Morning. My name is Ben, and I will be your conference operator today. At this time, I'd like to welcome everyone to the Q2 2019 Earnings Release and Operations Update for Oasis Petroleum. All participants will be in listen only mode. Please note this event is being recorded.
I will now turn the call over to Michael Liu, Oasis Petroleum's CFO to begin the conference. Thank you. You may begin your conference.
Thank you, Ben. Good morning, everyone. Today, we are reporting our Q2 2019 financial and operational results. We're delighted to have you on our call. I'm joined today by Tom Anous 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 ks 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 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 and thanks for joining our call. The Oasis team continues to execute on our plan, harvesting free cash flow from the Williston to fund Permian development and generate free cash flow at the E and P level, excluding the impact of OMP. As an organization, we continue to focus on 1st share value drivers of cash flow, cash margins, return on investment, capital efficiency and volume performance relative to our budget targets, all of which should drive attractive returns whether at the well project or corporate level. Taylor will get into more operational detail in a minute, but I want to highlight a few key points about our performance and strategy. First, Oasis continues to execute its measured development program in 2019 and expects to generate strong free cash flow at the E and P level at current oil prices.
2nd, in the Williston, in spite of some challenging weather and flooding conditions, we executed well on the D and C side, getting 24 wells online during the 2nd quarter, albeit weighted to the latter part of the quarter. 3rd, in the Delaware, we've been able to secure services and drive operational efficiencies, get visibility on takeaway capacity, and we continue to make significant progress delineating our position and understanding the subsurface. We brought on 3 wells testing the Wolfcamp A, B and C across our position. We also completed 3 other wells during the quarter in our Sugar Loaf spacing unit testing our spacing concept in the Wolfcamp A upper and lower. These latter 3 wells were fracked in the Q2 and came on production early July.
So keep in mind that while the CapEx was spent in the Q2, they'll show up in our July completion count. Additionally, we were able to do a small bolt on acquisition in Ward County that created a 12 80 acre spacing unit. In fact, all of this puts us in a position now to move towards development mode. 4th, our midstream assets continue to provide an advantage. This can be seen in our cost structure netbacks and flow assurance.
As we said for some time, the midstream side of the business has been a big win for us and a very important component of managing business risk over the last several years as all of our drilling was focused on Wild Basin. We IPO ed the Oasis Midstream Partners almost 2 years ago and it's proven to be one of the better performing partnerships in a difficult market. We continue to look at ways to enhance the value of our ownership in this asset. During the quarter, we did experience some downtime in the Wild Basin gas complex. The impact reduced quarterly production by approximately 3,000 BOEs per day net in the Q2.
We will also have some impact in early July that's captured in our guidance. The complex has been up and running well since mid July and over the last few weeks. That coupled with us seeing the production from our 2nd quarter completions really starting to show up now. And total Oasis production averaging about 89,000 BOEs per day in July. We continue to incorporate our views of well performance, completion timing and any infrastructure constraints into our full year guidance and have updated our range to 86,800,000 to 88,500 BOEs per day to account for our current views.
We are now estimating 3rd quarter volumes to range between 8,700,000 BOEs per day with an oil cut of around 71.5%. We continue to expect the 4th quarter oil cut to trend down a little bit to about 71%. With things moving around a bit on us here, it's early to begin totally flushing out 2020, but we would expect both oil and total volumes to be roughly flat to up relative to our Q4 exit rate depending on oil price, our cash flow generation and operations plan. Additionally, we've updated Slide 7 of our presentation to reflect our latest free cash flow projections. We have updated our capital assumptions.
As you saw in our press release, the increase primarily reflects an adjustment to deflation expectations related to a lower crude price in our budget assumptions, improved cycle times in the Delaware Basin, resulting in increased spuds with a 2 rig program and the number of operated wells with higher working interest as well as increased non op spending in the highest return parts of the Williston Basin. All of this results in an increase in CapEx, but that's more than covered by our free cash flow generation. On the EBITDA side, we've adjusted for pricing year to date, made tweaks to our volume forecast and lower natural gas and NGL pricing. We now expect to generate $75,000,000 to 120 $1,000,000 of free cash flow at the E and P business in 2019 at a $50 to $60 WTI price. Our intent at this point would be to take excess cash to our revolver as we've talked about in the past.
