Chord Energy Corp

NASDAQ:CHRD

Earnings Call Transcript 2018-Q4

[Operator]

Good morning. My name is Drew, and I will be your conference operator today. At this time, I would like to welcome everyone to the fourth quarter 2018 earnings release and operations update for Oasis Petroleum. [Operator Instructions] Please note, this event is being recorded.

I will now turn the call over to Michael Lou, Oasis Petroleum's CFO, to begin the conference. Thank you. You may begin your conference.

[Michael Lou, executive]

Thank you, Drew. Good morning, everyone. Today we are reporting our fourth quarter 2018 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 reference to non-GAAP measures, and reconciliations to 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 thank you for joining our call. The Oasis team continues to do a great job executing 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 volatile oil prices and associated headwinds. Our management of E&P spending was in cash flow over the last 4 years has clearly demonstrated that Oasis is built and managed to withstand and even prosper in low price environments, given our deep inventory, which now spans 2 low-cost basins, our experienced workforce, our financial management and our ability to manage business risks. We designed this 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 down to WTI prices of $45 per barrel.

Taylor will provide more color in a moment, but I want to highlight a few key points regarding 2018 for you this morning as we wrap up the year. First, our Williston Basin asset performance remained strong as we completed 28 wells in the quarter, and were able to capture more gas in Wild Basin. In aggregate, our fourth quarter volumes averaged 88,300 Boes per day in line with midpoint guidance. Second, OMP successfully started its 200 million a day gas plant in early December, bringing our total processing capacity to about 320 million per day and making OMP the second largest natural gas processor in the basin. Congratulations to the Oasis team for a huge win here. They did a great job using their sub-surface knowledge to anticipate increasing gas production and tightness in gas processing capacity. This allowed Oasis to stay ahead of the curve in capturing its own production and also led to multiple third-party gas contracts to allow others to do the same. Third, in the Delaware, our delineation program is going well as we continued to integrate this world-class asset and prepare for full field development. We had a few wins this year in the Delaware basin. We successfully executed a major development program, exceeded our financial expectations, expanded our footprint and hit our target exit rate of 6,000 Boes per day.

The team has also done an exceptional job with our service partners so that we can get our work done as well as managing our takeaway capacity while bridging 2 big takeaway projects that will start hitting in the second half of the year. Fourth, in what proved to be a difficult day in [ the ] market, our team closed approximately $360 million of noncore asset sales, which have helped high-grade our portfolio and strengthen our balance sheet.

Fifth, in our operating efficiency -- our operating efficiency continues to stand out among our peers. Page 15 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.

As we turn to 2019, Oasis is in a formidable position to generate significant free cash flow driven by Top-Tier capital-efficient inventory. With our commitment to generate free cash flow at a $50 oil price, we lowered our 2019 E&P capital plan by 40% compared to 2018. We expect capital efficiency to improve in 2019 driven by improved operating efficiency and lower service costs. Additionally, we've entered into a new arrangement with OMP that significantly reduces Oasis' portion of Williston Midstream CapEx in 2019. We have a proven track record of capital discipline. And while prioritizing cash flow generation and returns over volume growth, we have positioned the company to succeed through volatile market conditions.

Going forward, development of the Williston will continue to be a significant driver of activity and provides a source of free cash flow to fund Delaware activity. Even with oil price trading well above $50 today, we intend to execute on our planned activity for 2019, and we'll use excess free cash flow to reduce leverage.

Our Williston development activity will be concentrated on Wild Basin with additional completions primarily across Indian Hills, Alger and Red Bank. Total Williston spending is expected to account for about 75% of our drilling and completion budget, driving Williston production to increase modestly year-over-year while generating free cash flow that more than funds a slight Delaware outspend. In the Delaware, our strategy is centered on delineating our low-cost, highly economic position, understanding the sub-surface and holding acreage.

