Chord Energy Corp

NASDAQ:CHRD

Earnings Call Transcript 2019-Q1

[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 First Quarter 2019 Earnings Release and Operations Update for Oasis Petroleum. [Operator Instructions] 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. Thank you. You may begin the conference.

[Michael Lou, executive]

Thank you, Danielle. Good morning, everyone. Today, we are reporting our first quarter 2019 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 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 have described in our earnings releases 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 statement.

During this conference call, we will make references to non-GAAP measures, and reconciliations to the applicable GAAP measures can be found in our earnings releases 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 Nusz, executive]

Good morning, and thanks for joining our call. The Oasis team is off to a very good start in 2019, operationally execution has been solid and has led us to exceed production expectations in the first quarter, while keeping our costs in check.

Taylor will provide more color on our operations in a moment, but I wanted to highlight a few key points regarding our performance and strategy. First, in spite of some challenging weather conditions, production exceeded expectations on both oil and on a Boe basis. In the Williston, we brought on 12 wells during the first quarter.

Second, in the Delaware, we continue to make progress delineating our position and understanding the subsurface. We brought on 3 wells during the quarter, well performance remained strong and we look to -- look forward to testing various development concepts over the course of 2019, including 8 wells in the Bighorn spacing unit.

Third, our operating efficiency continues to stand out among our peers. Page 13 of our investor presentation highlights our recycle ratio, which is top tier within our peer group reflecting a combination of strong well productivity, cash margins and capital cost efficiency.

And fourth, Oasis remains focused on executing it prudent development program in 2019 and generating free cash flow. We're on track with our budget and have no plans at this point to accelerate activity. Commodity prices have strengthened materially since earlier this year and we continue to take advantage of higher priced windows to roll in additional 2019 and 2020 hedges.

The team continues to do a great job executing the -- against the 4 cornerstones of our strategy that we laid out in 2017. Those are, size and scale, portfolio diversity, asset quality and financial strength. This strategy continues to serve us well in the face of uncertain oil prices. Our management of E&P spending within cash flow over the last 4 years has clearly demonstrated that Oasis is built and managed to withstand even and even prosper and lower price environment, given our deep inventory, which now spans to low cost basins, our experienced workforce, our financial management, and our ability to manage business risks.

We designed the business to have the flexibility to efficiently ramp-up and down depending on market conditions with an aim to generate free cash flow in the E&P business even in low price environment.

Slide 7, is our updated free cash flow projection for 2019, which captures first quarter actuals in our updated guidance. The team remains financially disciplined and we have continued to prioritize return to our shareholders, which we have clearly demonstrated through the last few years. With 2 core assets and 2 of the lowest cost oil basins in the United States, we have strong inventory depth allowing us to earn attractive returns, the low prices. Additionally, our midstream and well services businesses provide a tremendous competitive advantage. We've made progress on -- on several fronts on our midstream business. But I'll highlight just a couple.

We're ramping up our second gas plant in the Williston, a bit quicker than anticipated, performance has been excellent and our capture rates are now at record levels. As I've said before, the team has done a tremendous -- it’s had tremendous foresight and moving forward with this project and we have run as much as 300 million standard cubic feet per day through our processing complex. Also the capture of third-party business has been going extremely well.

Moving onto the Delaware, we announced yesterday that Oasis plans to dedicate certain acreage to OMP for crude oil and produced water infrastructure development. We'll get into more detail later on the call, but this is a strong win for Oasis as will benefit from the surety of service, reliability and cost advantages provided by OMP. We believe Oasis is 1 of the best-positioned companies in this sector and represents a uniquely attractive investment opportunity.

With that, I'll turn the call over to Taylor.

[Taylor Reid, executive]

Thanks, Tommy. Oasis' 2019 development plan is generally in line with the last update. We continue to expect second quarter through fourth quarter 2019 production to average between 86,000 and 91,000 Boes per day. As we indicated in February, the oil cut is expect to average about 72% throughout the year, with the fourth quarter at about 71%.