Despite a few headwinds, Oasis E and P stands to deliver strong free cash flow this year. The underlying business remains strong and we continue to advance our strategic objectives, which include size and scale, portfolio diversity, asset quality and financial strength. With that, I'll turn the call over to Taylor.
Thanks, Tommy. We continue to execute our 2019 program with a focus on efficient operating in the Williston and preparing the Delaware for full field development. Oasis well productivity in Williston remains the top of the pack. As seen on Slide 10 of our investor deck, we are ranked number 2 for the 12 month cumulative average oil equivalent versus our peers. Separately, we continue to be encouraged by delineation results from step out areas.
Slides 89 have been updated to reflect the latest data from select emerging areas in the Williston. We continue to see outstanding results in Painted Woods, North Alger, South Cottonwood and Red Bank, which shows that 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 a low economic breakeven. Our remaining inventory in these areas averages between 7 10 wells per spacing unit. When combined with current well costs, these well performance numbers lead to great economics across the play.
Current well costs for the Bakken average about $7,600,000 and we see a path to work these down to $7,000,000 by the end of the year. Switching to the Delaware, we're seeing strong performance across the entire column with certain Wolfcamp B and C wells performing in line with the Wolfcamp A. We recently brought on a Wolfcamp B, the Rattlesnake 1H, with 1 month cumulative oil production of 3,500 barrels per 1,000 foot of lateral. A recent Wolfcamp C well, the Kerwin A1H, delivered 3 month cumulative oil production of 7,500 barrels per 1,000 foot of lateral. Additionally, we brought on a 3 well Wolfcamp A spacing test in early July.
Reminder, we will be conducting a larger 8 well spacing test, which we're currently drilling and expect to bring online in 2020. We've learned a tremendous amount since closing on the Forage asset in early 2018. We've been able to secure services at a reasonable cost, execute on our well program, navigate to volatile basis pricing and develop an effective marketing strategy, which will command attractive pricing. Our subsurface knowledge is growing rapidly through Oasis wells, non operated activity, trading information with other partners and third party data sources. Cycle times are improving rapidly as well.
As we began to discuss last quarter, we've made significant strides in reducing our drilling days with our most recent 2 mile lateral wells being drilled in the 25 to 30 day range versus our first wells in the basin that were in the 40 plus day range. This has allowed us to drill more wells this year optimizing capital optimizing capital efficiency. While we could drop a rig to forego these additional wells and the associated spending in 2019, keeping an efficient crew together and continuing to lower well cost is important. The fact that we're moving into development with more DSU drill out means that we will carry a little larger DUC backlog than what we were in testing mode when we were drilling 1 to 3 well pads. Additionally, we're funding these additional wells with free cash flow generated in 2019.
Said another way, E and P free cash flow will be slightly less this year, but the benefits of having an efficient program with manageable cycle times are a net positive for the company. Drilling speed should continue to improve as well as we optimize well design and shift to pad development. In development mode, we would expect drill times to be in the mid to low 20s, and we're targeting well costs of $9,600,000 for a 4 well pad, which compares to approximately $11,500,000 in 20 18. We've learned a great deal since integrating this world class asset about 18 months ago. Well performance remains exceptional, and we've been able to lower costs significantly.
We continue to believe economics will be as good as or potentially better than the best parts of the Williston. To close, we continue to execute on our 2019 plan, focused around an efficient Williston program as we move into development in the Delaware. Oasis benefits from our inventory depth, subsurface expertise, operational experience as well as a top notch marketing team. We're excited about driving these assets forward into 2019 and beyond. With that, I'll now turn the call over to Michael.
