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. All participants will be in a listen-only mode. Should you need assistance, please signal a conference specialist by pressing the star key followed by 0. After today's presentation, there will be an opportunity to ask questions. To ask a question, you may press star, then 1 on your touch-tone phone. To withdraw your question, please press star, then 2. 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.
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 statements. 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 website. 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.
Good morning. 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 want 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 remains strong, and we 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. Fourth, Oasis remains focused on executing its 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 price windows to roll in additional 2019 and 2020 hedges. The team continues to do a great job executing against the four 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 four years has clearly demonstrated that Oasis is built and managed to withstand and even prosper in lower price environments, given our deep inventory, which now spans two 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 environments. Slide seven has our updated free cash flow projection for 2019, which captures first quarter actuals and our updated guidance. The team remains financially disciplined, we have continued to prioritize return to our shareholders, which we have clearly demonstrated through the last few years.
With two core assets in two of the lowest cost oil basins in the U.S., we have strong inventory depth, allowing us to earn attractive returns at low prices. Additionally, our midstream and well services businesses provide a tremendous competitive advantage. We've made progress 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 had tremendous foresight in 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 on to 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, this is a strong win for Oasis, as we'll benefit from the surety of service, reliability, and cost advantages provided by OMP. We believe Oasis is one of the best-positioned companies in the sector and represents a uniquely attractive investment opportunity. With that, I'll turn the call over to Taylor.
Thanks, Tommy. Oasis' 2019 development plan is generally in line with our 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 expected to average about 72% throughout the year, with the fourth quarter at about 71%. In the Williston, we entered the year at four rigs, dropped to three in February, and will be at two later this month. We continue to run two 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 number one 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 nine in our investor presentation has been updated to reflect the latest data from select emerging areas in the Williston. Clearly, we are 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 break-even. In North Alger and South Cottonwood, we have 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 results. As you can see, economics have taken a major leap forward with advanced completion techniques, and we expect to drive these even further in coming years.
As a reminder, our inventory in the basin is secure as we have no drilling obligations on this acreage. In the Delaware, we are currently running two rigs and continue to expect to complete nine to 11 wells this year. Volumes are expected to increase approximately 50% year-over-year and exit 2019 at 8,000 to 9,000 BOEs per day. We have learned a tremendous amount over the past year or so and continue to supplement our knowledge through our operated activity, non-operated activity, and third-party data sources. Importantly, I am pleased to report we have made significant progress in reducing our drilling times and our well cost. Our most recent wells with 2-mile laterals have been drilled in 25 to 30 days versus our first wells in the basin that were in the 40-day range.
Drilling speeds should continue to improve as we continue to optimize well design and shift to pad development. In development mode, we would expect drill times to be in the mid to low 20s. Well costs are approaching $10 million versus $11.5 million last year, and our well productivity remains strong. On the southwest portion of our acreage, we recently brought on a Wolfcamp C well, which is producing on par with our Wolfcamp A wells, which highlights the extreme depth and productivity of this resource. In addition, our Third Bone Spring Shale wells, once considered an upside zone, are exceeding our expectations. During the second quarter, we plan to complete a three-well Wolfcamp A spacing test with two 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, Wolfcamp C, and Third Bone Spring. We will also be conducting a larger spacing test with an eight-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 and 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. 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.
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 achieve the highest capital efficiency. One factor of development mode is wells come online in groups of wells rather than one at a time. 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 two quarters.
Once again, all this activity in the first quarter was extremely close to our planned activity level, and production continued to come in strong. Remember also that during our budgeting process, oil prices were at or below $50 per barrel. Recent prices remain well above these levels, but we have no plans to accelerate activity. Note that on page seven in our presentation that at $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, tight differentials, opportunistic hedging, and overall efficiency of our operations. We continue to enjoy strong liquidity levels with a borrowing base of $1.6 billion and $493 million drawn on our credit facility as of March 31st, 2019.
Oasis has a net debt to first quarter 2019 annualized EBITDA multiple of 2.4x, with adjusted EBITDA attributable to Oasis 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, 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-$57 million in 2019 on building out additional infrastructure. Total gross midstream capital expenditures are expected to be $195 million-$219 million in 2019, with about $11 million-$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, it 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. 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 two-thirds of our forecasted oil volumes, with one-third of those volumes swapped and two-thirds in collars. Our 2019 WTI collars have an average ceiling of about $70 and floor of approximately $55.