In the Williston, we entered the year at 4 rigs, dropped to 3 in February, and will be a 2 later this month. We continue to run 2 OWS frac crews as well. Oasis well productivity in the Williston remains at the top of the pack. As seen on Slide 10, we are ranked #1 for the 12-month average cumulative oil equivalent versus our peers. Additionally, we continue to be encouraged by delineation results from step-out areas.

Slide 9, in our investor presentation has been updated to reflect the latest data from select emerging areas in the Williston. Clearly, we're seeing results in Painted Woods, North Alger, South Cottonwood in Montana, which indicate these areas are competitive with the rest of the basin. In Painted Woods, we provided additional production history, which validates our view that the area is highly productive with low economic breakeven. In North area -- in North Alger and South Cottonwood, we've also seen a significant increase in productivity for wells with current completion techniques.

In fact, if you look at Slide 8, you will see that wells in the Painted Woods and North Alger area compare favorably with our core Indian Hills result. As you can see, economics have taken a major leap forward with advanced completion techniques, and we expect that to drive these even further in coming years. As a reminder, our inventory in the Burke Basin is secure, as we have no drilling obligations on this acreage.

In the Delaware, we're currently running 2 rigs and continue to expect to complete 9 to 11 wells this year. Volumes are expected to increase approximately 50% year-over-year and exit 2019 at 89,000 Boes per day. We have earned a tremendous amount over the past year or so and continue to supplement our knowledge through our operated activity, nonoperated activity and third-party data sources.

Importantly, I'm pleased to report, we've made significant progress in reducing our drilling times and our well costs. Our most recent wells with 2 mile laterals have been drilled in 25 to 30 days versus our first wells in basin that were in the 40 day range, drilling speed to continue to improve as we continue to optimize well design and shipped to pad development. In development mode, we would expect drill times to be in the mid to low-20. Well costs are approaching $10 million versus $11.5 million last year and our well productivity remain strong. On the Southwest portion of our acreage, we recently brought on the Wolfcamp C well, which producing on par with our Wolfcamp A wells, which highlight the extreme depth and productivity of this resource.

In addition, our Third Bone Spring Shale wells, once considered an upside zone are exceeding our expectation. During the second quarter, we plan to complete a 3 well Wolfcamp A spacing test with 2 in the lower and one in the upper interval. The remainder of the 2019 program will be focused on the Wolfcamp A with additional tests in the Wolfcamp B, C and Third Bone Spring.

We will also be conducting a larger spacing test with an 8-well pad to be drilled in 2019, and completed and brought online in 2020. We are excited about moving into full-field development and know that the Delaware will be a major driver of growth from returns for years to come.

To close, we continue to execute on our conservative 2019 plan. The recent commodity price rally should only strengthen our financial position and returns outlook. Our team got us off to a great start in Q1, by leveraging their top notch technical skills to drive capital productivity across our asset. And I challenge them to maintain the momentum that they have established for the rest of the year.

With that, I'll now turn the call over to Michael.

[Michael Lou, executive]

Thanks, Taylor. Due to the strength of our operating team and our assets, we executed well in the quarter and exceeded our volume guidance. We remain on a trajectory to generate significant free cash flow over 2019. Our CapEx is in line with our expectations and we were able to get significant work done in the first quarter.

In the Williston, all of our work is in development mode where we achieved the highest capital efficiency. One factor of development mode is wells come online in groups of wells, rather than one at a time. So while we were able to get a lot of activity done in the first quarter, our wells put on production looks a bit lower this quarter and will catch-up over the next 2 quarters.

Once again, all this activity in the first quarter was extremely close to our planned activity level and production continue to come in strong. Remember also, that during our budgeting process, oil prices were at or below $50 per barrel and recent -- and recent prices remain well above these levels. But we have no plans to accelerate activity.

Note that, on Page 7 in our presentation, that $50 oil, we now expect to generate close to $200 million in free cash flow in our E&P business versus approximately $150 million in the February presentation. This increase is due to strong production, lower LOE, type differentials, opportunistic hedging and overall efficiency of our operations.

We continue to enjoy strong liquidity levels with the borrowing base of 1.6 and $493 million drawn on our credit facility as of March 31, 2019. Oasis has a net debt to first quarter '19 annualized EBITDA multiple of 2.4x with adjusted EBITDA attributable to Oasis of approximating $259 million in the first quarter. Capital expenditures during the first quarter were $226.8 million, in line with the company's first quarter 2019 plan for both E&P and Midstream businesses.