Thanks, Taylor. Oasis remains focused on delivering our 2019 program. Operating costs are in check and oil realizations remain strong. We are on a trajectory to deliver significant free cash flow in 2019. We continue to enjoy strong liquidity levels with a total borrowing base of $1,600,000,000 with only $531,000,000 drawn as of June 30, 2019.
Oasis had a net debt in the 2nd quarter annualized EBITDA multiple of 2.7x with adjusted EBITDA attributable to Oasis approximating $238,000,000 in the second quarter. Turning to Midstream, we continue to work towards executing final agreements for the dedication of certain Delaware acreage to OMP via the Panther DevCo. We would expect this to be finalized September 1. Additionally, Oasis continues to work with 3rd parties for gas infrastructure in the Delaware and expects to provide an update in the coming months on the outcome of the selection process. Total midstream CapEx was adjusted to range $219,000,000 to $230,000,000 This largely reflects additional third party business, incremental plant costs and an acceleration of gathering and infrastructure construction spending from 2020 into 2019.
Net CapEx to Oasis attributable to its retained interest is expected to range between $15,000,000 $16,000,000 We'll be talking in more detail on the OMP call shortly, and I would direct you to our OMP press release for more color on our continued success on the midstream percent of the remainder of 2019 estimated oil production hedged at a weighted average floor price of $56 per barrel. For 2020, we've added additional collars and swaps, the details of which can be found in the appendix of our investor presentation. Wilson crude differentials remain strong as our marketing team has done a great job of being opportunistic in getting Oasis superior realization. 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 twenty nineteen should continue to improve realization. We took down the top end of our differential guidance and we're now expecting $1.50 to $3 per BOE through 2019.
As everyone is aware, natural gas and NGL prices have deteriorated significantly since May. Oasis benefits from its midstream assets and was an early mover in securing strong contracts with third parties to process and market our NGLs. This should keep our pricing relatively towards the top end of our peer group. However, on an absolute basis, gas and NGL realizations have come down significantly. And for modeling purposes, we've begun providing differential guidance on a 2 stream basis.
To sum things up, Oasis continues to execute well and we're in strong position to deliver in 2019 and beyond. With that, I'll hand the call back over to Ben for questions.
Thank you. Our first question comes from Derrick Whitfield with Stifel. Please go ahead.
Thanks and good morning all.
Good morning, Derek.
Perhaps for Michael, referencing Slide 7 of your presentation, if I recall based on past conversations on this slide, your views on potential free cash flow outcomes for 2019 contemplated $50,000,000 of the $80,000,000 increase just announced for upstream CapEx. Could you confirm that and possibly walk us through any other material changes in your Q2 versus Q1 assessment?
Yes. No, it's a great question, Derek. Really appreciate that. You're absolutely right. So what we talked about at the beginning of the year, remember, we were in a mid-forty dollars oil price when we budgeted for the year.
As we came out in February with that budget, we talked about a budget at $50 and we came out with a CapEx number. And in that cash flow chart and through many discussions with you and with others, we talked about in a $60 environment, you wouldn't see the same type of deflation that you would see in a $50 environment. And so, we did have in that free cash flow chart at $60,000,000 $50,000,000 more essentially for the lack of deflation at the same pace that we would have saw in the $50 environment. Where you've seen oil prices so far this year, activity level has really been more in the $60 level. And thankfully, we've been closer to that level in terms of pricing.
We've enjoyed that free cash flow, but service costs have remained a bit higher. Now you're seeing a lot of progress that we're making not quite as quickly as that $50 scenario, but you're seeing well costs come down across both basins and we think we can continue to hold that. You're seeing service costs starting to soften now, but they're just a little bit different, and we've taken the deflation assumptions out of those CapEx numbers that we've just newly guided to. So those are kind of the differences. Obviously, on the free cash flow side, you're also seeing some adjustments on the NGL and natural gas side.
