lever, an option of going to 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.

[Gail Nicholson:]

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?

[Taylor L. Reid:]

Recovery factors are – with these type of completions and the density of spacing that we're talking about, we think they're probably in kind of 15% to 18% range, and we'll continue to monitor. Some areas that lower than that, it 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.

[Gail Nicholson:]

Great. Thank you.

[Thomas B. Nusz:]

Thanks, Gail.

[Operator:]

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

[Thomas B. Nusz:]

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.

[Operator:]

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