As Tommy mentioned, we're excited to announce that the Boards of Oasis and the general partner of OMP have approved the dedication by Oasis of acreage to OMP for crude oil gathering and produced water gathering and disposal. Final agreements have not been executed, but the Boards did approve the agreements on terms similar to existing commercial agreements between Oasis and OMP in the Williston Basin. OMP will form a new development company called Panther DevCo, which will be 100% owned by OMP. As you know, both Oasis and OMP have been working hard to create a symbiotic and synergistic relationship that supports the development of the Delaware.

Under this new arrangement, OMP expects to spend an additional $53 million to $57 million in 2019 on building out additional infrastructure. Total gross midstream capital expenditures are expected to be $195 million to $219 million in 2019, with about $11 million to $13 million of that net to Oasis. Oasis portion consists mostly of maintenance capital and a little growth capital in Beartooth.

This is a huge win for both companies. For Oasis, given that OMP is a separate bankruptcy remote company is great that Oasis is able to improve its balance sheet by using its projected cash flow to build on its top tier E&P assets and generate significant free cash flow for its investors. For OMP, this is an incredible opportunity to diversify its assets, enter another top-tier oil basin and set itself up to support Oasis as an anchor tenant and access third-party volumes as well, while maintaining a very strong OMP balance sheet.

Overall, OMP continues to perform well, as we exceeded expectations during the quarter. 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.

Turning to hedges. Our development program is protected by our strong position, just to update you on that front, we are fairly well hedged for 2019 at around 2/3 of our forecasted oil volumes with 1/3 of those volumes swapped and 2/3 in collars.

Our 2019 WTI collars have an average ceiling of about $70 and floor of approximately $55. This strategy protects our capital program and lower price environment, while also allowing us to capture more upside should prices continue to recover. As you can see on Slide 24 of our presentation, we've taken advantage of recent strength and significantly added to our 2020 program during the quarter.

On the operational cost front, we performed towards the low end of our LOE guidance, with LOE per Boe averaging $7.08 in the first quarter. We lowered our LOE guidance to be in the $7 to $7.75 per Boe range for 2019. Williston crude differentials improved significantly versus the fourth quarter of 2018, our marketing team continues to do a fantastic job consistently delivering pure leading differentials through various market fluctuations. In the Delaware, as expected, crude differentials have narrowed considerably versus last year and several new long-haul pipes coming online in the back half of 2019 should continue to improve realizations.

We continue to expect differentials to be in the $1.50 to $3.50 range over the course of the year, and clearly, we were on the low side of this in the first quarter. Marketing transportation and gathering expense per Boe averaged $3.96 per Boe over the quarter. As you've seen in years past, this metric will ebb and flow a bit depending on how much space we book on long-haul pipes, in addition to other factors. We now expect to average $3.50 to $4.50 over the course of 2019.

To sum things up, Oasis continues to execute well and we're in a strong position to deliver in 2019 and beyond.

With that, I'll hand the call back over to Danielle for questions.

[Operator]

[Operator Instructions] The first question comes from Derrick Whitfield of Stifel.

[Derrick Whitfield, analyst]

Perhaps for Tommy or Taylor, your Q1 production was meaningfully above consensus and our estimate, despite only completing 15 wells or 19% of your 2019 plan, what do you guys attribute to that performance and more specifically were there any base production initiatives underway in Q1?

[Taylor Reid, executive]

Yes. So when you look at the well count, we're at 15 wells total and -- so we brought in -- production was pretty strong coming into the year and that combined with -- really had good performance, like -- I think, Tommy talked about in his comments, in spite of a cold weather or we'd normally expect a turn of downtime. We had really good uptime in performance, particularly what it points to is the -- the infrastructure system, we talk a lot about being able to move our barrels primarily on pipe. So not having much trucking when you're getting bad winter, we're able to continue to move our barrels. So we had bit of downtime when it was 30, 40 below, but generally really good uptime throughout that weather period.