We talked about significantly lower realizations on that side. There's probably about $30,000,000 of difference from kind of what we had in that free cash flow before versus where differentials and pricing is today. So you're seeing that impact that number as well.
That's great. Thanks for the confirmation. And then perhaps for yourself or Tommy, there has been growing discussion within the investor community regarding the long term strategic fit of your midstream business. As I recall from your comments last quarter, the upstream business has derived tremendous benefit from Oasis having control of the infrastructure. However, you guys did note that its strategic importance is evolving.
Big picture, if you were to think about the amount of expected gas processing additions in the Bakken in the second half and your progress in the Delaware to date, how do you currently view the strategic importance of that business?
Yes. Let me make a comment, Derek, and then I'll turn it over to Taylor. But as we went into the downturn, we kind of contracted to activity in Wild Basin and that asset was really, really important to us to be able to move our volumes. As you know, until that gas plant came on, gas production in the basin was 2.8 Bcf a day, processing capacity 2 Bcf a day and then our plant came on plant 2 and bumped that up to 2.2 Bcf a day. And so we've been very fortunate in that we've been able to absent the little blip we had here in June, early July, we've been able to move our volumes, which has been tremendously important to us.
But as we start to look at the future and more activity in areas outside of Wild Basin, which based on the slide in the presentation, you can see a lot of those areas have really improved over the last few years in terms of results. That more of our drilling activity will move out of Wild Basin. So that asset won't be quite as strategic to us on a go forward basis as it has been in the past. Taylor?
Yes. So what I'd add to that is if you look back in 2015, 2016, you'll remember that was when we really were spending a lot of dollars developing the midstream on the gas side, building the plants, building out the Wild Basin infrastructure. And as Tommy said, it was super strategic at the time because all the gas capture laws wanted to make sure we had that infrastructure in place. And as we were doing that, obviously, in a downturn, being very cautious about where we're spending our dollars and with a focus on being free cash flow positive, we're very open about considering alternatives for those investments. Was there a different way to fund that very important spend for us?
And we had a lot of conversations with you guys around that. At the time, a little more kind of challenging to find those dollars, especially for really a nascent business that was just getting off its feet. And the good news is, if you fast forward to today and it is a substantial business, It is differential in terms of a first mover up in the basin on building out gas infrastructure And the cash flows and value in the business has materialized, still growing great coverage ahead of us. And so the great news around that is that there's really big value in it. And to Tommy's point about how do you think about it strategically, it's still very important to us.
But the biggest strategic piece of it that we wanted to get set up and get it in place has been served at this point. So as we go forward and think about that investment and the value in it, People ask, hey, would you ever consider doing anything with that? And we've been open about it again saying, like in 'fifteen and 'sixteen, we're open to alternatives and we'll consider all those things. And we want to maximize value for the company. And so we'll be thinking about all those things going forward.
At the end of
the day, it's what we try to build is coveted assets. And this has been a coveted asset for us. And I think it would be a coveted asset for a lot of other people as well. But that's what we try to do across our entire portfolio is build coveted assets, and we certainly think this is one of them.
Thanks, Tommy and Tiller. That's very helpful, guys.
You bet.
Our next question comes from Michael Hall with Heikkinen Energy Advisors. Please go
ahead. Thanks. Appreciate it, guys. I was just curious,
I guess, a little bit on the Delaware program, better understanding kind of the moving pieces there that have changed a little bit. How do you think about kind of as you're building up, it sounds like a little bit of an incremental backlog from a completion standpoint. How big of what does the DUC count look like, I guess, as you head out of the year? And is that really, like you alluded to, really more a function of just kind of optimizing for the changing pad size versus providing some sort of future potential drawdown potential that would improve capital efficiency in 2020?
Michael, it's really probably a little bit of both. As we've been talking about the DUC backlog, when we're drilling up to this point, we're really doing kind of 1 to 3 wall pads and having a single digit DUC backlog was natural with that. With the increased cycle times that we've talked about keeping 2 rigs going, You're likely to build the low to might be the low to mid teens next year. And so it does 2 things. 1 is we're on an eight well pad right now.
