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Oasis Petroleum Inc (OAS)
Q1 2019 Earnings Call
May 9, 2019, 8:30 p.m. ET
Contents:
- Prepared Remarks
- Questions and Answers
- Call Participants
Prepared Remarks:
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. (Operator Instructions) After today's presentation, there will be an opportunity to ask questions. (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 H. Lou -- Chief Financial Officer and Executive Vice President
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 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 -- Chief Executive Officer
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 three 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 eight 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 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 priced windows to roll in additional 2019 and 2020 hedges.
The team continues to do a great job executing the -- 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 even -- 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 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 two core assets and two of the lowest cost oil basins in the United States, 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 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 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 this sector and represents a uniquely attractive investment opportunity.
With that, I'll turn the call over to Taylor.
Taylor L. Reid -- Director, President, and Chief Operating Officer
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 expect 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 we'll 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 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 basin is secure as we have no drilling obligations on this acreage.
In the Delaware, we're 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'm pleased to report, we've made significant progress in reducing our drilling times and our well costs. Our most recent wells with two 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 remain 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 expectation. 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, C and Third Bone Springs.
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. 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 H. Lou -- Chief Financial Officer and Executive Vice President
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 we'll 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 continue to come in strong. Remember also that during our budgeting process oil prices were at or below $50 per barrel and 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, type 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 31, 2019. Oasis has a net debt to first quarter 2019 annualized EBITDA multiple of 2.4 times, 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 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 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've 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.
Questions and Answers:
Operator
We will now begin the question-and-answer session. (Operator Instructions) The first question comes from Derrick Whitfield of Stifel. Please go ahead.
Derrick Whitfield -- Stifel Nicolaus -- Analyst
Thanks and good morning, all.
Thomas B. Nusz -- Chief Executive Officer
Good morning.
Derrick Whitfield -- Stifel Nicolaus -- 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 L. Reid -- Director, President, and Chief Operating Officer
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 where we would normally expect a ton of downtime, we had really good uptime in 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're getting bad winter weather, 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 B. Nusz -- Chief Executive Officer
And I'll add, the guys have done a great job of managing downtime and kind of -- I mean, through tracking wells -- tracking the wells remotely and then anticipating failures and just keeping the wells producing. They've just done a great job.
Taylor L. Reid -- Director, President, and Chief Operating Officer
Yes.
Derrick Whitfield -- Stifel Nicolaus -- Analyst
Very helpful. And 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?
Taylor L. Reid -- Director, President, and Chief Operating Officer
Yes. So generally, as you look at that side of the basin, as you move north 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 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 of Cottonwood it's more like a 60% water cut, where it's that area where the North Alger, Cottonwood well is.
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 gradational. So 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 we'll bring on those later this year. So we talk more about it then.
Derrick Whitfield -- Stifel Nicolaus -- Analyst
It's very helpful. Thanks for your time.
Thomas B. Nusz -- Chief Executive Officer
Thanks.
Operator
The next question comes from Oliver Huang of Tudor, Pickering, Holt. Please go ahead.
Oliver Huang -- Tudor, Pickering, Holt & Co. -- Analyst
Good morning and thanks for taking my questions.
Thomas B. Nusz -- Chief Executive Officer
Good morning.
Oliver Huang -- Tudor, Pickering, Holt & Co. -- Analyst
For the eight-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 design, spacing concept you all are planning to test there?
Thomas B. Nusz -- Chief Executive Officer
Sure. So it's an eight-well test. And it's going to be a combination of Bone Springs 3 and Wolfcamp A. And so, it will actually be four wells in the Bone Springs 3 and then four 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 two parent wells already existing. So spacing will effectively be 880 between the wells and -- or it'd be like six wells within a Wolfcamp A bench.
And this is primarily focused in this well in the lower Wolfcamp A and then the four wells in the Bone Springs 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 what the interference or the interplay looks like between the Wolfcamp A and the Bone Springs 3. So this is our first, I think if you guys know our first well really drill in density. And we'll take our learnings from this, and then, apply it in to the next one 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 a number of stages, clusters, all those things. The fluid loadings is 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 in this spacing pattern.
Oliver Huang -- Tudor, Pickering, Holt & Co. -- 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 H. Lou -- Chief Financial Officer and Executive Vice President
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 kind of their balance sheet separately.
So you're keeping a very strong balance sheet at the OMP 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. 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.
Oliver Huang -- Tudor, Pickering, Holt & Co. -- Analyst
Okay, perfect. Thank you very much.
Thomas B. Nusz -- Chief Executive Officer
Thanks.
Operator
The next question comes from Ron Mills of Johnson Rice. Please go ahead.
Ronald Mills -- Johnson Rice & Company -- Analyst
Good morning, guys.
Thomas B. Nusz -- Chief Executive Officer
Hey, Ron.
Ronald Mills -- Johnson Rice & Company -- Analyst
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 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 Wolfcamp C under a particular section?