[Thomas Nusz, executive]

And I'll add, the guys have done a great job both managing downtime and kind of through tracking wells -- tracking the wells remotely and anticipating failures and just keeping the wells producing and they have just done a great job.

[Derrick Whitfield, analyst]

Very helpful, and as my follow up, referencing Page 8, the North Alger or South Cottonwood well was quite impressive. Do you guys expect a meaningful change in geology between that well in the number 6 on your map as you move north into South Cottonwood?

[Thomas Nusz, executive]

Yes. So generally, as you look at that side of the basin as you move north, you're -- you get shallower, so you lose a bit of pressure, but it's a gradual change as you go north. So there's -- and then there's the saturations change a bit as you go north as well. You tend to get a little higher water cut. So in the extreme north end Cottonwood, it's more like a 60% water, whereas that area where the North Alger, Cottonwood well as it's probably more like a 40% water cut, 30%, 40% water cut. So you're going to see some drop-off, but it's gradation also weak, we expect the wells are still going to be good as you go north. The -- we're actually drilling some wells, a bit further north from what we've done or what we're showing here right now and will bring on those later this year. So we talk more about it then.

[Operator]

The next question comes from Oliver Huang of Tudor, Pickering, Holt.

[Hsu-Lei Huang, analyst]

Were the 8-well spacing test in the Bighorn spacing unit, I was wondering if you all might be able to provide some incremental color as to the plant completion designs based in [ content ] you all are planning to test there?

[Thomas Nusz, executive]

Sure. So it's an 8-well test and it's going to be a combination of Bone Springs 3 and Wolfcamp A. And so it will actually be 4 wells in the Bone Springs 3 and then 4 in the Wolfcamp A. The -- as far as the, well, let me talk a little bit more about spacing. So when you look in the Wolfcamp A, there's 2 parent wells already existing. So spacing will effectively be [ 80% ] between the wells and/or it would be like 6 wells within a Wolfcamp A bench, and this is primarily focused in this well in the lower Wolfcamp A and then the 4 wells in Third Bone Spring 3 which would be more like 1,300 foot spacing. So that's similar to what we talked about. As we did the acquisition and we're testing spacing between those lower Wolfcamp A wells and also testing with the interference or the interplay looks like between the Wolfcamp A and in the Bone Springs 3. So this is our first, I think if you guys know our first well really drilling in density and we'll take our learnings from this and then apply it into the next when we do going forward. As far as stimulation, it's going to be fairly similar to what we've been doing so far and we continue to optimize around number of stages, clusters, all those things. Fluid loading is the same. Sand has been optimized down a little bit from our first completions, but still robust. So this is our -- now that we've done about 10 wells, we've been able to optimize the design and we think it will work well on the spacing pattern.

[Hsu-Lei Huang, analyst]

Okay, perfect. That's really helpful. And for a second question, I know this is probably something that has been in the works for several months now. But as a result of the acreage dedication midstream agreement announced last night, has anything changed in terms of how you all are thinking about capital allocations for the corporate portfolio going forward?

[Michael Lou, executive]

No, I think what we've said is that we want to keep at the parent company all the cash flow going towards continuing to drill in that -- in the E&P assets, and generating free cash flow. And I think that's exactly what we're doing there. From a midstream perspective, it's continuing to grow that asset base, stay very reasonably levered, given that their bankruptcy remote we think about kind of their balance sheet separately. So you're keeping a very strong balance sheet to OMP side, you're diversifying your asset base into what we think is also a very premiere area in the Delaware, and we think having an anchor tenant in Oasis is a good thing from a midstream perspective and then they can pursue third-party opportunities which we think there are some both on the water and on the crude side. So we really think it's a win-win from both perspectives, it's exactly what we've been talking about for -- since we did the Delaware acquisition, is how do we continue to make sure that the parent can use its cash flow to continue to return to shareholders and generate great returns and focus mainly on the E&P side and let the midstream focus on the midstream business. So following that plan exactly.

[Operator]

The next question comes from Ron Mills of Johnson Rice.

[Ronald Mills, analyst]

One quick follow-up on the Bighorn spacing test or I guess an extension of that you're testing Third Bone Springs in the Wolfcamp A there. Can you think -- look ahead to next year at some point, do you think you -- when do you think you get to maybe even testing more complete of kind of a cube development in terms of maybe adding the Wolfcamp B and the Wolfcamp C under a particular section?