The one that's behind it is likely to be somewhere in that kind of range as well. And so you're going to need a little bit more of a backlog. You're going to drill 8 wells before you track them and then follow with another one. So you just need a little bit more of a pad. But there is some additional buildup here that gives us the flexibility next year depending on how things are going to draw that down a bit.
And so we'll as we get into 2020, we'll be looking at all those options. What's that right level? Do you pull it down a bit more from a capital efficiency standpoint like you talked about?
Okay. And can you remind me what the kind of required activity levels look like from a lease capture standpoint in the Delaware in 2020?
Yes, it's been it's kind of 1.5 it depends on cadence, kind of 1.5 rigs to meet our land holding requirements. And most of that is we talked about about 7 percent of that is on of our land is on the Delaware. We've got a great agreement there that allows us to we can drill in development mode and it holds the pool of acres. We don't have to be jumping all around and it really helps from an efficiency standpoint.
Okay. That's helpful. And then last one on my end is, you mentioned in the prepared remarks that I think it was you, Michael, that you see potential room to take Williston Basin well cost down closer to $7,000,000 in the back half. Is that something that's already played into the updated budget? Or would that be, I guess, a potential tailwind in the back half of the year?
Yes. Really, at this point, we've kind of factored in the cost that we the 7%, 6% range that we're talking about, Michael. And so that could provide a bit of a tailwind depending on how well we do.
Okay. Well, I appreciate
the time guys. Thank you. You bet, Michael.
Our next question comes from Ron Mills with Johnson Rice. Please go ahead.
Good morning, guys. A quick question following up on the Delaware. Can you talk a little bit maybe about the spacing test you did? I know it just came on in July. What kind of spacing was that done on?
And then when you move and I think you said you're doing an 8 well spacing test now, is that is the 2nd spacing test designed to test not just the upper and lower A, but also the B and C on the same pad?
Yes. Ron, good question. The first test, the 3 well test, it was all in Wolfcamp A. And so we actually had 2 Lower Wolfcamp A wells and 1 Upper Wolfcamp A well. The spacing, the 2 lower wells were 800 feet apart.
And then the upper well was right smack in between them. And it was about 200 feet above them. So it's like a wine rack, you had them that one right in the middle, but 200 feet above up in the Upper Wolfcamp A. And then horizontally, it was 400 feet from those Lower Wolfcamp wells. And in terms of the 8 well test that's coming up, it's going to be a combination Third Bone Spring Sand and Wolfcamp A test.
So we'll have 4 wells in the Third Bone Springs and then 4 wells in the Lower Wolfcamp A. So at this point, it's not and we're looking at that going forward. We don't have B and C incorporated in the multi well test. But as we talked about, we've got a number of really attractive B and C tests that we're excited about. So we're looking at incorporating more of the column as we go down the road.
Okay, great. And then Michael, just for you on the Slide 7 chart. I know the new presentation updates for the new CapEx, you still have kind of an EBITDA number based on $50 oil prices. So you seem to be burdening the CapEx with the higher CapEx level. But what kind of impact does that $10 delta have in the EBITDA?
Because is it as simple as it's kind of that $25,000,000 or $30,000,000 delta, as shown on the far right. I just want to try to make sure I understand the you do have an associated EBITDA benefit from the higher prices even though it does impact spending.
Correct. No, that's absolutely right, Ron. And that is a good way to look at it at this point. The free cash flow numbers now have the same capital, assuming that kind of higher cost level kind of throughout the year. So is there a possibility that you could bring it down if you sat at 50 and today where the strip is closer to 50 for a longer period of time?
Possibly, but right now this has kind of the less deflation case kind of in there. And the way to think about the differences with hedges and all that impact is that difference in the free cash flow line kind of midpoint of $85,000,000 to the midpoint of $115,000,000 So that $30,000,000 number you're referencing is kind of the differential between those scenarios.
