Chord Energy Corp (CHRD) 2016 Q3 法說會逐字稿

Good morning ladies and gentlemen, and welcome to the Oasis Petroleum third-quarter 2016 earnings conference call.

(Operator Instructions)

Please note, this event is being recorded. Now, I would like to turn the conference over to Michael Lou, Chief Financial Officer. Please go ahead.

Thank you, Nan. 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 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 material 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 our filings with the Securities and Exchange Commission, including our annual 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 home page of our website.

With that, I will 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 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 17.1 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 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 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' frac efficiency reached all-time highs in the quarter. These well costs and EUR improvements in Wild Basin 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 costs and EUR expectations for Wild Basin, 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 for our wells supplemented by those of up 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 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 toward meaningful delivering over the next two years, down to a more normalized levels that we have 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 will 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 did 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 standalone 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.

Crew differentials improved to the best levels of the year, and moved to the bottom-half of our $4 to $5 per dollar range, as we recognized just $4.39 per barrel less than NYMEX. We've delivered basin-leaving 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 18 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. Included in 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 will 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. 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 in the Williston, we have not seen that happen yet. As operators increase profit 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 will decide if and when it makes sense to add a second internal crew. This is a great example of the options afforded to it as we look to grow the Company.

Because 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 assets, 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 at one more year in 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've 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 up the line for questions.

(Operator Instructions)

Jeanine Wai, Citigroup.

Good morning, everyone.

Good morning.

Just going back to your prepared remarks, you mentioned that you retained your option to spend on Midstream if you choose. I'm wondering how that fits into your projections of growing within cash flow? Was that Midstream spend something we should be thinking that's outside of when you say within cash flow, or would that be included in the total?

It would be inclusive, so would include the Midstream expenditures as well.

Okay. How are you thinking about your free cash flow generation profile, I think some of that 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 and 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 look to meaningfully under spend in the future?

Jeanine, the plan that Taylor laid out is think about a $50 world and that's basically spending cash flow on EMP and Midstream, all CapEx for the company, spending within cash flow and growing to those rates that Taylor mentioned -- which was the 62,000 exit for this year growing around 70,000 next year, and comfortably above 80,000 by the end of 2018. That's all spending inside of cash flow. 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.

Great. Thank you.

Thanks.

Neal Dingmann, SunTrust.

Good morning guys, nice quarter. Maybe Tom, for you or Taylor, you mentioned in the prepared remarks about the $5.2 million, and 1550 MBoe in the Wild Basin. I'm looking at the map, is that fair to say -- is that going to be the general results -- or general costs, I should say, in type curve, if you move over to what you have left in Indian Hills, or if you move to the east to Alger? I'm wondering, how specific is that in the Wild Basin versus your existing, and let's even throw in there the acquisition as well?

The well cost is going to apply for that whole area, so we will be it $5.2 million, as we said, we think we will continue to get efficiencies. And 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. The type curve that we talk about the 1.55, at this point is really more focused on Wild Basin. However, if 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 as I said, you go back to the west, it's going to drop off a bit in Indian Hills. It's a little shallower there; the 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 pounds, $5.2 million well cost, so as we start push proppant loads and efficient placement along the wellbore. Then we possibly can push that up a bit across the entire position. A little bit early to tell.

That's a good point, Tom. I was going to ask that as a follow-up. On the enhanced completions, I know you all have talked about, it in some of your peers are doing, I guess even over 10 million pounds, et cetera. How quickly do you anticipate pushing that? And do think we are getting close to diminishing returns there, or we are still a bit away from that?

Taylor can 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 tapped the wells for this year -- for 2016, have some kind of enhancement over those base jobs.

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 tested 10 million, and as high as 20 million pounds, like Tommy's talked about. So we're trying to find the right cost and intensity trade-off.

And as we get more data, we will 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 restricted rates until we got the infrastructure online. So we'd like to have a good four to six months of production without that restriction.

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, from some of the other operators, those -- they've seen some very encouraging results in what we call the Extended Core. So we are pretty excited about that as well.

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

I think it will be more -- I don't think it will be -- it's always a bit lumpy, that I wouldn't expect it to swing wildly. I think 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.

Michael Hall, Heikkinen Energy Advisors.

Thanks. Congrats on the solid quarter. Appreciate the time.

Thanks Mike.

I want to zero in a little more on some of the things you already talked. In particular, I'm 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 your current thinking and on modeling outline on slide 9?

The well per-rig, per-year, as we're modeling, it's right around 25, maybe a little over that. And --

Is that drilled or completed, Taylor?

It's really the same.

Okay. The same at this point. Great. And in the past, I believe 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?

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 balance between the two rigs and the one frac crew. It could just be a bit over.

Especially with some of the 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. Any commentary on around whether your base decline assumption is -- or what you're modeling around base decline, coming out of 2016, and again out of 2017, was in that long-range outlook, you provided?