[Taylor Reid, executive]

Yes. Ron, we're -- as we talked about, we're test and just independent wells in the B and the C. So we want to understand productivity for those intervals around the position. As we're looking at it, we're still trying to understand the interplay between the A and the B. So we'll have some test around that, but certainly for part of the acreage, we think that there is a barrier between the A and the B intervals. And we're going to try to confirm that around -- across -- across the whole acreage position. And so it may turn out that in some of this you can, it's compartmentalized and you do the A, up to Third Bone Springs and one package and the B and the C would be another package that would come up later on. But still early time, really want to understand that, that upper package first and then understand the economics of the B and the C wells independently and then figure out where we need to add it into a whole queue, but that -- you're right, that's where we're headed is to this -- to that cube development concept.

[Ronald Mills, analyst]

Okay. And then moving on mining, the 6-well Wolfcamp A, I guess the 3-well Wolfcamp A spacing that you have coming up, is that just -- is that design, what kind of the horizontal well spacing are you testing in vertical well spacing? Just a little bit more information about what that is testing versus what are there -- yourself or offset operators who have already started to testing it that?

[Taylor Reid, executive]

You bet. So that's the 3-well Wolfcamp A spacing test and it's test in the upper and the lower. And so you've got one well in the upper and then 2 in the lower. And the distance between each of the wells is 440 feet. If you look at that, just the 2 wells in the lower, they are 880 feet apart and then the distance between those lower and those uppers on a horizontal basis is 440 each. And so with that, I think we'll get a good test of that inner well spacing and then how the interplay is between the upper and the lower.

[Ronald Mills, analyst]

Okay. And lastly just bigger picture. When you have a couple of rigs in the Williston is with the plan and then you have 2 in the Delaware. If you think forward 12 to 24 months, how do you think capital allocation and activity will look between your 2 basins and relative growth contribution? And that's it.

[Taylor Reid, executive]

You bet. Right now we've got this 2 and 2 and it balance is pretty well because with the Williston, we're able to generate excess cash flow as we talk about before it fund the program in the Permian. As that Permian asset grows, it's going to be able to fund a greater portion of its own capital which is going to give us a lot of flexibility. If same-same as everything is like it is right now, we're probably going to have the growth in the program, at least in the next 1 to 2 years likely to be more than the growth in the program in the Williston, but keep in mind and that's getting it to doing the same thing in the Permian, that we're doing the Williston, which is full-field development and going in and drilling out spacing units then keep in mind the cycle times in the Permian for about twice. So you got or little bit more, you're doing wells in the Williston in 12 to 14 days, and then as we talk about, we're in the 25 to 30-day range in the Permian. So you just need more resources to get the same work done. So 2 rig program in Williston, you're getting a lot more done and if we get to a 3 or 4 rig program at least at this point, we're going to continue to drive the cycle times down. Last point I would make though is, we want to maintain the flexibility, Ron, to be able to allocate capital according to the environment we're in. We know we've been able to do that through this period of lower oil prices we demonstrated it when we got pipe, pipe short in the Permian. We maintained a kind of a slower pace. And we want ability to allocate that capital back between the basin is dependent on the environment that we're in. We've got a program set up to do that.

[Operator]

The next question comes from David Deckelbaum of Cowen.

[David Deckelbaum, analyst]

Just curious as you evaluated the acreage dedication and form this Panther DevCo, you're building out water and oil. Can you talk about the negotiations on the gas processing side. And why you elected to go with the third-party in that direction?

[Michael Lou, executive]

Yes, so we're out in RFP process for the gas side, we think there are lot of very strong third parties that we can do business with out there, from an acreage dedication standpoint, it does seem like the gas side is a little bit more dedicated, we thought that there was a little bit more opportunity from an OMP perspective on water and oil at this point. And just want to be prudent for OMP on where they spend their capital. And so of the 3 kind of different oil, gas and water -- the 3 different kind of things that you're taking off out of the well, we thought the crude in the water side had more opportunity.