Our next question comes from Brad Heffern with RBC Capital Markets. Please go ahead.
Hey, good morning, everyone. Just looking at the new guide and what the 3Q guide implies for 4Q, it looks like production is expected to be down a little bit and there's only expected to be around $100,000,000 in CapEx. I was just wondering if those two things are related and what it says about the momentum into 2020?
So when you look at the production, like you said, is going to taper down a little bit in Q4. And it's really it's just really everything coming together. And we look every quarter. We look at everything from our PDP base to the capital wells coming online, to the capital well performance. And so as we look into 4Q this year, we think that, that number, while down a bit, really sets us up for 2020.
One of the things that, let's say, is from a PDP standpoint, as we continue to look at our volumes, one of the things we've talked about in the past and factored in a bit here is we've talked about spacing. And if you look at our pre-nineteen wells, and this is really focused in Wild Basin, we tended to be a little tighter. When we drilled the very first wells there, we were in kind of 13 to 14 well per spacing unit range, and then we've walked that down over time. Everything 'nineteen forward is and really going back into parts of 'eighteen, we really made this shift, but everything going forward is kind of this 10 to 11 well spacing. And we think we're spaced about right at this point.
The impacts of the tighter spacing, we think we have fully factored in and have that behind us as we go forward. But all that stuff kind of plays into the number for 4Q as we've dialed it in. And then the last thing I'd say in terms of cadence, which you touched on, our capital, when you look at 3Q and 4Q, it's going to be still weighted a little bit more with the remaining capital we have for the year. Probably about 60% to 65% of that's going to be in 3Q and then the balance will be in 4Q. So just so people aren't thinking, hey, it's just going to be evenly split between the quarters because we'll probably get get a few more wells fracked in 3Q than 4Q and then we'll work on when we bring those on.
Okay, got it. And then just an administrative question maybe for Michael. Do you have a commodity mix for the Wild Basin downtime? And does it look approximately like what Wild Basin looks like on a production mix? Or was it more gas weighted?
That number specifically is a little bit more gas weighted, Brad. We don't we know that the oil was impacted, but we don't know exactly how much. And so of that 3,000 a day, it could be a bit higher than that 2 with the oil side, but more of that's going to be on the gas side in terms of the way we thought about that.
Okay, thanks.
But you're right, that gas plant downtime did impact potentially on the oil side as well. And what we're trying to show is that with the July number is that your production number is back up and part of that is the plant running very efficiently now.
Our next question comes from Daniel Pickering with TPH Asset Management. Please go ahead.
Good morning, guys. Hey, Dan. Michael or Tommy or Taylor, maintenance capital, how do you think about how much money you need to spend to sort of hold volumes flat 'twenty versus 'nineteen roughly?
So I think to start with what we'll probably talk about is just what the and Michael can add to this, but what the capital program is going to look like, we think, going forward. And it's probably flat to slightly down from this year and for 2020. And in fact, it is probably pretty close to what's out there from a guidance perspective at this point. And then Mike can add to that on the volume side.
Yes. So Dan, I think that you'll see kind of for 2019 guidance that consolidated numbers is right around $850,000,000 And as Taylor mentioned, next year that consolidated number should come down. I think consensus has it just under 800. I think that's probably a good ballpark and that's on a consolidated basis. And then I think Tommy talked about in his comments, Q4 oil volumes, we should be in a position to keep that flat to growing a little bit.
And obviously, there's a lot of things that that depends on and we don't have a full program scoped out for 2020 yet, but that's how we're thinking about it.
Thanks. And then, I guess, conceptually, I'm looking at a stock market that doesn't clearly isn't rewarding the assets you've got or the spending program you're doing or it's not rewarding something, it's obviously penalizing you for kind of where we sit today. And I guess my question, I heard on the call some kind of dancing around a little bit about the future of OMP. I just wonder, given how the market is treating the company now, if there isn't if it isn't time for something a little more aggressive and how you guys think about a clearly undervalued equity and the levers that you can pull, whether it's capital spending, O and P monetization, something isn't working now, what changes going forward?