This strategy protects our capital program in lower price environments 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've lowered our LOE guidance to be in the $7-$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 peer-leading differentials through various market fluctuations. In the Delaware, as expected, crude differentials have narrowed considerably versus last year. 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-$3.50 range over the course of the year. 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-$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.
We will now begin the question-and-answer session. To ask a question, you may press star one on your touch-tone phone. If you are using a speakerphone, please pick up your handset before pressing the keys. If at any time your question has been addressed and you would like to withdraw your question, please press star two. At this time, we'll pause momentarily to assemble the roster. The first question comes from Derrick Whitfield of Stifel. Please go ahead.
Thanks. Good morning all.
Morning.
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? More specifically, were there any base production initiatives underway in Q1?
Yeah. When you look at the well count, we're at 15 wells total. We brought in Production was pretty strong coming into the year, that combined with, really had good performance. I think Tommy talked about in his comments, in spite of cold weather where we'd normally expect a ton of downtime, we had really good uptime and performance. Particularly what it points to is the infrastructure system we talk a lot about, being able to move our barrels primarily on pipe, so not having much trucking. When you get into bad winter weather, we're able to continue to move our barrels. We had a bit of downtime when it was 30, 40 below, generally really good uptime throughout that weather period.
I'll add, the guys have done a great job at managing downtime and through tracking the wells remotely and then anticipating failures and just keeping the wells producing. They've just done a great job.
Yep.
Very helpful. As my follow-up, referencing page eight, the North Alger South Cottonwood well was quite impressive. Do you guys expect a meaningful change in geology between that well and the number six on your map as you move north into South Cottonwood?
Yeah. Generally as you look at that side of the basin, as you move north, you get shallower, you lose a bit of pressure, it's a gradual change as you go north. The saturations change a bit as you go north as well. You tend to get a little higher water cuts. On the extreme north end of Cottonwood, it's more like a 60% water cut, whereas that area where the North Alger Cottonwood well is, it's probably more like a 40% water cut, 30, 40% water cut. You're gonna see some drop off, it's gradational. We expect the wells are still gonna be good as you go north.
We're actually drilling some wells a bit further north from what we've done, or what we're showing here right now, and we'll bring on those later this year, so we talk more about it then.
It's very helpful. Thanks for your time.
Thanks.
The next question comes from Oliver Huang of Tudor, Pickering, Holt. Please go ahead.
Good morning. Thanks for taking my questions.
Morning.
For the eight-well spacing test in the Bighorn spacing unit, was wondering if you all might be able to provide some incremental color as to the planned completion design spacing concept you all are planning to test there?
Sure. It's an eight-well test, and it is going to be a combination of Bone Springs three and Wolfcamp A. It'll actually be four wells in the Bone Springs three, then four in the Wolfcamp A. Let me talk a little bit more about spacing. When you look in the Wolfcamp A, there are two parent wells already existing. Spacing will effectively be 880 between the wells, or it would be six wells within a Wolfcamp A bench, and this is primarily focused in this well in the lower Wolfcamp A. Then the four wells in the Bone Springs three, which would be more like a 1,300-foot spacing.
That is similar to what we talked about as we did the acquisition, and we are testing spacing between those lower Wolfcamp A wells, and also testing what the interference or the interplay looks like between the Wolfcamp A and the Bone Springs three. This is our first, I think if you guys know, our first well really drilling in density, and as we will take our learnings from this and apply it into the next one we do going forward. As far as stimulation, it is going to be fairly similar to what we have been doing so far. We continue to optimize around number of stages, clusters, all those things. The fluid loading is the same. Sand has been optimized down a little bit from our first completions, but still robust.
Now that we have done about 10 wells, we have been able to optimize the design, and we think it will work well in the spacing pattern.
Okay, perfect. That's really helpful. 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, does anything change in terms of how you all are thinking about capital allocations for the corporate portfolio going forward?
