Chord Energy Corporation
Q3 2018 Earnings Call Transcript

Published: 6 Nov 2018

[Operator:]

Good morning. My name is Danielle and I will be your conference operator today. At this time, I'd like to welcome everyone to the Third Quarter 2018 Earnings Release and Operations Update for Oasis Petroleum. All participants will be in a listen-only mode. After today's presentation, there will be an opportunity to ask questions. Please note this event is being recorded. I would now like to turn the call over to Michael Lou, Oasis Petroleum CFO, to begin the conference.

[Michael H. Lou:]

Thank you, Danielle. Good morning, everyone. Today, we are reporting our third quarter 2018 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 on both Oasis Petroleum and Oasis Midstream Partners, 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 releases and conference calls. Those risks include, among others, matters that we've 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 may make references to non-GAAP financial measures and reconciliations to the applicable GAAP measures can be found in our earnings release and on our websites. We will also reference our current investor presentation, which you can find on our website. With that, I'll turn the call over to Tommy.

[Thomas B. Nusz:]

Good morning and thank you for joining our call. Oasis completed another solid quarter as we continue to execute on our 2018 plan and set up for 2019. Performance in our cornerstone Williston asset remained strong as we continue to efficiently develop our deep core inventory across the basin. Separately, we could not be happier with the performance of our Delaware position. Our deliberate and measured development program is progressing nicely. As well performance remained strong, we've been able to secure necessary services with quality partners and our subsurface knowledge is growing rapidly. The plan we laid out at the first of the year is right on track as reflected in our completion cadence where we have completed five of the six to eight-well target for the year by the end of the third quarter. We have just brought on an additional well that brings our total to six currently and we currently have three wells waiting on frac. Additionally, we continue to engineer a long-term development strategy for this world-class asset and remain very impressed with everything we've seen so far. I want to highlight a few key points for you this morning. Our capital efficiency continues to stand out among our peers. Page 13 of our investor presentation highlights our recycle ratios which are top tier within our peer group, reflecting a healthy mix of strong well productivity and capital costs. We're modestly adjusting our fourth quarter volume guidance to reflect timing of our second gas plant, but still expect exit rates to approximate our previous guidance of 91,000 to 94,000 Boes per day. That being said, our updated fourth quarter range reflects a 5% increase from our original guidance with our exit rate up 10%. We're also maintaining our current full year 2018 CapEx budget and continuing to expect the E&P business to generate free cash flow in 2019, while growing volumes in the mid-teens. We successively added to our Delaware position this year in an accretive manner with bolt-ons totaling 1,600 net acres in eastern Loving County and Ward County, bringing our current position to over 23,000 net acres, and we see similar opportunities through acquisitions and trades adjacent to our acreage, and we'll continue to add to our consolidated blocks to build scale just as we've done and continue to do in the Williston. Operational execution remained strong in both the Williston and the Permian. Our lease operating expenses per barrel of oil equivalent continues to trend below expectations, a testament to the efficiency of our operations, including remote monitoring and optimization. Our marketing team and strategy is performing well as we're moving barrels to premium markets avoiding exposure to the commonly quoted daily Clearbrook market. Our average Williston differential in October and November has been around $3 off of WTI. Unusually high refining maintenance is having an impact on early December pricing, but this is transitory as we expect it to be resolved over the next few weeks. As we look into 2019, Midwest refinery demand should normalize and our coastal customers have indicated that they're significantly expanding their rail fleets, which will further increase our access to coastal markets. Lastly, Oasis Midstream Partners continues to be an important strategic asset for us, allowing us to grow volumes, capture better margins and manage business risk. Our team did a great job anticipating the impending tightness in the processing market and addressing it so that we can move not only our gas production, but bring third-party volumes through as well. Our second gas plant will be ramping up soon and puts Oasis in a strong position to grow through increasingly stringent gas capture regulations. By year end, OMP stands to be the second largest gas producer in the Williston Basin. As a reminder, Oasis' shareholders own 69% of the OMP LP units and participate in its growing success. Turning to production, Oasis produced 85,400 Boes per day in the third quarter, an all-time high for the company. Oil volumes were up approximately 27% year-over-year and increased over 8,200 barrels per day sequentially, adjusting for the impact of acquisitions and divestitures. Oil volumes were approximately 1% above the midpoint of guidance for the quarter. Gas volumes in the third quarter were below expectations, reflecting a brief outage we experienced at Wild Basin Gas Plant I. We have adjusted our fourth quarter guidance to 87,500 to 90,000 Boes per day, which largely reflects timing of our second gas plant, which is slightly behind our target date, but we expect it to be online by the end of the month. Our previously announced exit rates of 91,000 to 94,000 Boes per day remains intact. And as I mentioned earlier, our 2018 CapEx is unchanged from our last update. The Williston continues to be a major production driver this year with development across Alger on the east side of the basin and Wild Basin, Indian Hills, Painted Woods and Red Bank on the west side. These projects in total account for over 85% of our drilling and completion budget. Importantly, we're driving growth while maintaining capital discipline. We expect to be free cash flow positive on our E&P business this year and into 2019 and beyond. Additionally, internally-controlled infrastructure through OMP continues to provide flow assurance in a tight processing market, reducing costs and providing access to liquid marketing points with direct access to premium markets. In the Delaware, our measured approach to development has proven the right course as our subsurface knowledge continues to grow and we've avoided putting ourselves in a position of accelerating volumes into a weak net pricing environment by virtue of limited takeaway capacity. Well performance remains strong and we updated our curves showing production above the typical industry type curve. We're learning not just from our wells, but from third-party activity and partnerships as well and continue to develop our long-term operational strategy around this tremendous asset. I will conclude my remarks by saying that we're excited about where we are and what's in front of us. Our company continues to deliver great cash margins and higher returns. We've executed well this year and have delivered on solid capital execution and results. The Williston remains our cornerstone asset and a major growth driver, while we continue to delineate and add to our Delaware acreage, getting closer to full-field development in 2020. Capital discipline remains a core focus. Then, we're in a great position to be able to be E&P cash flow positive, while delivering value-added growth for years to come. With that, I'll turn the call over to Taylor.