[David Deckelbaum, analyst]

I appreciate that. I guess, as we think about this buildout now in the Delaware, should that be more or less the only capital that we see on the midstream line in 2020?

[Michael Lou, executive]

Yes. There's going to be -- are you talking about from the parent side or from...

[David Deckelbaum, analyst]

Just like on this fully consolidated level?

[Michael Lou, executive]

Yes. Obviously, there is from an OMP perspective, they're going to be working on third-party kind of opportunities, which are always very strong. If you think it kind of build multiples, based on kind of just building off of the asset. And so there're certainly opportunities like that, that may come up, but those are shipper high capital efficiency type opportunities. There's obviously work in the Delaware that we've kind of laid out, and then there is likely to be some ongoing stuff in the Williston as you think about building out on current acreage dedication, some of that gathering system both in Wild Basin as well as in the Beartooth asset.

[David Deckelbaum, analyst]

Got it. And if I could just ask one more, I know in the past and then Taylor you kind of alluded to this in some of the prior questions, but thinking about growing oil into next year and sort of this $50 environment and are there free cash stroller, free cash generative We want to sort of assume that, that happens with this current rig count exiting 2019? And then I guess, how do we think about driving that growth is it -- is it a function of getting some of the cycle times compressed in the Delaware, is it a function of the base decline moderating from this year and that's one thing, just was trying to understand how you see the mechanics there of sort of delivering that growth without the rig additions?

[Taylor Reid, executive]

Yes, it's -- you touched on a couple of things. And first, when you look at the projection, as we've talked about, it's pretty, it's really flat at 86 to 91 for the year. We came in at the top end on first quarter, and then the oil cuts dropping. So that implies slight decline in oil production. And then as you look at it going forward into 2020, the base declines as we've slowed down moderate. And so with that moderated base decline you have less to battle. And then on top of that, you've got cycle times in inefficiencies, as we -- one of the things we're excited about in the Delaware as we go into development, we're going to go from drilling, singles, doubles and triples to doing really all pad development and reaping the benefits like we've done in Williston of pad operations. The efficiency of getting cost down and in the cycle times down as well. We think all that bodes well for us to get back into growth.

[David Deckelbaum, analyst]

As you progress into the pad development is there -- do you -- is that a call on having more rigs and more crews in the Delaware? Is it still just being able to keep -- how do you compress that cycle times going from where you are now into next year?

[Taylor Reid, executive]

Yes. So it's probably similar, in terms of rig count, but it's just bringing cycle times down. As we talk, we move from our very first wells in the basin, a little over a year ago at around 40 days. We're now 25 to 30 days, and that's non-pad operations, you get into pad operations and get the benefits of that drilling in and then optimizing our completion techniques as well all that, we think will bode well to improve. So you think same amount of equipment you're going to get more work.

[Operator]

Our next question comes from Michael Hall with Heikkinen.

[Michael Hall, analyst]

Wondering, if maybe you could provide kind of where you see the balance sheet at the end of this year and the end of next year on the current strip? And then in that context of that, you've hedged some of 2020 strips, well north of $50 at this point. Is there any evolution that you're thinking about the potential of that activity in 2020, as you kind of derisk downside as you bring on more and more hedges?

[Michael Lou, executive]

Yes. So Michael, I think the way we're thinking about it is there is a commitment from us to continue to generate a significant amount of cash flow. And then we have to continue to think about, okay, are we going to -- what else are we going to. We got a great asset base. I think you want to get to and Taylor mentioned that this kind of efficiency in the Delaware, similar to what we have in the Williston and try to figure out exactly kind of where that all plays out. Like you mentioned, we're able to do some things even this year in a $50 world, given kind of where the strip prices are doing some hedging as well as just getting better at our business on all fronts. LOE, diffs, et cetera, to generate more cash flow at the $50 case. So that's fantastic. And then as we think about next year, we'll continue to think about that. Like you said, we've layered in some hedges in 2020 at certainly higher than $50 and we'll continue to look to kind of on a incremental basis continue to add to that on a each month. So as we start getting into a little bit more kind of comfort into next year's plan we'll come out with where we come out. But once again, it's going to be what we've said in the past and I think where you're seeing this change a little bit is, we were spending to grow within cash flow in the past. And now we're spending and we're going to generate significant amount of free cash flow. We're certainly going to try to do that and generate some growth over time as well. And some of the things that Taylor mentioned, will certainly help us get there, whether it's efficiencies, driving down costs, generating more free cash flow. And then as that program moderates from off of high growth rates over the last couple of years, your decline rate comes down and you'll be able to generate more growth from that standpoint as well.