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 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 their balance sheets separately. You're keeping a very strong balance sheet to the E&P side. You're diversifying your asset base into what we think is also a very premier area in the Delaware, and we think having an anchor tenant in Oasis is a good thing from a midstream perspective. They can pursue third-party opportunities, which we think there are some, both on the water and on the crude side. We really think it's a win-win from both perspectives.
It's exactly what we've been talking about 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. Following that plan exactly.
Okay, perfect. Thank you very much.
Thanks.
The next question comes from Ron Mills of Johnson Rice. Please go ahead.
Morning, guys.
Hey, Ron.
One quick follow-up on the Bighorn spacing test, or I guess an extension of that. You're testing the Bone Springs and the Wolfcamp A there. When you look ahead to next year, at some point, when do you think you get to maybe even testing more complete of a cube development in terms of maybe adding the Wolfcamp B and the Wolfcamp C under a particular section?
Yeah, Ron, as we talked about, we're testing just independent wells in the B and the C. 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. We'll have some tests around that. Certainly for part of the acreage, we think that there's a barrier between the A and the B intervals, and we're going to try to confirm that across the whole acres position. It may turn out that in some of this, it's compartmentalized and you do the A up through the Bone Springs in one package, and the B and the C would be in another package that would come up later on. Still early time.
really want to understand 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 cube. You're right. That's where we're headed, is to that cube development concept.
Okay, thanks. Moving on to mine. The 6-well Wolfcamp A, I guess the three-well Wolfcamp A spacing test that you have coming up, what kind of horizontal well spacing are you testing, and vertical well spacing? Just a little bit more information about what that is testing versus what either yourself or offset operators have already started to test in that zone.
You bet. That's the three-well Wolfcamp A spacing test, and it's testing the upper and the lower. We've got one well in the upper and then two in the lower, and the distance between each of the wells is 440 feet. If you look at just the two wells in the lower, they're 880 feet apart, and then the distance between those lower and those uppers on a horizontal basis is 440 each. With that, think we'll get a good test of that inner well spacing and then how the interplay is between the upper and the lower.
Okay. Lastly, just bigger picture. You have a couple rigs in the Williston, is with the plan, then you have two in the Delaware. If you think forward 12-24 months, how do you think capital allocation and activity will look between your two basins and relative growth contribution? That's it. Thank you.
You bet. Right now, we've got this two and two, and it balances pretty well because with the Williston, we're able to generate excess cash flow, as we talked about before, and 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 everything is like it is right now, we're probably going to have the growth in the program, at least in the next 1-2 years, likely to be more than the growth in the program in the Williston. Keep in mind, that's getting it to doing the same thing in the Permian that we're doing in the Williston, which is full field development and going in and drilling out spacing units.
Keep in mind, the cycle times in the Permian are about twice or even a little bit more. You're doing wells in the Williston in 12-14 days, and then, as we talked about, we're in the 25- to 30-day range in the Permian. You just need more resources to get the same work done. A two-rig program in Williston, you're getting a lot more done than if we get to a three- or four-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've been able to do that through this period of lower oil prices. We demonstrated it when we got pipe short in the Permian.
We maintained a slower pace, and we want the ability to allocate that capital back and forth between the basins, depending on the environment that we're in, and we've got a program set up to do that.
The next question comes from David Deckelbaum of Cowen. Please go ahead.
Morning, Tommy, Michael, Taylor. Thanks everyone for taking my questions.
Yeah, good morning.
Just curious, as you evaluated the acreage dedication and formed 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 a third party in that direction?
We're out in an RFP process for the gas side. We think there are a 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 wanted to be prudent for OMP on where they spend their capital. Of the three different oil, gas, and water, the three different kinds of things that you're taking off out of the well, we thought that crude in the water side had more opportunity.
Appreciate that. I guess as we think about this build-out now in the Delaware, should that be more or less the only capital that we see on the midstream line in 2020?
Yeah. Are you talking about from the parent side or from-
Just on a fully consolidated level.
Yeah. Obviously, from an OMP perspective, they're going to be working on third-party opportunities, which are always very strong if you think of build multiples based on just building off of the asset. There's certainly opportunities like that that may come up. Those are super high capital efficiency type opportunities. There's obviously work in the Delaware that we've laid out. There's 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.