Taylor L. Reid -- Director, President, and Chief Operating Officer
Yes. Ron, we're -- as we talked about, we're testing these 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 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 the Bone Springs and one package, and the B and the C would be in 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 -- Johnson Rice & Company -- Analyst
Okay. Thanks. And then moving on mining, the six-well Wolfcamp A, I guess the three-well Wolfcamp A spacing test that you have coming up, is that just -- is that design, what kind of 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 L. Reid -- Director, President, and Chief Operating Officer
You bet. So that's -- three-well Wolfcamp A spacing test and it's test in the upper and the lower. And so, you've got onewell in the upper and then two in the lower, and the distance between each of the wells is 440 feet. If you look at that, just the two 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 -- Johnson Rice & Company -- Analyst
Okay. And then lastly, just bigger picture. When you -- you have a couple of rigs in the Williston is with the plan and then you have two in the Delaware. If you think forward 12 to 24 months, how do you think capital allocation and activity will look between your two basins and relative growth contribution? And that's it. Thank you.
Taylor L. Reid -- Director, President, and Chief Operating Officer
You bet. You know what, 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, 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 one to two 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 unit, and keep in mind of the cycle times in the Permian are about twice. So you got or even a little bit more, you're doing wells in the Williston in 12 to 14 days. And then, as we talked 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 a two rig program in Williston you're getting a lot more done, and 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 kind of a slower pace, and we want to believe that allocate that capital back and forth between the basin is dependent on the environment that we're in, and we've got a program set up to do that.
Operator
The next question comes from David Deckelbaum of Cowen. Please go ahead.
David Deckelbaum -- Cowen & Co. -- Analyst
Good morning, Tommy, Michael and Taylor. Thanks everyone for taking my questions.
Thomas B. Nusz -- Chief Executive Officer
Yes. Good morning.
David Deckelbaum -- Cowen & Co. -- Analyst
Just curious as you've 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 H. Lou -- Chief Financial Officer and Executive Vice President
Yes. So we're out an 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 dedications 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 three kind of different oil, gas and water, the three different kind of things that you're taking off out of the well, we thought that crude in the water side had more opportunity.
David Deckelbaum -- Cowen & Co. -- Analyst
I 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?
Michael H. Lou -- Chief Financial Officer and Executive Vice President
Yes. There is going to be -- are you talking about from the parent side or from...
David Deckelbaum -- Cowen & Co. -- Analyst
Yes. Just like on this fully consolidated level?
Michael H. Lou -- Chief Financial Officer and Executive Vice President
Yes. Obviously, there's -- from an OMP perspective, they're going to be working on third party kind of opportunities, which are always very strong if you think kind of build multiples based on kind of just building off of the assets. And so, there are certainly opportunities like that that may come up, but those are super 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 -- Cowen & Co. -- 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 in sort of this $50 environment, and either free cash neutral (ph) or, 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 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 the rig additions?
Taylor L. Reid -- Director, President, and Chief Operating Officer
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 the first quarter and then the oil cut is 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 and 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 costs down and the cycle times down as well. We think all that bodes well for us to get back into growth.
David Deckelbaum -- Cowen & Co. -- Analyst
As you progress into the pad development, is that -- 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 L. Reid -- Director, President, and Chief Operating Officer
Yes. So it's probably similar to more 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 and then optimizing our completion techniques as well, all that we think will bode well to improve. So I think same amount of equipment you're going to get more work.
David Deckelbaum -- Cowen & Co. -- Analyst
Got it. Good luck guys. Thanks for the answers.
Taylor L. Reid -- Director, President, and Chief Operating Officer
Thanks.
Thomas B. Nusz -- Chief Executive Officer
Good luck. Thanks.
Operator
The next question comes from Michael Hall with Heikkinen. Please go ahead.
Michael Hall -- Heikkinen Energy Advisors -- Analyst
Excuse me. Good morning. Thanks for the time. 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 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 of that activity in 2020, as you kind of derisk downside as you bring on more and more hedges?
Michael H. Lou -- Chief Financial Officer and Executive Vice President
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've 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 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 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 layered in some hedges in 2020 at certainly higher than $50. And we'll continue to look to kind of on an 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 L. Reid -- Director, President, and Chief Operating Officer
Yes. 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. And then you've got -- okay, what oil price 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 the 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 -- Heikkinen Energy Advisors -- Analyst
Okay. That's helpful color. I 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 B. Nusz -- Chief Executive Officer
Yes. I mean, obviously, you're coming down at the strip and it depends on the day. But call it under 2.5 times, as you move out in time.
Michael Hall -- Heikkinen Energy Advisors -- Analyst
Okay. And then the other thing, I wanted to -- I guess just get into a little bit was on the efficiencies that are -- on 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 L. Reid -- Director, President, and Chief Operating Officer
Yes. So that's really what we're doing currently and that's as we look at the plan this year, it'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 and the well cost. 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 a -- going to be a big benefit.
Michael Hall -- Heikkinen Energy Advisors -- Analyst
All right, makes sense. Thanks, guys.
Operator
The next question comes from Noel Parks of Coker and Palmer. Please go ahead.
Noel Parks -- Coker Palmer Institutional -- Analyst
Good morning.