[Taylor L. Reid:]

Thanks, Tommy. Performance remains strong and we continue to execute our plan. We raised production guidance twice this year, even taking into account the loss of divested volumes. During the quarter, we completed two gross and net wells in the Delaware. We added our second rig in late May and we expect to stay on track with our previous guide at six to eight wells completed for the year. In the Williston, we remain primarily focused in the core and still expect to complete around a 110 gross operated wells in 2018. During August, we experienced a temporary outage at OMP's 80 million cubic foot per day gas plant due to a compressor failure. During the 12-day outage, design changes were implemented to prevent future risk of a similar nature. The gas plant has been running smoothly since the outage in October at record efficiency. Downtime affected August volumes while July and September were not impacted. Lost volumes associated with the downtime averaged approximately 6 million cubic feet per day over the third quarter. With the second Wild Basin gas plant coming online later this month, Oasis stands to benefit from operational efficiency and flexibility provided by OMP's two gas plants and mechanical refrigeration units, providing total processing capacity of 320 million cubic feet per day. Turning to well performance, the core Williston remains a focus for us. Wild Basin, Alger and Indian Hills comprise the lion's share of our 2018 development program. Just recently, we completed our first enhanced completion well in Painted Woods and early results were encouraging. As we continue to the of the Central Basin, we plan to complete three wells in Painted Woods and six wells in Red Bank this year. In addition to our own activity, we continue to watch other operators across the play implement enhanced completion techniques and are excited about the early time results and the potential positive implications for our extended core and fairway acreage. In the Delaware, our wells continue to outperform the industry 1.2 million Boe type curve. All wells are still naturally flowing with our Bighorn well still flowing after more than two years on production. We expect to continue to improve returns through the use of longer laterals and optimizing completion techniques. In January, we'll be completing a three-well Wolfcamp A spacing test with two in the lower and one in the upper interval. While the Wolfcamp A will still be the primary focus in 2019, you'll see us drill across the different zones from the third Bone Spring to the Wolfcamp C as we continue our delineation and work towards full-field development. We're excited about the results we have seen in ours and other operators' wells in these intervals. For example, we have drilled and tested two wells on the second Bone Spring so far and are excited with the results. Remember, this interval was not included in our acquisition value and provides significant upside. On the operational cost front, the team continues to execute well. LOE per Boe averaged $6.18 coming towards the low end of our guidance range of $6 to $7 per Boe. We've reduced LOE guidance for the third time this year. On crude differentials, Tommy did a great job summarizing the fantastic job our marketing team has done in the Williston. In the Delaware, differentials are volatile, but we believe significant long-haul pipelines coming online in the second half of 2019 will alleviate the bottleneck for years to come. As a reminder, we've committed 10,000 barrels a day to the Gray Oak pipeline, which is expected to come online in the fourth quarter of 2019. As we look to 2019, our steady Williston and Permian programs should deliver 15% year-over-year exit rate volume growth. We plan to issue formal guidance along with our Q4 update in February. But on the CapEx side, here are some preliminary thoughts. In 2018, we averaged slightly over four rigs in the Bakken and about one-and-a-half in the Delaware. We are adding our fifth rig in the Williston towards the end of this year. In the Delaware, we plan to add our third rig in the second half of 2019 and dedicate a full-time completion crew soon thereafter. In the Williston, we're on track to complete around 110 gross operated wells this year. And in 2019, we expect the count to be slightly higher. In the Delaware, we're on track to complete approximately seven gross operated wells this year. And for 2019, we currently expect around 15 completions to 20 completions. Given the moderate increase in Williston activity and more pronounced pickup in the Delaware, E&P spending is expected to increase year-over-year, primarily driven by activity in the Delaware. As you can see, our results continue to be solid across both basins, and we are excited about our Williston and Permian programs as we close out 2018 and move into 2019. Our Midstream is a big part of that, and Michael will give you more color on that program next. I will now turn the call over to Michael.