Got it. If I could just ask one more. I know in the past, Taylor, you kind of alluded to this in some of the prior questions, thinking about growing oil into next year in this $50 environment at either free cash neutral or free cash generative, are we to assume that that happens with this current rig count exiting 2019? I guess, how do we think about driving that growth? 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 into 2020? Just trying to understand how you see the mechanics there of sort of delivering that growth without rig additions.
Yeah. You touched on a couple of the things. First, when you look at the projection, as we talked about, it's really flat at 86-91 for the year. We came in at the top end on first quarter, the oil cuts dropping, that implies slight decline in oil production. As you look at it going forward into 2020, the base declines as we slow down, moderate. With that moderated base decline, you have less to battle. On top of that. You got cycle times and inefficiencies.
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 efficiencies, getting costs down, and cycle times down as well. We think all that bodes well for us to get back into growth.
As you progress into that pad development, is that a call on having more rigs and more crews in the Delaware? How do you compress that cycle times going from where you are now into next year?
Yeah. It's probably similar in terms of rig count, but it's just bringing cycle times down. As we talked about, we moved 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. That's non-pad operations. You get into pad operations and get the benefits of batch drilling and then optimizing our completion techniques as well, all that we think will bode well to improve. Same amount of equipment, you're going to get more work done.
Got it. Well, good luck, guys. Thanks for the answers.
Thanks.
You bet, thanks.
The next question comes from Michael Hall with Heikkinen. Please go ahead.
Excuse me. Good morning, thanks for the time. I was wondering if maybe you could provide where you see the balance sheet at the end of this year and the end of next year on the current strip. In the context of that, you've hedged some of 2020 strips well north of $50 at this point. Is there any evolution in your thinking about the potential to add activity in 2020 as you de-risk the downside, as you bring on more and more hedges?
Michael, I think the way we're thinking about it is, there's a commitment from us to continue to generate a significant amount of cash flow, we have to continue to think about, okay, what else are we going to do? We've got a great asset base. I think you want to get to, Taylor mentioned it, this kind of efficiency in the Delaware similar to what we have in the Williston, try to figure out exactly where that all plays out. Like you mentioned, we were able to do some things even this year in a $50 world, given where those 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 that $50 case. That's fantastic.
As we think about next year, we'll continue to think about that. Like you said, we layered in some hedges in 2020 at certainly higher than $50. We'll continue to look to, on an incremental basis, continue to add to that each month. As we start getting into a little bit more comfort into next year's plan, we'll come out with where we come out. Once again, it's going to be what we've said in the past, I think where you've seen us change a little bit is, we were spending to grow within cash flow in the past, now we're spending we're going to generate significant amount of free cash flow. We're certainly going to try to do that generate some growth over time as well.
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. Then as that program moderates from off of high growth rates over the last couple of years, your decline rate comes down, you'll be able to generate more growth from that standpoint as well.
Yeah, Michael, I'd also add that 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, then you've got, okay, what oil price environment am I in? 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, 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. Same thing with frac crews, because that's wildly inefficient. Anything that we can do to maintain consistency and efficiency, I think drives.
We always have to be mindful of oil price and cash that we have to deploy or allocate, we're really going to focus on, especially as you move to full field development in the Delaware is, how can we be the most efficient that we can be and manage our cost?
Okay. That's helpful color. I appreciate it. I guess on that, do you have a view on the balance sheet at year-end and year-end 2020 in terms of net that EBITDA on the strip?
Obviously, you're coming down at the WTI strip, and it depends on the day, but call it under two and a half times as you move out in time.
The other thing I wanted to, I guess, just get into a little bit was on the efficiencies and the cycle time improvements that you all have been driving in the Delaware, just to understand how we should think about that playing forward. That level you highlighted in the deck, are those sorts of cycle times and well costs, I guess, durable today and something we should play forward? How should we think about that over the course of 2019?
That's really what we're doing currently, and as we look at the plan this year, it's what we've baked. Now we will continue to be focused on and hope to drive that down further. That really provides an upside for us in terms of both the cycle times and the well costs. Keep in mind, the well cost, it's a benefit of less days, but it's also really getting our completion designs optimized for these wells. Like we talked about, getting into pad operations is really going to be a big benefit.
All right. Makes sense. Thanks, guys.