In 2019, we no longer expect to pick up a third development rig, which was originally slated for the second half of the year. This decision reflects the current commodity outlook and also drilling efficiencies that allow us to hold our acreage with fewer rigs than originally anticipated. I'm confident that the Delaware asset will be a major value driver for the company for years to come.

With 2 core assets and 2 of the lowest-cost oil basins in the United States, we have a strong inventory depth allowing us to attract -- earn attractive returns at low prices. Additionally, we have differential midstream and services businesses that have been a tremendous competitive advantage. 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.

[Taylor Reid, executive]

Thanks, Tommy. In 2019, we expect to spend between $540 million and $560 million of E&P in other capital across both basins, with about 85% of that capital for drilling and completions. The program should deliver production of about 86,000 Boes to 91,000 Boes per day for the full year as well as in the fourth quarter of 2019, essentially in line with the fourth quarter of 2018.

Our oil cut is expected to average approximately 72% in 2019, which implies a cut of about 71% for the fourth quarter. The decline in oil cut versus 2018 reflects a few different factors, including the start-up of our new gas plant, which allows Oasis to capture higher volumes; a program in the Williston that is more focused on Wild Basin, which has a higher GOR than our PDP base, even though the Wild Basin wells are some of the best oil producers in the Williston; and a restrained Delaware program, which has a higher oil cut.

In 2018, Oasis delivered strong production growth from new wells, especially later in the year. These high-rate wells also have fairly high first year declines, which directly impacts our base decline, which we now estimate at about 40% exit to exit. Base declines get shallower in 2020 and beyond. In the Delaware, we'll steadily become a larger part of the development program. As a result, overall oil production in 2020 should flatten out or even slightly grow based on maintaining a program in a $50 world that generates free cash flow.

In the Williston, we are currently running 3 rigs but expect to drop to 2 in the next month or so. We quickly adjusted our plan in the fourth quarter and released 2 rigs so we have effectively adjusted our 2019 plan from 5 rigs to 2 rigs. Likewise, our frac activity has gone from 3 to 2 crews. As a result, we expect to complete about 70 gross operated wells this year. Well productivity and inventory depth remained key strengths in our Williston position. And as a result, our relative well performance is very strong. Slide 12 of our investor deck highlights our 12-month average cumulative oil equivalent production per 1,000 foot of lateral versus our peers. Our continued focus on high intensity completion optimization has paid dividends, as you can see. We're at the top of the pack on our Boe and on the oil basis.

As you can see on Page 10 and 11 of our deck, early delineation results from various stepout areas are also encouraging. We drilled 3 wells in Painted Woods in 2018, which are trending well and validate our view that the area is economic below $45 per barrel. While a moderator program is likely to push back Painted Woods development, Oasis has a huge advantage in having this deep inventory secured with no drilling obligations. Separately, we continue to monitor third-party activity around our South Cottonwood and Montana positions. Based on these results, these areas are also economical at sub $45 pricing and have been moved into our Top-Tier inventory. Economics have certainly improved with advanced completion techniques, and we're evaluating the possibility of drilling select wells in these areas as part of our 2019 and 2020 programs.

In the Delaware, we expect to run 2 rigs throughout the year completing 9 to 11 wells and volumes are expected to increase approximately 50% year-over-year and exit 2019 at 8,000 Boes to 9,000 Boes per day. Our prior estimates anticipated about 2x the capital we have currently budgeted for 2019, which would have resulted in an exit rate of 11,000 Boes per day. We continue to enhance operations and expect productivity to improve as we progress drilling and design efficiency.

Last year, we drilled 3 -- we drilled a 3-well Wolfcamp A spacing test with 2 in the lower and 1 in the upper interval, which we expect to complete shortly.

The remainder of the 2019 program will be primarily focused on the Wolfcamp A with additional drilling across other zones, including a Wolfcamp B, and C as well as the 3rd Bone Springs. We will also conduct another spacing test with an 8-well pad to be drilled in 2019 and completed and brought on production in 2020. As we've said in the past, it is important for us to understand productivity and spacing before beginning full field development operations.