[Michael H. Lou:]

Thanks, Taylor. Production growth remains strong and we are growing in a capital efficient manner. Additionally, we high graded our asset base this year through a series of divestitures and new bolt-ons in the Delaware. Also we project being free cash flow positive on the E&P business in 2019 and beyond. Liquidity remains strong. We recently completed our fall redetermination. Our total borrowing base remains at $1.6 billion with $1.35 billion committed with only $522 million drawn as of September 30. Maturity was extended to five years from the closing date. Oasis had a net debt to third quarter 2018 annualized EBITDA multiple of 2.4 times with adjusted EBITDA attributable to Oasis of $270 million in the third quarter. As Taylor noted, operating costs remain towards the bottom end of our guidance range and we reduced guidance for a third time this year. We slightly increased marketing, transportation and gathering expenses, reflecting the increased use of the Dakota Access Pipeline in the third quarter, which led to better realizations. Our third quarter differential of $1.42 per barrel off WTI was slightly better than the low end of our guidance range. Said another way, DAPL costs increased about $0.89 per barrel of oil sequentially. And including this impact, all-in oil differentials were essentially flat quarter-over-quarter. Just to update you on our hedging program, we continue to layer on hedges for 2019. We have added collars in 2019 with an average ceiling of $75 and floor of $55 plus. This strategy protects our capital program in lower price environments while also allowing us to capture more upside in higher price environments. As a general rule, we like to have approximately two-thirds of our forward year production hedged by year end, and we're most of the way there. Diving deeper into Midstream, we continue to develop our asset base to ensure flow assurance at Oasis and capitalize on market opportunities across different commodities. Since our last update, we've secured additional third-party agreements with attractive build multiples, and we continue to look for additional business. As a reminder, gas processing in the Williston remains tight, with state data indicating a capture rate of only 82% over the past several months, well below the 88% requirement that kicks into effect this month. OMP's second 200 million a day plant should be on line by the end of this month. We'll be talking in more detail on the OMP call shortly, and I would also direct you to our OMP press release for more color on our continued success on the Midstream front. To elaborate on the 2019 Midstream plans, we continue to work through the many opportunities available to us. As it stands, steady-state Midstream CapEx would drop significantly year-over-year around 40%, reflecting the completion of Gas Plant II and associated gathering. However, there are many growth opportunities that we're currently evaluating including third-party deals, additional Williston infrastructure and potential Delaware investments. Final decisions on which projects to pursue and the financing will be made in the coming months and we look forward to updating the market in early 2019. 2018 has been an exceptional year for Oasis. The team continues to execute incredibly well lowering costs, increasing productivity across the play and delivering some of the tightest differentials in the basin. All this puts us on track to provide best-in-class capital efficient growth, resulting in increases to our production targets throughout the year. While we're making a few minor tweaks to the fourth quarter for the gas plant timing, the 2019 outlook remains intact with robust 15% growth with positive cash flow. With that, I'll hand the call back over to Danielle for questions.

[Operator:]

We will now begin the question-and-answer session. The first question comes from Brad Heffern of RBC Capital. Please go ahead.

[Brad Heffern:]

Hey. Good morning, everyone.

[Michael H. Lou:]

Hey, Brad.

[Brad Heffern:]

On the Bakken crude takeaway front, can you talk about how your volumes have been traveling recently? Have you seen more of them traveling on rail? And then if there are pipeline expansions in 2019, would Oasis consider making a commitment to those, or would you stay relatively uncommitted on your volume?

[Michael H. Lou:]

Yeah, a couple of things on the differentials side. Our marketing team, we think, does an incredibly strong job of keeping us to where we get some of the best differentials in the basin. You've seen that quarter-over-quarter. You'll see that again, we think, in the fourth quarter. You've seen, and Tommy mentioned this, that you've seen Clearbrook kind of gap out because some of those refinery turnarounds and some of the dislocation in the local markets. But for the most part, we don't move a lot of volumes to that Clearbrook market and so we're bypassing it, whether it's through pipelines or rail. So, you'll see that our differentials continued to stay pretty tight, even though you've seen some dislocation in that spot market. So, you are seeing quite a bit of an additional rail coming in late this year and early into next year. So, we think that will continue to provide the basin a lot of access to those coastal markets. And you mentioned the pipeline increases, and people have heard about kind of pipeline potentially increasing or having some availability, and, yeah, we're always looking at whether or not we should continue to get more long term space. Historically, we haven't done a lot of it, but we'll certainly look at it each time it comes available and see if it makes sense at that time.