Thomas B. Nusz -- Chief Executive Officer
Hey, Noel
Noel Parks -- Coker Palmer Institutional -- Analyst
I just listening to you, 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 sort of so gradual incremental that it's pretty, -- you have come a long way in those areas. And I wonder if you could just kind of 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 sort of the lower productivity assets?
Thomas B. Nusz -- Chief Executive Officer
Yes, so, it's kind of like what we did in the core and that our original stimulations were the older hybrid jobs. And so they're the classic and crosslinked 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 in the older jobs were less, so you had more in the 28 to 36 stages. And then cluster spacing was different as well.
And 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 -- or out of what was the old core to slick water jobs.
And these new wells we tested, generally, around 1,000 pounds to up to 2,000 pounds per foot of proppant with slickwater, so much bigger volumes of water. And then you combine that with high capacity artificial lift. We've done a lot of work with the 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 in 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 -- Coker Palmer Institutional -- Analyst
Great. Thanks. And I have 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. Well, you're not calling the third Bone Springs shale, that's what you were calling the second before, is that right?
Thomas B. Nusz -- Chief Executive Officer
Correct.
Noel Parks -- Coker Palmer Institutional -- Analyst
Okay, got it.
Thomas B. Nusz -- Chief Executive Officer
This time we're quite, but we called the second before. Now, we're -- and we're going through the third Bone Springs shale.
Noel Parks -- Coker Palmer Institutional -- Analyst
Okay, great. And just one other thing, when you guys were reviewing the guidance, when you talked about the 2019 exit rate, I actually missed the number. I just wanted to check, is that unchanged from last quarter the number you gave last quarter?
Thomas B. Nusz -- Chief Executive Officer
Correct, it's the same as last quarter.
Noel Parks -- Coker Palmer Institutional -- Analyst
Great. Thanks a lot.
Thomas B. Nusz -- Chief Executive Officer
Bye Noel Thanks.
Operator
The next question comes from Gail Nicholson of Stephens. Please go ahead.
Gail Nicholson -- Stephens Inc. -- Analyst
Good morning, everybody. Just looking at all the low ends of -- low end of guidance in the first quarter you lowered it from the top end of the guide range for 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 toward that low-end of that guide range in 1Q?
Thomas B. Nusz -- Chief Executive Officer
Yes. So it's -- volumes were good in the first quarter, but along with that what we talked about, less downtime on wells, less work-over cost. Historically, the winter has been the higher LOE period. And we got some of that that impacted us. But we just did a really good job of keeping our production on line and keeping overall cost down. One of the things that, tremendous amount of work has been done on and hats off to the team is our failure rate on our -- in our official lift andthe 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 -- Stephens Inc. -- Analyst
And then just a housekeeping question, when we look at the oil price utilization guide as well as the marketing, transport and gathering guide, what percent of your volume is on DAPL based upon that guide?
Michael H. Lou -- Chief Financial Officer and Executive Vice President
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 -- Stephens Inc. -- Analyst
And then, for comparison what were they in 1Q?
Michael H. Lou -- Chief Financial Officer and Executive Vice President
About in the 25% range. It's not changing.
Gail Nicholson -- Stephens Inc. -- Analyst
Okay, great. Thank you.
Michael H. Lou -- Chief Financial Officer and Executive Vice President
Like 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.
Gail Nicholson -- Stephens Inc. -- Analyst
Thanks.
Michael H. Lou -- Chief Financial Officer and Executive Vice President
Thank you.
Operator
The next question comes from Michael Glick of J.P. Morgan. Please go ahead.
Michael Glick -- JP Morgan -- Analyst
Hey, just one bigger picture question for 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 OMP could be securing the value and free cash flow power of 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 B. Nusz -- Chief Executive Officer
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 a challenged, and how do we get out and front of that. We did that.
And so, I think that being able to move oil and water in what it was a historically cold, I think maybe the second coldest 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 as 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 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 it's cost structure, it's reliability and being able to move our products. And that goes -- and it's the same in both basins.
Michael Glick -- JP Morgan -- Analyst
Got it. Thank you.
Thomas B. Nusz -- Chief Executive Officer
You bet.
Operator
This concludes our question-and-answer session. I would like to turn the conference back over to Tommy Nusz for closing remarks.
Thomas B. Nusz -- Chief Executive Officer
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.
Duration: 77 minutes
Call participants:
Michael H. Lou -- Chief Financial Officer and Executive Vice President
Thomas B. Nusz -- Chief Executive Officer
Taylor L. Reid -- Director, President, and Chief Operating Officer
Derrick Whitfield -- Stifel Nicolaus -- Analyst
Oliver Huang -- Tudor, Pickering, Holt & Co. -- Analyst
Ronald Mills -- Johnson Rice & Company -- Analyst
David Deckelbaum -- Cowen & Co. -- Analyst
Michael Hall -- Heikkinen Energy Advisors -- Analyst
Noel Parks -- Coker Palmer Institutional -- Analyst
Gail Nicholson -- Stephens Inc. -- Analyst
Michael Glick -- JP Morgan -- Analyst