I would now direct you to Slide 5 of our deck as we move on to inventory. In the Williston, we have identified 1,385 gross operator locations with breakeven pricing at or below $45 per barrel, which we think about as Top-Tier locations. At our 2019 drilling pace, this equates to 20 years of low-cost inventory in the Williston alone. This generally represents 8 to 10 wells per DSU across this acreage and has been optimized over the past 5 years that we have been drilling in full field development. In the Delaware, we stand at approximately 600 to 700 gross operator locations, which, like our Top-Tier Bakken, have breakeven pricing below $45 per barrel.

To close, our team has done an outstanding job of executing on our plans this year. Williston development is going well, and we continue to drive efficiency and capital productivity. In the Delaware, the team has done a great job of integrating the asset, delivering solid well results and progressing our efforts to move closer to full field development.

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

[Michael Lou, executive]

Thanks, Taylor. As you've seen in the years past, our low-cost assets and top-notch operational team delivered strong performance. This past year, we high graded our asset base further through a series of divestitures and new bolt-ons in the Delaware. We are in a great position to enhance returns, drive capital efficiency across our deep portfolio and generate significant free cash flow. Since 2015, Oasis has been dedicated to living within E&P cash flow. We created OMP in 2017 to help finance Midstream spending and in 2018 used a portion of divestiture proceeds to expand the D&C program. During the fourth quarter, we sold down Oasis interest in Bobcat and Beartooth DevCos for $250 million, which resulted in Oasis receiving approximately $170 million in cash and $3.95 million in OMP common units. The cash portion of the sale covered Oasis Midstream spending in 2018.

As we turn to 2019, the current plan calls for Oasis to generate approximately $150 million of free cash flow at $50 WTI oil price, which increases to approximately $230 million at $60 per barrel.

Slide 9 of our investor presentation highlights our free cash flow position and bridges the components of our free cash flow. We defined free cash flow as a stand-alone E&P EBITDA plus Oasis ownership of midstream and distributions from OMP minus cash interest, minus total CapEx attributable to Oasis, including Midstream. The Midstream portion of Oasis CapEx is minimized due to a recently approved arrangement between Oasis and OMP, where OMP will fund Oasis portion of growth capital in our Bobcat DevCo. We believe this arrangement is mutually beneficial for both Oasis and OMP as OMP can increase its ownership position at a fair value and Oasis is able to focus its spending on its E&P business. As a result of this strategy, Oasis ownership in Bobcat is expected to decline from 75% to approximately 65% by year-end.

In 2019, Oasis continues to expect to fund some Midstream capital at the Oasis level, primarily consisting of select Delaware midstream projects. As Tommy and Taylor mentioned, OMP is performing well and was able to sign additional third-party contracts in the fourth quarter of 2018. These incremental deals help protect and diversify OMP's revenue stream. And OMP was able to increase its 2019 EBITDA projections despite a reduction in Oasis completion activity. With our second Wild Basin gas plant ramping up over the past several months, we've met our expectation for 60% utilization in early 2019. With additional third-party deals signed, we know expect utilization to ramp up to north of 90% by year-end versus 80% at the last update.

Going forward, Oasis stands to benefit from operational efficiency and flexibility provided by OMP's total processing capacity of 320 million cubic feet a day. We'll talk 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.

On the operational cost front, LOE per Boe ended up averaging $6.44 in 2018 and our exceptional performance allowed us to lower guidance through the year. We're expecting LOE to be in the $7 to $8 per Boe range in 2019 and the increase reflects increased use of ESPs in the Williston and a relatively low production base in the Delaware over which fixed costs can be spread. Williston crude differentials widened somewhat in the fourth quarter, particularly in November and December, but our marketing team did a fantastic job delivering peer leading differentials against the backdrop of historically high refinery maintenance that occurred in Pad 2.