You're going to be right around that 30% neighborhood on base declines. And then, what we had historically said or for the last couple of years, that a more flattish type production per -- if you were only running two rigs and you're standing at that, now year-end, 62,000 and day, your declines are going to decrease over time, but as we start growing again, obviously those decline rates will stay in the same range, in that 30% range.

Okay. The last one of mine, I'm just trying to think through, broadly for the basin, but specifically for you all as well, as you move towards these new completion designs. Our understanding is that it's as much about near wellbore stimulation, as it is putting a bunch more profit in the wells. 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 Williston, were on older completion technologies, just curious if you have thoughts on that?

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 it ended up not seeing appreciable difference in spacing, we don't think, just better recoveries. As we go to these bigger jobs, as the sand loadings increase, that's one of the things that we are going to continue to keep an eye on.

Don't have a view just yet, we need more data and we're doing, not only testing, but a lot of simulation and subsurface work to draw the conclusions on that front. It will be something we will be talking about more as we get into 2017 and beyond.

Great. Appreciate the time and congrats on the good momentum.

Thanks Mike.

John Freeman, Raymond James.

Good morning guys.

Hello John.

First question, on these much higher-intensity frac jobs that you're starting to do, this preliminary, 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 4 million -- if we consider 4 million now for the standard job, these 9 million, 10 million plus, what percentage do you thing, of the wells, that would be in 2017?

At this point, we don't have a good percentage. What we are trying to figure out is -- we think you're going to be, on average, larger than 4 million going forward, you end up being at 6 million, or 8 million, or 10 million. Where do you fall out in that cost versus benefit?

But I would think about, as I said, we 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, say 8 million or something, what's been 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 a 10 million, it's about close to a 20% uplift in costs, around $1 million. So we think that, like you said, this is a normalized. We haven't done a large group of these. They are test wells.

We will have better uplift going forward, but early time, it's somewhere under, at, or around 20% increase in cost.

I appreciate it. Well done guys.

Thanks John.

Jason Smith, Bank of America Merrill Lynch.

Good morning everyone, and thanks for the color on the outlook. Coming back to Jeanine's question, I appreciate that thunder of $50 scenario, and the plans that 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? Where I'm going is -- where's the first incremental dollar go?

Then you get into place where you are -- you are trying to figure out where the best utilization is, as the market and environment changes. 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 are 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 in monitoring the service costs. So 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.

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 that 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 more may be a little bit better.

Got it. I appreciate that. And 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 going out, our gathering systems, connecting more wells as you go. So in Wild Basin, it's going to be all the gathering systems, the 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. Those gives us some opportunity to expand the footprint for Wild Basin and capture some incremental volumes there.

Thanks. Congrats again guys.

Thanks.

Biju Perincheril, Susquehanna.

Good morning. Looking at the newer completions, have you tested wells on the western side of the acreage -- on what you would characterize as the Fairway region? Do you have an idea on what kind of upside you can see from the numbers that you are 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. And if you look 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 are 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 are seen in the Core, or do you think the uplift would be something lower because of the rock quality?

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 a 4 million pound job, and we stepped that up to a 4 million pound slick water, or we also did a larger high-volume prop version of a job, we saw the increase in the EURs in those wells go from around 400 to 450, up to 625 MBoe. So nice uplift just on that first step in intensity. So we would be helpful that we would see another increase. We've just got to try to pilots to confirm it.

Got it. Thank you.

Thanks.

Ron Mills, Johnson Rice.

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 kind of ideas, in terms of what that can mean to cycle times? I assume they take longer to complete. Just how much time do 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. So you're going to add some time but it's not a huge increase.

And then from the 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 onto 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 being evenly split between Bakken and Three Forks.

We have continued to test some lower benches along the way. 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 will get more results before we do that.

Okay. When you look at 2017, two questions on the DUCs and 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 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?

As far as the DUCs are concerned, there's 80 wells now. We brought 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've got a handful that are in the Fairway. And 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 will be one likely in Indian Hills, City of Williston area, and another rig in the Alger area, over on the east side.

Perfect. I appreciate all the help. Thanks.

Thanks.

Kashy Harrison, Simmons Piper Jaffray.

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

Kashy what we talked about was, still sub $40, you going to probably stay more in at a two-rig level, production will stay flat in that scenario, spending within cash flow. In, call it a $45 range, instead of, call it, mid-teens type growth, it's going to be more like call it 10-ish% type growth, so going to scale back just a little bit, you stay within cash flow, once again.

What we talked about this time is, further tightening and getting a little bit better. We've historically said mid-teens growth at $55, and now we're talking about that in the $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 go with that 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 will 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 just for clarification, the longer-term forward-guidance does not incorporate the higher-intensity in completions, right? In your production estimates?