Yes, Dan. I think that the good news in there is that whether you look at what we have in the Williston, what we have in the Delaware, what we have in E and P, we've got a portfolio of coveted assets like I talked about earlier. When we start thinking about the midstream and it I mean it kind of there's a focus on Wild Basin, but it also on the water side touches our entire footprint in the Williston. But ultimately, we do feel like there's a coveted asset there that whether it's our coveted assets or somebody else's, I mean, what you coveted assets provide a lot of optionality. And so like and as we talked about, as we move our drilling activity outside, we've got that thing in place.
And as we move drilling activity outside of the Wild Basin complex, it increases options for us is probably the easiest way to say that, if that makes sense.
Yes. I mean, I guess I understand it increases optionality, Tommy. Let's pretend that action comes on that front sometime in the next 6 months or so. You'd have a lot of cash from some sort of monetization of that asset. What are the priorities for external non operational cash?
Is it paying down debt, which seems like the market's nervous about your leverage. Are you nervous about your leverage? Would you pay down debt? Would you spend more on E and P? How would you handle that?
Yes. I think as we've talked about in the past, Dan, it's in today's world, what you've heard us say is when you look at debt metrics, the old 3% is below 2% and it may be even 1.5%. And I do think as we get screened, that metric does provide a bit of a drag. And so as we've talked about in free cash flow or available cash, that's the first place that it needs to go to get right sized in this market, which and I don't think that's going to change anytime soon. Michael, you got anything to add to that?
No, I think that's exactly right. So, prioritization is paying down debt, 1st and foremost, Dean.
Yes.
Dean. Our next question comes from David Deckelbaum with Cowen. Please go ahead.
Good morning, Tommy and Michael
and Tyler.
Thanks for taking the time. You guys just provided a lot of really comprehensive answers to a lot of questions that I had, but I really just wanted to add on to, one, some of the tests outside, I guess, more in like the extended core going into Alger, South Cottonwood area. I guess, as you're evaluating these and you're looking at these areas kind of expanding, do you see these as opportunities to start allocating rigs towards? Or do you see these as opportunities to delineate some areas like Foreman Butte that you would have looked to sell over time?
So
really probably some of both. And when you look back at you remember after we did the forged deal, we went through a divestiture process, sold about $360,000,000 in assets. And we originally talked about looking at something around $500,000,000 and we just, at that time, elected to just go with what we thought was the very best value. But one of the things you saw at that time was, while there was some good test results with these newer, bigger completions across the basin. They weren't long lived at that point and they hadn't stretched as far as they have right now.
So it by our testing and third party testing, both of this is doing 2 things. 1, it's pulled more of this inventory into the core and what's economic at a low price point. So it really sets us up for our continued drilling program as we go forward. But in addition to that, it really makes some of this acreage attractive that was kind of further out in the Q. And so we're excited about having more of those tests pushed out on the acreage.
And at the right time, we are open to placing those assets in somebody's hands who sees a lot of value in them if it's stuff that's tailing our inventory and helps us to get our debt down or leverage down as we just talked about, then those are things that we'll be looking at, but some of both.
I appreciate that. I guess we haven't seen a ton of Bakken transactions outside I guess, some stuff in the Q1, I guess, for obvious reasons, especially in the public arena. I guess, have you seen any interest on I guess, like has the mix of buyers changed that you're seeing out there that are kind of sniffing around deals right now? Is it more on the private side now or private equity side? Or are you still kind seeing like the same players that would be out there?
Yes. Obviously, as you've mentioned, David, the A and D market is extremely challenged, especially as you think about public company buyers with the capital markets where they are. You should really seen that A and D market shrink where you have seen transactions done kind of more broadly. There has been a little bit more capital access on the private side. And so that is where you've seen some of the more recent deals.