As we head into 2019, Williston oil differentials have returned to levels seen throughout the first year of last -- first half of last year. In the Delaware, crude differentials have been volatile, but several new haul -- long-haul pipelines coming online over the course of 2019 should debottleneck the area for years to come. We currently expect differentials to be in the $1.50 to $3.50 range over the course of the year. Additionally, marketing and transportation and gathering expenses per Boe should be in the $2.50 to $3 per Boe range. I want to briefly address the revisions to our financials that you will see in our press release and detailed in our 10-K. As I mentioned, our marketing team does outstanding work optimizing our price realizations, benefiting our shareholders, working interest partners and royalty owners. For example, given our size and scale in the Williston, our team engages in low-risk paired buy-sell transactions within the basin to reduce gathering and transportation expenses. We have historically shown all of these transactions on a net basis. We will now be showing certain transactions on a gross basis given their characteristics. Most importantly, no restatement of our prior period financial results is required and the revisions we are making to our financial statements, although they do increase both revenues and expenses, result in no change to our prior period financial results such as EBITDA, net income and earnings per share. Liquidity remains strong. Our total borrowing base is $1.6 billion with $1.35 billion committed with only $468 million drawn as of December 31. Oasis had a net debt attributable to Oasis to full year 2018 EBITDA multiple of under 2.7x with adjusted EBITDA attributable to Oasis of $936 million for the year. Fourth quarter EBITDA was adversely impacted by lower oil prices, wider differentials, and the carryover of approximately $24 million of realized hedge losses from September.

Just to update you on our hedging program. We are fairly well hedged for 2019 at around 55% to 60% 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 $72 and floor of approximately $54. This strategy protects our capital program in lower price environments, while also allowing us to capture more upside should prices continue to recover. We've already begun our 2020 program. To sum things up, 2018 was a great year for Oasis as our team executed incredibly well across multiple fronts. Each of these steps continue to improve our size and scale, diversify our asset base, increase our Top-Tier inventory while building upon our financial strength. As we look to 2019, the solid foundation our team has built through focus on returns and capital efficiency allows us to generate significant free cash flow, while maintaining our strong asset base.

With that, I will hand the call back over to Drew, for questions.

[Operator]

[Operator Instructions] The first question comes from Michael Hall of Heikkinen Energy Advisors.

[Michael Hall, analyst]

I was curious if you could provide just a little additional color on kind of the cadence of the completion profile over the course of the year. I'm just trying to think through obviously with the rig count coming down, how that will kind of play into your normal seasonality of completions in the Williston and I'm trying to square that also with the kind of flat 1Q '19 versus 4Q '18, just trying to think through how the momentum from the back half of '18 doesn't carryover a little bit into the first quarter '19?

[Taylor Reid, executive]

Yes, I think you're thinking about it the right way. The cadence is like we normally see in the winter is going to be a little slower in the first quarter. So for Williston, 70 wells, you're going to have -- it's not evenly distributed. Like I said, I don't know, maybe 10, 15 well kind of range, and then you can spread the rest of the wells pretty evenly across the last 3 quarters of the year. Obviously, less completions in the first quarter, but we had a number of wells that we brought online, 28 wells that Tommy talked about and a number that were late in the quarter so some of that's spilled over and it will just help us to keep volumes flat into the first quarter, and then like we talked about we pick up activity again.

[Michael Hall, analyst]

Okay. And as we kind of think through the oil rate trajectory, you pointed to 71% oil mix in the fourth quarter '19, which should be kind of down a little bit, exit to exit. Are you growing out of the year so like is there a low point in the year that comes prior to the fourth quarter? Or are you declining through the course of the year on oil volumes? And when would you think you would flatten that out, if the latter is the case?

[Taylor Reid, executive]

Yes. So when you talked about the cuts and the end of last year, fourth quarter you're more like 76%. And the thing that's going on in Williston, we'll bring -- we brought on the plant in December. So quite a bit more processing capacity here at year-end, but just for really a month and then you get that full treatment for the whole first quarter with that new plant on so a bit of a dip. If you just did the numbers we talked about, it went down pretty symmetrical [indiscernible] you'd go 73%, 72% at the midpoint of the year and then 71% at year-end, which will imply as we talked about there is a bit of a drop off in oil volumes for Williston, but then you get offset with increasing oil volumes in the Delaware.