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 will build that into both the capital expenditure side, the increases there, as well as productivity side.

Thank you that's it for me.

Thank you.

David Deckelbaum, KeyBanc.

Good morning guys. Thanks for fitting me in, and congrats on all the improvements you guys have made back to getting that 2 1/2 times leverage.

Thanks.

As you guys modeled it, you talked about the rig additions, and I want to get some color, if I missed, on where the third, fourth, fifth rig would be going? And 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?

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 the -- that would be the third rig, the fourth rig would be in the Alger area. And likely, when we bring the fifth rig in, it would be also over in -- it would be in the Core, either 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. So some of that will 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 a percentage impact from the higher intensity completions? I know you have data, maybe you have smaller samples in certain portions. Where have you seen the best response so far across the entire acreage position?

As we talked about, if 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 North Cottonwood, on the east side. So the far northern part of that position hasn'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 slick water, as you go to a 10 million pound, and we will see where we fallout, as we talked about, or bigger, it could be a little smaller than the 10 million. We still don't have all the data in the Core. We are 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 would like to apply those in the Extended Core, for example. As Tommy talked about earlier, there is some third-party data with some of these bigger completions in our Extended Core that's pretty darn encouraging. We will be testing those in other areas as well.

Just the last question for 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 your 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? Or should we think about the average between Alger, Indian Hills, and portions of South Cottonwood being 1 million barrel equivalent?

That 1 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 based on Wild Basin at 1.2 million barrels. So that type curve across the Core, it's forward-looking at our inventory with what we anticipate for the 4 million pound fracs jobs, not the larger jobs. We will update that here going forward at the end of the year. So you can expect that to go up.

Perfect. Thanks guys.

Thanks.

David Tameron, Wells Fargo.

Good morning. Good quarter, and actually, a good string of quarters.

Thanks.

I don't think it's been asked enough [insights], so let me just hit something on the Midstream, and actually two things. In Midstream any thoughts around, I know [modernization] has been on the table for awhile. How should we be thinking about that, and can you quantify I think, Taylor, you alluded to it, but can you quantify what would drive the margin expansion in 2017 and 2018? The different pieces or what type of magnitude we should be thinking about?

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, and it's helped us to manage our business risk. And that is very important to us. And, versus if you were to step back one year ago, when you start talking about the Wild Basin project, and you're going to get all the, what I call the yes-buts, whether that's with respect to cost or whether that's with respect to timing of the project, and all of those things.

That's all behind us now. And so the thing is up and running. We've got if 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.

I was going to ask, any qualification on the margin side, then Tommy, or whoever wants to take that?

As far as the margin expansion, assume you're talking around netbacks, and so one of the things we have talked about is, we think the advantage of getting connected to a DAPL, when DAPL does come online, and that could really improve pricing in the basin. We've seen it, the margins for the DUCs 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.

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 is better, LOE should continue to go down. Across all pieces of our business, and with OMS online, you're going to get better, fuzzy realized pricing as well, so you're going to get pieces across-the-board that are going to be positive from a margin standpoint.

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

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

Okay. I know you guys talk a little bit about this with the recent acquisition, but can we talk about your thoughts as far as potentially, any divestments? I know there has been some talk around -- or there has been some JVs up there, from other players. How should we think about something similar to what Continental did or something along those lines?

We haven't really spent a whole lot of time on that at this point. 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, 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.

John Nelson, Goldman Sachs.

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

Thanks John.

My question is, is there commodity price at which other rigs three, four, or five go to the Extended Core?

Right now, the way we are 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, is where 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 drive those economics up even further.

So improve the economics, 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 will see in terms of returns, and then fan out from there.

Okay. And then we talked a little bit about Midstream spending earlier. Is there a ballpark we should be thinking about for 2017 on the Midstream side?

What we said historically, John, is that 50 to 70 range, right now. And as Taylor and Tommy have mentioned, we are going to continue to look and 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. 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 have. Congrats again.

Thanks, John.

Gail Nicholson, KLR Group.

Good morning. I'm curious, how thick is your pay zone in the middle Bakken, 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 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've got higher pressure because of deeper. So all those things combined, we're seeing better wells.

When you look at the 30% out-performance versus your initial expectation for Wild Basin, do feel like -- what are 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 say no let's take the higher EUR and current inventory versus taking a lower EUR an increase the inventory?

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 are going to continue to make as we are doing these completions in Wild Basin. Like I said, currently, we are spaced at around 11 to 15 wells per spacing unit.

And 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 the, generally 15% to 18% range. We will continue to monitor. There are some areas that it's lower than that. It could be closer to 13%, but 15% to 18% in the Core, with the density we are talking about, we think, are pretty good numbers.

Great. Thank you.

Thanks Gail.

This concludes our question and answer session. I would 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.