[Brad Heffern:]

Okay, thanks for that. And then on the asset sale program, can you talk about if you guys are done at this sort of a little under $400 million level or if there's still processes under way? And then can you give any sort of update on when we might see the first drop to OMP? Thanks.

[Michael H. Lou:]

Yeah. On the asset sales side, I think what we said on our last call is that the asset sale market has been incredibly difficult. We feel really good about where we are through the year with the increased oil price from the beginning of the year, cash flow generation, where our balance sheet is. We feel pretty good about where we've come out on the divestitures side. So right now, we're not looking at anything additional on that side in the Williston. On the drop, yeah, no change, it still continues to be something that we think is attractive for both the Oasis side and the OMP side for the future, but no raw update on timing on that side as of right now.

[Operator:]

The next question comes from Ryan Todd of Simmons Energy. Please go ahead.

[Ryan Todd:]

Great. Thanks. Maybe a follow up on the Midstream side with regard to CapEx next year, you talked about being free cash flow positive on the E&P side, should we think about – is that just on the relative to E&P capital spending, relative to cash flow? And in terms of funding the potential Midstream spend, how would that – would that be obviously – maybe a potential drop from OMP or how would the Midstream spend be funded?

[Thomas B. Nusz:]

Yeah. So Midstream this year, we had about $300-ish million on the Midstream side. Altogether, when we back out the amount spent by OMP, there was about $180 million. Next year, what we're saying is that it's, call it, 40% less than that on a run rate basis. So think about it as somewhere in the $150 million to $180 million type range. And when you start looking at what will be spent by OMP, Oasis's portion less the Midstream's or the MLP side will be somewhere in the $80-ish million to $100 million neighborhood. So, you're exactly right. We expect that overspend really this year and next to be funded by a drop to OMP. So once again, we don't have any update on timing of all that yet, but we do expect that to be over time funded by a drop-down process.

[Ryan Todd:]

And if some of the additional growth opportunities on the Midstream side showed up, how should we think about the potential funding for that?

[Taylor L. Reid:]

Yeah. What we've said in the past is it's continued to hold true. We're continuing to evaluate and figure out where the best place to fund that is. Certainly what we've done is we've created this MLP so that it can fund a lot of that growth going forward. But we'll eventually figure out, does that mean building it at the parent and dropping it down in the future or MLP building it directly? We don't know at this point. We're still evaluating that.

[Ryan Todd:]

Great. Thanks. Maybe one follow-up on some of your comments on Painted Woods, I realized that the wells have only – you don't have enough data yet on production to put definitive data out there. But can you talk a little bit about what you're seeing on early flows and what strong well results could mean relative to your expectations and inventory there?

[Thomas B. Nusz:]

Sure. So, we only have one of our wells on Painted Woods at this point and it's only been on production for a couple of months, maybe two-and-a-half months or so. But it continues to flow and it's outperformed what we've seen from the older wells that had more conventional frac. So, this was a larger style slickwater frac like we're currently doing. So, we'll talk about it more next year. But just suffice it to say that it's really outperforming what we've seen historically. And then on top of that, if you look at the map in our presentation, there's a slide that shows that area where we've completed the well and then other operators offset to us. And so, those are all enhanced completions in that area. And it was on the basis of really the third-party wells that we expanded our core to cover part of the Painted Woods area. And this well really just is reinforcement for that move. It's performing in line with those other wells. So, it really supports with our own production that moved to the core of some of that acreage. And like we said, we're going to have a couple of other wells that we'll complete and bring on probably late in this quarter. So, we'll be able to talk about all three of those new wells as we go into next year.

[Ryan Todd:]

Great. Thank you.

[Michael H. Lou:]

Thanks.

[Operator:]

The next question comes from Drew Venker of Morgan Stanley. Please go ahead.

[Drew Venker:]

Hi, everyone. I just want to follow up on the Bakken takeaway, if you can give us a sense of where that additional rail capacity is coming from. Is that new cars, or is it cars being moved around? And then how do the differentials in the Bakken play into your activity plans in 2019? Are those activity plans somewhat sensitive to your pricing in the basin?

[Michael H. Lou:]

Yeah, Drew. So, on the takeaway side, what our understanding is the additional rail will be a combination. But yeah, there's certainly a lot of new railcars that are coming in. But there's also things that are being transferred from other areas. Obviously, there would be a higher arbitrage, if you will, in the basin today. So more and more is going to move in that direction. So, we do think a number of kind of additions on the rail side as well as the pipeline side is going to keep differentials pretty tight in the Bakken for the foreseeable future. With that, that's how we kind of come up with our plans in the Bakken next year. We remain generally flexible kind of throughout our program for different commodity prices and changes in pricing, even within basins. But right now, our plan is exactly like we laid out, and we think that differentials in the Bakken will remain pretty tight throughout next year.