So exit to exit, all that combined, a bit of a drop in oil, but then as we also talked about as we get into 2020 the decline profile looks different. So you go in 2019, the base decline is about 40% and that as you have less of the new wells, not as much of the production be dominated by new wells, that moderates into 2020. And so that's -- we think that will allow us to keep our oil volumes flat to slightly growing in 2020 relative to the exit in 2019.

[Michael Hall, analyst]

Okay. That's helpful granularity. And then, I guess, last one and just may be bigger picture, stepping back as you guys think about 2020, kind of holistically, I guess, how are you thinking about that in the context of getting back to potentially some growth or is free cash flow really still the emphasis? And what sort of activity do you need to have in the Delaware in 2020 to keep that acreage position whole?

[Taylor Reid, executive]

Yes, from -- as far as the acreage hold, close to the pace that we're drilling this year can do that for us. But what we expect -- you saw from last year to this year, we stepped it up a bit in the Delaware. And then as you look at going into 2020, likely going to be going into more full development 2020 or close to that time. Again, the activity level's probably going to pick up, again, in the Delaware. Overall, with respect to the free cash flow generation, our expectation is to continue to generate free cash flow, certainly, in this $50 environment that we're in, we can continue to do that. And as I said, hold volumes flat. If you can get into a higher price world, we have the opportunity to move activity up a bit. But, again, it's going to be focused on continuing to generate free cash flow.

As Michael talked about that number, it's in the deck. You can look at the slide that shows at each of the higher price cases we generate more free cash flow, and that's on Page 9 of the presentation.

[Operator]

The next question comes from Derrick Whitfield of Stifel.

[Derrick Whitfield, analyst]

I definitely want to applaud you guys on a strong and capital disciplined outlook. With respect to the Williston, could you share with us your thoughts behind the name change from core and extended core to Top-Tier? Is it simply the results on the former extended core approaching a level that's very similar to past core returns?

[Taylor Reid, executive]

Yes, no, that's, you're on the right track. If you -- people that are new, if you look on Page 5 of the deck, you will see that we've really just got what we're calling Top-Tier and then additional upside acreage. And the way we had this classified over the past 3 or 4 years, we had this core and extended core concept. And the break between those 2 cores was $40 breakeven or below extended core was $45, and so a $5 difference between those 2 classifications. Before there was a lot of these higher intensity stimulations outside the core made sense. Now as you look, yes, I actually direct you to Page 10 and 11. The map on Page 10, you can see that, boy, there's a bunch of these enhanced completions really all over the basin and all over these areas that we're now calling Tier 1, and the results of the wells are pretty impressive. If you look on Page 11, you will see for South Cottonwood, Painted Woods, and for Montana how the more recent completions, so their 2016-plus completions and our recent test in Painted Woods compare to all the completions done for all operators in the basin since 2017. And keep in mind, most of that activity is in the core. So it really compares favorably. So we just think that the highly economic position is expanded over a bigger part of the basin and are going to this single Tier concept, which we also think is really more in line with our peers.

[Derrick Whitfield, analyst]

Got it. That makes sense. And just a follow up for you, Taylor. Speaking to peer wells you're referencing on Slide 11, how close are those designs to what you would consider best practice? And could you also speak to the potential timing for your planned enhanced completion test on both Montana and South Cottonwood?