The next question comes from Noel Parks of Coker & Palmer. Please go ahead.
Good morning.
Hey, Noel.
Just listening to you talk about the progress you've made with Painted Woods and Alger, and their returns now being competitive with the core. In my perspective, the progress there has been so gradual and incremental that you've come a long way in those areas. I wonder if you could just review for me what the components of the improvement were, just because for a long time, we thought of those as being very much the lower productivity asset.
Yeah. It's like what we did in the core, in that our original stimulations were the older hybrid jobs. They're classic cross-linked gel frack jobs that were smaller before 2014 and really before. They're 4 million pounds, and then also the number of stages in the older jobs were less. You had more in the 28 to 36 stages, and then cluster spacing was different as well. 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 frack across the whole lateral, and then higher intensity jobs. It went from the old cross-linked jobs that had been done out of what was the old core to slickwater jobs.
These new wells we've tested generally around 1,000 pounds to up to 2,000 pounds per foot of proppant with slickwater, so much bigger volumes of water. 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. You combine these bigger jobs, high-capacity lift, a lot of work on getting, like I said, better distribution of that frack across the lateral, and you're just seeing good results. Super encouraging what we're seeing in both of these areas. I'm sure you guys have been tuned in to some of the other operators in the basin. They're reporting similar things really across the position outside of the core. You see it on this map. We talk about the number of these jobs in each of these areas.
In Montana alone, you've got 20 wells that are more modern completion techniques. That's really bumping up the results there as well, and we'll continue to push out and do more pilots as we go.
Great, thanks. I had just a couple 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?
Correct.
Okay. Gotcha.
Just nomenclature, we called it the second before. Now we're going with this Third Bone Spring Shale.
Okay, great. Just one other thing. When you guys were reviewing the guidance and you talked about the 2019 exit rate, I actually missed the number. I just wanted to check. Is that unchanged from last quarter, or the number you gave last quarter?
Correct. It's the same as last quarter.
Great. Thanks a lot.
All right, Noel. Thanks.
Thanks.
The next question comes from Gale Nicholson of Stephens. Please go ahead.
Good morning, everybody. Just looking at LOE, low end of the guidance the first quarter. You lowered it for the top end of the guide range for the remainder of the year. Is that all just incremental volume driven or is there something else going on from an initiative standpoint that you are trending towards that low end of that guide range in 1Q?
Volumes were good in the first quarter, along with that, like we talked about, less downtime on wells, less workover costs. Historically, the winter has been a higher LOE period, we've got some of that that impacted us, we just did a really good job of keeping our production online and keeping overall costs down. One of the things that tremendous amount of work has been done on, hats off to the team, is our failure rate in our artificial lift. 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.
Just a housekeeping question. When we look at the oil price realization guide as well as the marketing transport and gathering guide, what % of your volumes are on DAPL based upon that guide?
On the marketing side, you can think about % of volumes on DAPL or other long-haul pipes like that being somewhere in the 25% range.
For comparison, what were they in 1Q?
About in the 25% range. It's not changing.
Okay, great. Thank you.
In previous years, it was a little bit lower, but it came up in the first quarter, and it should be that throughout the rest of the year.
Thanks.
The next question comes from Michael Glick of JPMorgan. Please go ahead.
Hey, just one bigger picture question for me. We don't think Oasis's stock price reflects much value for the midstream business, although the math is pretty simple, the consolidation of OMP could be obscuring the value and free cash flow power of the E&P business. Could you all talk about how you're thinking long term about the relationship between OMP and Oasis and what you'd consider strategically to unlock the value at Oasis?
Yeah, we've derived tremendous benefit out of having control of infrastructure. 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?" We did that. I think that being able to move oil and water in what was a historically cold, I think maybe second coldest in history in February, and to be able to keep things moving, 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, even at this stage in the Williston, you can see how important that is. 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, we'll continue to monitor that and see how it works. At some point in the future, down the road, if it's not as strategic, we'll take a look at it. At the end of the day, it's cost structure, it's reliability, and being able to move our products, it's the same in both basins.
Got it. Thank you.
You bet.
This concludes our question and answer session. I would like to turn the conference back over to Tommy Nusz for closing remarks.
Yeah. 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.
The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.