[Drew Venker:]

Thanks for that, Michael. As a follow-up, can you talk about whether you would be interested to commit to some of that additional takeaway capacity, whether it's rail or pipeline?

[Michael H. Lou:]

Yeah. Historically, we've stayed away from long, long-term deals but we have done some medium-term deals and there's still some of that that's available and we lock into some of those all the time. And so we kind of ladder out some of our obligations and keep a mix of kind of medium-term stuff. We're a little bit light on the longer term. We'd certainly look at it if we thought the Basin was going to be constrained longer term. We're not really seeing that yet, but there are some pipelines that are coming out with some availability and we will certainly take a look at those opportunities.

[Drew Venker:]

Okay. Just one more for me. As you think about the program longer term beyond 2019, how do you see the mix of activity or spending or rigs however you want to define it in 2020 and beyond between the Permian and the Bakken?

[Thomas B. Nusz:]

It's early to really talk exactly what 2020 is going to look like. But I think the trend that we were talking about for 2019 where you're seeing a slight increase in the Williston and a more pronounced increase in the Delaware something like that is, would not be out of the question to expect because we're going from really this delineation and analytics phase to really understand the subsurface in the Permian in 2018 and 2019 to full development mode in 2020. So, you're going to be at a higher clip, likely four rigs in 2020 and then again like I said a slight uptick in Williston most likely, but we'll see as we go.

[Drew Venker:]

Okay. Thanks for all the color.

[Operator:]

The next question comes from John Freeman of Raymond James. Please go ahead.

[John A. Freeman:]

Hi, guys.

[Michael H. Lou:]

Hey, John.

[John A. Freeman:]

When I look at the 2019 plan, which I appreciate all the added color on 2019 and it looks like basically at this point the drilling and completion activity is relatively locked in. So, it would appear the only remaining items to kind of to consider before you all come out with the 2019 formal budget in February is basically non-op activity and service cost inflation. Just maybe from a high level perspective, how you all are thinking about those?

[Thomas B. Nusz:]

Sure. First, with respect to service costs, what we're seeing at least at this point is not a lot of move overall in the service costs. There's pockets of small things that we've seen bump up. We're optimistic on the pressure pumping side that it's going to be flat to down. And so we're not anticipating a big move in service costs for 2019, but we'll continue to monitor that. Now, with respect to the non-op, we're just going to have to do like we normally do, which is we engage with all of our working interest partners that are of size and get their budgets. But based on programs, we think other operators are going to grow their programs a bit. Everybody is kind of focused on spending within cash flow. You may see a little more activity in Delaware in terms of an increase than you're going to see in the Williston, but I would think both of them would be up at least a bit, but probably not a huge amount.

[John A. Freeman:]

Great. And then if I was looking at slide 11 in the recent presentation, it still shows the outperformance in the Delaware, but it does appear the most recent five Wolfcamp A wells maybe aren't showing the same level of outperformance relative to the type curve that the previous eight kind of Wolfcamp A/B wells did. And I'm just wondering if there's anything kind of materially different on those last five regarding either completion design, location, something along those lines.

[Taylor L. Reid:]

Hey, John, you just have a bigger sampling of wells. The prior graph that we showed when you got out in time, you really had one well that was impacting a lot of the outperformance and that was the original Bighorn well that we talked about that continues to still flow. That well is an outstanding performer. And as we've just put more wells in that overall type curve, you could see it continues to outperform in some of the out time because it's not just dominated by one well. You're seeing a grouping of wells and good news, they're all doing well. So, we're still excited about the results we're seeing there. And you know how programs go, you get some wells that while they outperformed, some maybe a little bit under and overall you want to be over your type curve performance.

[John A. Freeman:]

Great. Thanks, guys. I appreciate it.

[Michael H. Lou:]

Thanks, John.

[Thomas B. Nusz:]

Thanks.

[Operator:]

The next question comes from Noel Parks o Coker & Palmer. Please go ahead.

[Noel Parks:]

Good morning.

[Thomas B. Nusz:]

Hey, Noel.

[Noel Parks:]

I was wondering about the second Bone Spring, you said you're encouraged by what you'd seen there so far. How much of your acreage is prospective for that and just learn some basics about the thickness and I assume it's a sand.