[Taylor Reid, executive]

Michael, I'd also add that it's -- it's a bit of a circular discussion, because as you start to -- as opposed to setting capital, or setting rig counts, or setting frac crews and then you've got -- okay, oil place environment in my hand. I think as you've seen in the Williston, the important thing is being able to maintain a program and consistency of crews and efficiency and that's the most important thing is to be able to do that. So that you're not picking up a rig and then dropping a rig, picking up a rig, dropping a rig or same thing with frac crews, because that's wildly inefficient. And so anything that we can do to maintain consistency and efficiency, I think drive -- now we always have to be mindful of oil price and cash that we have to deploy or allocate. But we're -- really going to focus on, especially as you move to full-field development in the Delaware is this how to -- how can we be the most efficient, that we can be and manage our cost.

[Michael Hall, analyst]

Okay, that's helpful color. Appreciate it. And I guess on that, do you have a view on the balance sheet, kind of at year-end and in 2020, in terms of net debt-to-EBITDA on the strip?

[Thomas Nusz, executive]

Yes, I mean, obviously, you're coming down at the strip and it depends on the day, but call it under 2.5x, as you move out in time.

[Michael Hall, analyst]

Okay. And then the other thing I wanted to, I guess just get into a little bit with on the efficiencies in the cycle time improvements that you're also driving in the Delaware. Just to understand how we should think about that playing forward, that level. You highlighted in the deck, are those sort of cycle times and well costs, I guess durable today and something we should play forward? Or how should we think about that over the course of 2019?

[Taylor Reid, executive]

Yes. So that's really what we're doing currently and that's -- as we look at the plan this year, that's kind of what we've baked. Now we will continue to be focused on and hope to drive that down further and so that really provides an upside for us in terms of both the cycle times in the well costs and keep in mind the well cost it's the benefit of less days, but it's also really getting our completion designs optimized for these wells and then, like, we talked about getting into pad operations is really going to be a big benefit.

[Operator]

The next question comes from Noel Parks of Coker and Palmer.

[Noel Parks, analyst]

I just listening to you, you talk about the progress you've made with Painted Woods and Alger and there -- their returns now being competitive with the core. In my perspective, the progress there has been so gradual and incremental that it's pretty, you have come a long way in those areas. I wonder if you could just kind of review for me, what the components of the improvement were just because it's -- for a long time, we thought of those as being very much the sort of the lower productivity assets?

[Thomas Nusz, executive]

Yes. So it's kind of like what we did in the core and that our original stimulation were the older hybrid jobs. And so there classic and across linked gel frac jobs that were smaller before 2014 and really before they're kind of 4 million pounds and then also the number of stages and the older jobs were less. So you had more in the 28 to 36 stages and then cluster spacing was different as well. So we've gone to just really like we evolved in the core to more stages, tighter cluster spacing, which just leads to a better distributed frac across the whole lateral and then higher intensity job. So went from cross link, the old cross link jobs that had been done out on the edges of the -- added, what was the old core to slick water jobs and these new wells we've tested generally around 1,000 pounds to up to 2,000 pounds per foot or proppant with slick water, so much bigger volumes of water. And then you combine that with high capacity artificial lift. We've done a lot of work with electrical submersible pumps, also some jet pumps. But a lot of it is ESP, and so you combine these bigger jobs, high capacity lift, a lot of work on getting like I said, better distribution that frac across the lateral and you're just seeing good results super encouraging. What we're seeing in that in both of these areas. And if you -- I'm sure you guys have been tuned into some of the other operators in the basin, they're reporting similar things really across the position outside of the core, so there's -- and you see it on this map, we talk about the number of these jobs need to these areas. So on Montana alone, you've got 20 wells that are more modern completion techniques. And so that's really bumping up the results there as well and we'll continue to do push out and do more pilots as we go.