Our next question comes from Noel Parks with Coker and Palmer. Please go ahead.
Good morning.
Hello.
I apologize if you touched on this already, but could you just talk a little bit more about the nature of the downtime at Wild Basin? What kind of the precipitating event was and whether it's something in hindsight was foreseeable or more of a random thing?
Yes. We didn't talk specifically about the downtime, Noel, but it's a good question. Look, one of the things that I'd say is that we saw a couple of years back a huge need for gas processing capacity in the basin. We move forward to building our 2nd gas plant, knowing that the basin was going to be constrained. Today, you've got 2.8 Bcf in the basin with our plan in place, 2.2 Bcf of processing capacity.
So that all played out really well. The other nice thing for us is that while we stress kind of safety and making sure that you can get your systems online and doing it safely, We did that, and we were on time and on budget with the plant, which is a phenomenal success for the team. You have seen because of just the weather fluctuations kind of throughout in a very short build season, a number of other plants didn't have the same type of success of getting up online like ours did. We had some downtime. Some of that's just kind of what I would call some of that startup phase of knocking out the kinks.
And it did impact us because of our concentration kind of in Wild Basin to that point. But kind of broader speaking, getting that gas plant up online on time in December was just a huge feat for the team. And what I would call this is just some of that initial startup that we got kind of 6 months into it. And now we're through it and we think we're past it.
Yes. You'd like to think that these things are all cookie cutter and you turn them on and they work perfectly, but they're a little bit more complex than that. So you always know that you're going to have a little bit of whether it's 3 months or 6 months trying to get these things lined out and operating correctly and efficiently, and that's not a wild surprise. You'd rather not have that, but it's not a wild surprise.
And just actually, can you tell us what the how long the plant was down? How many days?
It was about 20 days plus or minus, so something like it. It took a few weeks ballpark, yes.
Okay, great. And then just turning to the Delaware for a minute. I've heard some other operators out there comment on our being in a window of opportunity where meaningful acreage swaps and so forth can still be accomplished, but that window might be closing. I was just curious if around your acreage, do you have a sense of any urgency about that among your partners and competitors or just with oil having been a little weaker lately, is there not so much of a press going on anymore?
We've focused since we got the assets, a big part of the focus was to just really block it up and do bolt ons. And we've been successful on that front. We've done a number of trades and done some small acquisitions that has resulted in extending the number of places we can drill 2 mile laterals. That was already a high number. It's kind of 75%, 80% of the acreage.
And so we're moving that, continue to move that up and then consolidating in around the acreage. We've been successful. So we've seen good cooperation and willingness to do both trades and where it makes sense to sell assets that aren't core to people or may not be an exact fit for their position that may not be concentrated in this area. So we've been pleased on that front, and it looks like we're going to continue to have those opportunities going forward.
Just to clarify, but is your sense that we're kind of in the final innings of that process or just something that's going to keep going?
Yes. No, look, it's actually, if anything, kind of that trade activity and bolt on is, if anything, maybe picked up a bit. As everybody starts to optimize their capital spend and focus on their operated projects, especially with lease terms in the Delaware that you're very familiar with. It's very different than the Williston Basin, for instance, with different clauses that you have in these leases. So with the combination of those clauses in the leases as well as people being focused on their operated programs and optimizing their CapEx.
If anything, I would say that it's made it I mean, doing trades is never easy, but at least people are feeling a need to consolidate, which and as I mentioned, I mean, we just picked up some acreage that allowed us to form a 1280 where we didn't have it before. And but it does tend to get people focused on
it.
This concludes our question and answer session. I would now like to turn the conference back over to Tommy News for any closing remarks.
Thanks. In closing, Oasis continues to execute its 2019 program. We remain committed to being free cash flow neutral to positive in a volatile oil price environment as we have since 2015. But I want to be clear, we're focused on making prudent long term value decisions for our shareholders. Again, thanks for joining our call.
The conference has now concluded. Thank you for attending today's presentation.