[Thomas B. Nusz:]

Yes. Actually, the second Bone Springs is a shale. And in terms of what's prospective for it, we've got to continue to drill to hopefully expand the footprint there. So, potentially, it could be across quite a bit of the acreage, if not all of it, but got to do more drilling. Two wells, early time, but they both look good and really add some nice incremental inventory if it works over a broader area. So, it's just the indication of the kind of thing you've got with that thick of a column and most of the focus really haven't been on the Wolfcamp A, and then there's been testing above and below it depending on where you are. And as I talked about in the prepared comments, as we do more drilling in the B and the C and then in the Bone Springs, we just hope to bring in more inventory. So, it's a good indicator of kind of things that we think can be ahead for us.

[Noel Parks:]

Great. And I think you might have touched on this. Sorry, if I missed it before but up in the Bakken when you're talking about the results from the enhanced completion wells also being positive at Painted Woods and Red Bank, could just give a little bit of detail on the nature of the improvement, what you're seeing?

[Taylor L. Reid:]

Yeah. So, it's really early time at this point and I think one of the good indicators is the way the wells are flowing back. So this is the Florence Well that is in Painted Woods. As I said, it's been on a little under three months. The well continues to flow. Wells in those areas historically would flow for a shorter amount of time and go on pump pretty quick. So these bigger enhanced completions are – you're seeing a lot more – like we have seen in other areas, you're seeing wells flow for longer periods of times at higher rates. And so we – as I said before, what that has done is moved what was previously extended core now into the core bucket. And in terms of how we define that, the core is – provides a 10% rate of return at or below $40 WTI. The extended core is in between $40 and $45, so that gives you an idea of the improvement in results, what it's done in terms of returns on those wells.

[Noel Parks:]

Great. And I just had one quick housekeeping thing. Just looking at the financials, I saw the exploration expense ticked up a bit. I was wondering if that was Delaware – assuming that was Delaware Basin. And also, I saw like kind of a $56 million item of acquisitions on the cash flow. I'm just wondering what that might have pertained to? Thanks.

[Thomas B. Nusz:]

Noel, the acquisitions are the ones that we talked about in the Delaware and then the exploration costs are some write-offs of some earlier activity on wells that pre-worked on wells that we ended up deferring. And we couldn't carry those anymore, so.

[Noel Parks:]

Got it. Okay. Thanks a lot.

[Thomas B. Nusz:]

Yeah. That was all in Williston, the exploration costs. All the land stuff, the acquisition stuff was predominantly in Delaware, the exploration in Williston.

[Thomas B. Nusz:]

You bet.

[Noel Parks:]

Great. Thanks a lot.

[Operator:]

The next question comes from Jeoffrey Lambujon of Tudor, Pickering, Holt. Please go ahead.

[Jeoffrey Restituto Lambujon:]

Good morning, everybody. As we think about the 2019 program, any rough thoughts on how you might allocate the Delaware-specific capital across the different horizons just thinking about how the strong Bone Spring wells, you talked about so far. I'm trying to get a sense for how you're thinking about the timing there and defining that opportunity set.

[Taylor L. Reid:]

Yeah. So it's going to be, like I said, we're going from seven wells in 2018 to 15 to 20 wells in 2019. We don't have a specific breakout between the intervals but it will still be – the majority of the program will still be in the A and then we'll be testing more Bone Spring in B and C. We're also going to have some of those additional intervals not only tested, but incorporated in spacing tests. So we're setting ourselves up for our 2020 development program. So it's a little early to tell you what the exact mix is other than we're going to step it up a bit and set ourselves up for the 2020 development.

[Jeoffrey Restituto Lambujon:]

Got it. And then on the infrastructure side, I know more detail is coming on this as well in early 2019. But any high level thoughts so far on what products might make the most sense as you evaluate the potential there?

[Thomas B. Nusz:]

Jeoffrey, I assume you're talking about Delaware?

[Jeoffrey Restituto Lambujon:]

In Delaware, that's right.

[Thomas B. Nusz:]

Yeah. We're really looking it across kind of all the products in water, oil and gas. And so, we're making evaluations across all of it. There's probably the least competition from – and dollars that have gone to the water side. But we think there's some potential opportunity even on the crude and gas side too. So we're taking a look at all of it.

[Jeoffrey Restituto Lambujon:]

Got it. Appreciate it.

[Operator:]

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

[Michael Anthony Hall:]

Thanks. Good morning.

[Thomas B. Nusz:]

Good morning.

[Michael Anthony Hall:]

Just a few follow-ups I guess. I guess, first on the Permian or in the Permian, you talked about a three-well Wolfcamp A pad that you're currently working. What's the pattern? Like how tightly spaced are those three wells? And when do you think we might get results from that?

[Taylor L. Reid:]

So the pattern is drilling two lower sort of wine rack (42

[Michael Anthony Hall:]

Okay. That's fine. And then, as I was just thinking about the takeaway and the differentials in the Williston, do you have any specifics on how much you were flowing on DAPL and kind of how that looks in 2019 and I saw the MT&G line guided up a little bit on it seems like in part on that. So, I'm just trying to get a handle on just how much are flowing and how to think about that impacting financials in 2019?