[Taylor Reid, executive]

So when you look at the peer wells, different operators are doing different things, like most of this activity since '15 has been concentrated in the core and for the most part, everybody has gone to high intensity completions, and they've got different variances of those completions, but a lot of that is slickwater. And then the exact sizes of those kind of change. So pretty much everybody has made the shift at this point to high intensity completion, cemented liners, and also doing plug and perf completions. So we think it's pretty representative of what we've been doing. So I think a good comparator. In terms of drilling additional wells in Montana and South Cottonwood, we're evaluating that. And so this year or sometime next year, you'll probably see that happen. This -- it's not unlike what we did in Painted Woods. If you guys remember, we moved Painted Woods into the -- an additional Tier of inventory, moved it up based on third-party results we saw in the area. And then in 2017, we went in and drilled our own wells, and have seen as good or better results than what we saw from competitors. So you can expect a similar approach for both South Cottonwood and Montana.

[Operator]

The next question comes from David Deckelbaum of Cowen.

[David Deckelbaum, analyst]

Michael, congrats on consummating the deal with OMP on the CapEx agreement. I'm curious how you're thinking about that going into 2020 and beyond. Should we think about this as a sort of a perpetual structure that you could turn to until you get done [ to win ] the ownership threshold before you would be, I guess, effectively losing control?

[Michael Lou, executive]

Thanks for that, David. This arrangement is clearly only for this year. However, what we have said in the past from an Oasis standpoint is that, we want to spend free cash flow. We either want that to go back to the balance sheet at the parent level or go into our E&P capital spending program. And that's how we continue to think about it. So midstream capital for the most part we do want to be spent at the MLP level. Whether it's through a drop-down or it's a capital expenditure arrangement like we settled on now, that's kind of how we're thinking about it. So we'll see how this continues to work for both sides. We think it's a win-win for both sides, and will be great. And if that continues, obviously, we can think about that for 2020 and beyond as well.

[David Deckelbaum, analyst]

That's helpful. Appreciate that. And then, just on the '19 plan, and Taylor, you talked about the oil mix and gave some thoughts on to oil growth going into 2020 and it sounds like you would be adding some activity in the Delaware. In your sort of high-level planning now in sort of a $50 world, does that come at the expense of Williston capital going beyond 2019? Or I guess, another way, at what point do you see the Delaware becoming sort of almost an even capital allocation to the Williston?

[Taylor Reid, executive]

Yes. So the -- first question around activity levels and impact on the Williston, yes, if we continue to be at a $50 world, the program is going to be fairly similar. One of the things to keep in mind that is, if we are in a $50 world, you're going to continue to see deflation, and so we think that's helpful and being able to execute on a similar program. We also would expect that will continue to improve our efficiencies and cycle times and bring down cost, especially in the Delaware, and we're early on that asset. We've been operating it now for 1 year, have made good strides. We've got a path to continue to improve on that. And so as we pick up a little more activity in the Delaware, yes, there is going to be some offset in terms of activity if it's the same overall program. But there's also benefit to cost deflation, and then just overall efficiencies in a lower price world, that won't make that as big of impact it might be otherwise don't. It's just directional. I don't have specific numbers at this point, but that's how we would be thinking about it.

[Michael Lou, executive]

And David, something to add to that is Taylor did mention earlier in his prepared remarks about the declines -- the base declines are starting to flatten as well. So over time, you're not going to need as much capital in the Williston to continue to maintain production levels there. It's got a great inventory basis we've already talked about. And so we think we can maintain that with less and less capital. It's going to generate a lot of free cash flow that will originally be reallocated towards Delaware some before it gets to free cash flow itself.

[Taylor Reid, executive]

And then as far as, how long is it going to be before you're spending even capital between the 2 bases, well, that's a number of years out and just early for us to give a view on that at this point.

[Operator]

The next question comes from Ron Mills of Johnson Rice.

[Ronald Mills, analyst]

Taylor, I think for you. In the Permian, especially you talked about some of the tests you're doing, could you just provide a little bit more color on what 2019 looks like in terms of additional delineation of the Wolfcamp B, along with the 3rd Bone Springs? And is this also the year when you potentially start testing the codevelopment of all 3 other zones like you did in the upper and lower A tests?