[Noel Parks, analyst]

Great. And I have just a couple of housekeeping questions, one of them is in the Delaware and I think you made this change a few months ago, but it only just registered with me now. What you're now calling the Third Bone Spring Shale. That's what you were calling the second before, is that right?

[Thomas Nusz, executive]

Correct. This time we're quite, but we call the second before now we're -- and we're going to this Third Bone Spring Shale.

[Noel Parks, analyst]

Okay, great. And just one other thing, when you guys were reviewing the guidance and you talked about the 2019 exit rate, I actually missed the number and just wanted to check, is that unchanged from last quarter -- the number you gave last quarter?

[Thomas Nusz, executive]

Correct. It's the same as last quarter.

[Operator]

The next question comes from Gail Nicholson of Stephens.

[Gail Nicholson Dodds, analyst]

Just looking at all the low ends of that, low end of the guidance in the first quarter you lowered it from the top end of the guide range the remainder of the year. Is that all just incremental volume driven or is there something else going on at an -- from an initiative standpoint that you are trending towards that low end of that guide range in 1Q?

[Thomas Nusz, executive]

Yes. So it's -- volumes were good in the first quarter, but along with that what we talked about less downtime on wells, less workover costs. Historically, the winter has been a higher LOE period and we've got some of that, that impacted us, but we just did a really good job of keeping our production online and keeping overall cost down. One of the things that the tremendous amount of work has been done on and hats off to the team is our failure rate on our -- in our artificial lift in the amount of focus the guys have put on that has really paid dividends and we're at historic lows for our failure rates on both our rod pump wells and our submersible pumps.

[Gail Nicholson Dodds, analyst]

And then just a housekeeping question. When we look at the oil price realization guide as well as the marketing transport and gathering guide, what percent of your volume is on DAPL on based upon that guys?

[Michael Lou, executive]

Yes. The marketing side, you can think about percentage of volumes on DAPL or other kind of long-haul pipes like that being somewhere in the 25% range.

[Gail Nicholson Dodds, analyst]

And then for comparison, what were they in 1Q?

[Michael Lou, executive]

About in the 25% range. It's not changing.

[Gail Nicholson Dodds, analyst]

Okay, great. Thank you.

[Michael Lou, executive]

In previous years, it was a little bit lower, but it came up in the first quarter and it should be that the rest of the year.

[Operator]

The next question comes from Michael Glick of JP Morgan.

[Michael Glick, analyst]

Hey. Just one bigger picture question from me. So we don't think Oasis' stock price reflects much value for the midstream business. And although the math is pretty simple, the consolidation of O&P could be securing the value and free cash flow power of the E&P business. So could you all talk about, how you're thinking long-term about the relationship between OMP and Oasis? And what you consider strategically to unlock the value at Oasis?

[Thomas Nusz, executive]

Yes, I think it's -- we've derived tremendous benefit out of having control of infrastructure and we've talked about this for a long time. You look at our gas capture rates as an example in the Williston, relative to some of the peers and the ability to have the foresight to say, hey, gas capture is going to be challenged and how do we get out in front of that? And we did that and -- so I think that being able to move oil and water, and what it was historically cold. I think maybe second coldest on -- in the history in February and to be able to keep things moving. I can't -- I mean it's difficult for me to overstate how important that stuff is to maintaining the base business. Now over time, does that change, there may be some point in the future where it's not quite as strategic for us. But even at this stage in the Williston you can see how important that is. And so -- but you've just got to see how that plays out over time. I think in both basins right now, it's extremely important to us. And so we'll continue to monitor that and then see how it works and at some point in the future, down the road, it's not as strategic, then we'll take a look at it. But at the end of the day its cost structure, its reliability and being able to move our products and that goes, then it's the same in both basins.

[Operator]

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

[Thomas Nusz, executive]

Yes, thanks. In closing, Oasis is off to a great start this year, putting us in a strong position to deliver on our program and generate free cash flow. We have the team and the strategy in place to succeed and we look forward to delivering for our shareholders. Again, thanks for joining our call.

[Operator]

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