[Thomas B. Nusz:]

Yeah. I think the MT&G in the third quarter, Michael, was a little bit of an abnormality. And so, what we tried to talk about is that the increase in MT&G and the decrease in differentials basically offset each other and that's essentially us moving some extra volumes down. Think about it as more of a spot basis through marketers on that DAPL line. And so, you just kind of transfer it a little bit and you still got very strong differentials quarter-over-quarter. It basically held flat from second to third and we're just giving you a little bit of the details of how that played out. Going forward, I think you just – the best way to look at is MT&G looks more like the first half of our guidance range going forward and differentials look like our guidance range. So, it's not – there was this kind of third quarter anomaly. But I don't think that's true going forward.

[Michael Anthony Hall:]

Okay. And do you have committed capacity on top or is that all being moved through third-party shippers at this point?

[Thomas B. Nusz:]

Yeah. We've got 10,000 a day on DAPL, so it's a small portion but we still do flow quite a bit through other parties through DAPL along with rail to the coastal markets. Basically, we think almost all of our production moves to coastal markets at this point and you can see that in our pricing how strong it is.

[Michael Anthony Hall:]

Okay. That makes sense. And then, I guess, the only other one I had was on just kind of the timing of – I'm assuming that the ramp in the Permian volumes is back-loaded next year. Is that a fair way to think about it with the pipes coming on in the back part of the year, and is there any nuance to the timing of the Williston? Is that more likely a pretty even-loaded cadence with the usual seasonality that we see up there?

[Thomas B. Nusz:]

Yeah. Williston, you'll always see a little bit of a slower activity in the first half because of winter weather and breakup, et cetera. And so I think you should always think about Williston is a little bit more backend-loaded. And then like you said on the Permian side, I think you're exactly right that it's going to be a little bit more backend-loaded really around the pipelines, and we think differentials are going to be incredibly strong going into the end of 2019 and into 2020. But really, you don't want to overload volumes into a bad constrained market.

[Michael Anthony Hall:]

Okay.

[Taylor L. Reid:]

And, Michael, back on the well spacing, the three-well test in the Wolfcamp, it's within the same interval. So the two wells that are in the lower Wolfcamp A interval, that's 800-foot spacing between those wells.

[Michael Anthony Hall:]

Okay.

[Taylor L. Reid:]

If you look between the upper Wolfcamp A well and the lower Wolfcamp A well, it's right in between the two, so it'd be 400 between those two wells.

[Michael Anthony Hall:]

Perfect. That's helpful. Thanks, guys. Appreciate all the color.

[Taylor L. Reid:]

All right, Michael. Thanks.

[Operator:]

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

[Ronald E. Mills:]

Good morning. Just as it relates to the Williston activity, Taylor, you talked about the Painted Woods area and mentioned Red Bank as well. And since you've had most of your activity in Wild Basin, Indian Hills and Alger, how do you think today that you fold in incremental activity outside of those three recent focus areas and move into Painted Woods or Red Bank or do you shift back?

[Taylor L. Reid:]

Yeah. So Ron, the program is still going to be really dominated by Wild Basin, Indian Hills and then Alger, although a shift to kind of the north part of Alger. And so in Wild Basin, you're going to continue to run one to two rigs during the year, mostly you're probably in the two-rig range, and then you're going to have like I said probably a rig over in North Alger, and then you're going to have Indian Hills with activity, and then Red Bank with activity. Painted Woods, we may be delayed a little bit longer the next year until we get more of these well results, but that would set us up there for late next year and going into the following year.

[Ronald E. Mills:]

Okay. Great. And then from a CapEx standpoint, Michael, maybe just clarify a little bit when you talk about from an E&P spending standpoint, it will go up given the increased rig count in each area. But can you clarify more of what you're talking about on the infrastructure side? If you didn't spend any more the infrastructure would be down 40%, but Mike, you could read into that as you evaluate incremental growth opportunities in either the Williston or initial build out in your Delaware area that that infrastructure spending could increase again, and would it be as high as this year or somewhere in between?