[Taylor Reid, executive]

Yes, Ron, it's a good point. We are going to do some individual interval tests of the Wolfcamp C, the Wolfcamp B, Bone Springs 3, like you talked about. But then with the 8-well pilots that we talked about, drilling 8 wells in spacing, we will test a number of those different intervals together all in a block to see how they interplay and what's the basin will look like going forward. And that's important for us, as we look to 2020 and beyond, and getting to more of a development program going forward. We really want to understand how all those intervals interact in spacing and with the type of stimulation that we're doing.

[Ronald Mills, analyst]

And do you think in terms of timing, you'll have enough of that data in hand by the end of this year to -- as you look to formulate your 2020 plan? Or is that something that really transitions over the course of 2020 and you potentially move to more of a full codevelopment program?

[Taylor Reid, executive]

Yes, it's going to be early results as we get into 2020. So we might be doing more pad work like that and then getting into really full development later in the year. But we'll continue to evaluate it as we go. It's important from efficient resource recovery standpoint, but also important from cycle time of capital efficiency, just getting into pad operations is going to really help to continue to bring the cost down.

[Ronald Mills, analyst]

Okay, great. And then Michael, for you on the free cash flow side, as -- what are the -- what's the planned use of the free cash flow? My guess is, initially to pay down debt. And I guess, if that's the case, do you kind of have a targeted longer-term leverage ratio you would like to achieve with that free cash flow? And how do you measure that versus the opportunity to do more or similar bolt-ons to what you did in the latter part of last year in the Delaware?

[Michael Lou, executive]

Yes, right now, the way we're thinking about it is, we need to continue to increase our financial strength, and we've always kind of talked about a 2x debt-to-EBITDA level that we're shooting for in a normalized oil price. So if you called $50 or $55 oil price kind of a normalized basis, that's what we're going to shoot for is under that 2x. And so as we think about free cash flow generation, what we tried to show were what that might be in a $50 world, today you're more like $55, so what it might look like in $55 and $60, and in those scenarios, trying to be thoughtful around service cost maybe being a little bit different as well in those different environments. So you'll notice those don't ratchet up perfectly with necessarily with the EBITDA as we're kind of adjusting inflation on CapEx too, but really looking at that as kind of bolstering the balance sheet and paying down debt at this point.

[Operator]

The next question comes from Brad Heffern of RBC Capital Markets.

[Brad Heffern, analyst]

I guess, kind of on the same thing for the 2019 plan. Can you just talk about what led to this being the plan versus maybe a plan that would have kept oil flat or maybe even a free cash flow neutral plan? What are the benefits of this versus the other option?

[Taylor Reid, executive]

Look, we've had a big focus -- I'll start, I think Tommy's got something to add, but we had a big focus on a minimum being free cash flow neutral. And as we continued to work the program, it became apparent that we could really keep our volumes flat and generate free cash flow. And we just thought it was a great use of proceeds. The capital-efficient inventory in the basins really allow us to put a program like this out, which we think is tremendous.

[Thomas Nusz, executive]

I think having been in a position where we can keep volumes flat on an aggregate basis and generate free cash flow that then we can bank to lay off financial alternatives versus operational alternatives is a great place to be. We've talked about it for a long time and just make sure that you get the dollar going to the next optimal place. And as Michael mentioned, I think, in the short term, it's all going back to the balance sheet and providing more firepower.

[Brad Heffern, analyst]

Okay. Thanks for that. And I guess, obviously, as you slowdown, that lengthens the inventory life to some extent. Does that make you have a greater desire to potentially prune some of the longer-dated inventory?

[Thomas Nusz, executive]

We'll see how the market is. It gives you flexibility for sure.

[Operator]

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

[Thomas Nusz, executive]

Thanks, Drew. To sum it up, Oasis continues to execute on our long-term plan with our deep low-cost inventory in the Williston driving capital efficiency and allowing for free cash generation in a low price environment. In the Delaware, we continue to delineate our position and accretively grow our footprint, while preparing for full field development. We have the team and the strategy in place to succeed, and we look forward to delivering for all of our stakeholders. Thanks, again, for joining our call.

[Operator]

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