[Michael H. Lou:]

Yeah. So if you think about the $900-ish million of – $900 million to $930 million, I believe, of E&P capital spend based on Tommy and Taylor's comments around activity levels. You could see that obviously up on the D&C side, mainly because of the Permian activity. So think about that as, I don't know, $100 million, $150 million. So we've kind of doubled the Permian number from this year which is right in line with the number of completions. And then on the Midstream side, what you saw was $300 million of capital to kind of the consolidated Oasis, right, and what we've said is – this year, in 2018. And what we've said is a little over $100 million, or $120 million of that is spent by the Midstream or the MLP and $180 million by the parent. Next year, we think that $300 million basically could be down by, call it, 40%. So both the MLP and the parent end up spending less. So if it's down by 40%, think about it as $180 million total and split about 50-50 between the MLP and the upstream company – and the parent company. And then what we've said is that outspend is going to be funded by drop-downs going forward. And then – so all of that's without the Delaware deal or kind of additional larger Williston projects. And so we're still evaluating. We've still got some good third-party deals. Those are super capital efficient. We think there's some good capital efficient things to do potentially in the Delaware, and we'll figure out is that going to be once again done at the parent and dropped down eventually over time or is that going to be just funded straight at the MLP level. Both of them are possibilities, and so we're continuing to evaluate that. We'll come out and give a little bit more color on that in our February call.

[Ronald E. Mills:]

Okay. Great. And I think Taylor also mentioned the – once you add a third rig in the Delaware, you'd probably move to a dedicated frac spread in that area. Given the state of that market, is it more likely that that's going to be a third-party frac spread or have you all started to contemplate additional expansion on the OWS side?

[Taylor L. Reid:]

So, at this point, we're thinking about it as a third-party. But we're looking at that option to build out spread and have one of our own down there. We'd certainly like to have – and as we've talked about in the past, the way we've approached that part of the business is in a downturn, we want to be supplying all of our activity and capacity. And then in a regular market, third parties are going to provide the incremental piece, say 40%, 50% of the activity. So we'll factor all that stuff into – whether we make that decision when we do it as well.

[Ronald E. Mills:]

Great. Everything else has been asked. Thank you, guys.

[Taylor L. Reid:]

Thanks.

[Thomas B. Nusz:]

All right, Ron, thanks.

[Operator:]

The next question comes from John Aschenbeck of Seaport Global. Please go ahead.

[John W. Aschenbeck:]

Good morning and thanks for taking my questions. For my first one, I was hoping to follow up on the preliminary 2019 commentary. And I was just wondering how we should think about potential acceleration scenarios. Is it as simple as keeping E&P spending within cash flow, and then with that if there was incremental capital to be added to the E&P business next year, I believe you've previously said that would be directed toward the Williston. I was wondering if that's still the case or if you'd be more inclined now to add to the Permian? Thanks.

[Taylor L. Reid:]

So, as we think about the capital spend going into 2019, we're establishing a program around a fairly conservative price deck. It's a lot like we've done this year. And in the event that the price deck runs well above that, the need to go and spend more dollars on the drilling program isn't necessarily there. We've got a lot of options with excess cash flow, and we've talked about the program's ability to generate excess cash flow. And so, it can range from paying down debt, really focusing on – continue to accelerate that move to get below 2 times net debt-to-EBITDA. As Michael mentioned, we're already at 2.4 times, so well on our way on that front. But we'll continue to focus on that side if we have excess cash flow and then there's always the ability to pick up additional acreage like we've talked about this quarter. So, no, not necessarily going to focus on increasing the program. We really want to make sure that we have strong execution with the program that we lay out.

[John W. Aschenbeck:]

Okay. Great. Appreciate the color there. And so, for my follow-up, I was hoping to get a little more detail on the Delaware acquisition. It seems like 20,000 an acre seems like a pretty solid price relative to recent transaction. So, I was just hoping to get a better idea of where the acreage was located, if it was more so in Loving or Ward County. And also I was curious how much value was ascribed to production in terms of a multiple on existing production? And finally, I was wondering if this was more so an increase of working interest in existing units, or if you're able to increase your gross operated footprint?

[Thomas B. Nusz:]

Yeah. So it'll increase gross operated. It's contiguous basically to our position. And I think the way to think about PDP. There's not a lot of PDP but when there's producing 40,000 an acre – 40,000 of flowing barrel, sorry, is probably a good number to think about from that perspective.

[John W. Aschenbeck:]

Okay. Great. In terms of just where the acreage was located, is it fair to think of like a even split between Ward and Loving.

[Thomas B. Nusz:]

Yeah. It's in kind of a little bit in Loving and a little bit within Ward. It's basically a pretty even split.

[John W. Aschenbeck:]

Okay. Great. That's it for me. Thanks.

[Operator:]

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

[Thomas B. Nusz:]

Great. Thanks, Danielle. To sum it up, Oasis continues to execute on our long-term plan with our deep low-cost inventory in the Williston driving capital efficient growth for years to come. In the Delaware, we continue to delineate our position and accretively grow our footprint as windows of opportunity open up. As the industry moves towards development across the Permian, an important differentiator will be operating ability. On that note, I'm extremely confident that we have the right team in place and our decade-plus experience and developing the Williston will serve us well as we begin to ramp up in the Delaware. Thanks again for joining our call.

[Operator:]

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