Good morning. My name is Ben, and I will be your conference operator today. At this time, I'd like to welcome everyone to the second quarter 2019 earnings release and operations update for Oasis Petroleum. All participants will be in listen-only mode. Should you need assistance, please signal the conference specialist by pressing the star key followed by zero. After today's presentation, there will be an opportunity to ask questions. To ask a question, you may press star, then one on your touch-tone phone. To withdraw your question, please press star, then two. 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.
Thank you, Ben. Good morning, everyone. Today, we are reporting our second 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 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&P level, excluding the impact of OMP. As an organization, we continue to focus on first-year 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&P level at current oil prices.
Second, in the Williston, in spite of some challenging weather and flooding conditions, we executed well on the D&C side, getting 24 wells online during the second quarter, albeit weighted to the latter part of the quarter. Third, in the Delaware, we've been able to secure services and drive operational efficiencies, get visibility on takeaway capacity. We continue to make significant progress delineating our position and understanding the subsurface. We brought on three wells testing the Wolfcamp A, B, and C across our position. We also completed three other wells during the quarter in our Sugarloaf spacing unit, testing our spacing concept in the Wolfcamp A, upper and lower. These latter three wells were fracked in the second quarter and came on production early July. Keep in mind that while the CapEx was spent in the second quarter, 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 1,280-acre spacing unit. In fact, all of this puts us in a position now to move towards development mode. Fourth, our midstream assets continue to provide an advantage. This can be seen in our cost structure, net backs, 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 Williston Basin. We IPO-ed the Oasis Midstream Partners almost two 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 second quarter. 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 second quarter completions, really starting to show up now had 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 86.8 thousand BOEs per day-88.5 thousand BOEs per day to account for our current views.
We are now estimating third-quarter volumes to range between 87 and 90,000 BOEs per day with an oil cut of around 71.5%. We continue to expect the fourth 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 fourth quarter exit rate, depending on oil price, our cash flow generation, and operations plan. Additionally, we've updated slide seven on 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 two-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 lowered natural gas and NGL pricing. We now expect to generate $75 million-$120 million of free cash flow at the E&P business in 2019 at a $50-$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&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 at 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 eight and nine 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 break-even.
Our remaining inventory in these areas averages between seven and 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 $7.6 million, and we see a path to work these down to $7 million 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 one-month cumulative oil production of 3,500 barrels per 1,000 foot of lateral. A recent Wolfcamp C well, the Kerwin A1H, delivered three-month cumulative oil production of 7,500 barrels per 1,000 foot of lateral. Additionally, we brought on a three-well Wolfcamp A spacing test in early July.
As a reminder, we'll be conducting a larger eight-well spacing test, which we're currently drilling, expect to bring online in 2020. We've learned a tremendous amount since closing on the Forge asset in early 2018. We've been able to secure services at a reasonable cost, execute on our well program, navigate through 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 two-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 than originally planned. We continue to expect completions of nine to 11 wells for the year. As always, our focus remains on 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 one to three-well pad. Additionally, we're funding these additional wells with free cash flow generated in 2019. Said another way, E&P free cash flow will be slightly less this year, 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 $9.6 million for a four-well pad, which compares to approximately $11.5 million in 2018. 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, 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 $1.6 billion, with only $531 million drawn as of June 30th, 2019. Oasis had a net debt in the second quarter annualized EBITDA multiple of 2.7 times, with adjusted EBITDA attributable to Oasis approximating $238 million 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 1st. Oasis continues to work with third 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 million-$230 million. 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 million-$16 million. 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 front. We have approximately 80% 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. Williston 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 2019 should continue to improve realization. We took down the top end of our differential guidance range, and we're now expecting $1.50-$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 two-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. We will now begin the question and answer session. To ask a question, you may press star, then one on your touch-tone phone. If you are using a speakerphone, please pick up your handset before pressing the keys. To withdraw your question, please press star, then two. At this time, we will pause momentarily to assemble our roster. Our first question comes from Derrick Whitfield with Stifel. Please go ahead.
Thanks, good morning, all.
Morning, Derrick.
Perhaps for Michael, referencing slide seven 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 million of the $80 million 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?
No, it's a great question, Derrick. Really appreciate that. You're absolutely right. What we talked about at the beginning of the year, remember, we were in a mid-$40 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. 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. We did have in that free cash flow chart at $60, $50 million 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. Thankfully, we've been closer to that level in terms of pricing. We've enjoyed that free cash flow. 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. 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 it's just a little bit different, and we've taken the deflation assumptions out of those CapEx numbers that we've just newly guided to. Those are 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 million of difference from what we had in that free cash flow before versus where differentials in pricing is today. You're seeing that impact that number as well.
That's great. Thanks for the confirmation. 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. 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?
Yeah. Let me make a comment, Derrick, and then I'll turn it over to Taylor. As we went into the downturn, we contracted to activity in Williston Basin, and that asset was 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 two, and bumped that up to 2.2 Bcf a day. 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.
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. That asset won't be quite as strategic to us on a go-forward basis as it has been in the past. Taylor?
Yeah. 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. As Tommy said, it was super strategic at the time because all the gas capture laws, we wanted to make sure we had that infrastructure in place. As we were doing that, obviously in a downturn, being very cautious about where we're spending our dollars and with the focus on being free cash flow positive, we were very open about considering alternatives for those investments. Was there a different way to fund that very important spend for us? We had a lot of conversations with you guys around that.
At the time, a little more challenging to find those dollars, especially for really a nascent business that was just getting off its feet. The good news is, if you fast-forward to today, and it is a substantial business. It is differential in terms of the first mover up in the basin on building out gas infrastructure, and the cash flows and value in the business has materialized, still growing with great coverage ahead of us. The great news around that is that there's really big value in it. 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.
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?" We've been open about it, again, saying, like in 2015 and 2016, we're open to alternatives, and we'll consider all those things. 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, what we try to build is coveted assets. 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. That's what we try to do across our entire portfolio, is build coveted assets. We certainly think this is one of them.
Thanks, Tommy and Taylor. 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 the moving pieces there that have changed a little bit. How do you think about, as you're building up, it sounds like a little bit of an incremental backlog from a completion standpoint? What does the DUC count look like, I guess, as you head out of the year? Is that really, like you alluded to, really more a function of just 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 one to three-well pads and having a single-digit DUC backlog was natural with that. With the increased cycle times that we've talked about, keeping two rigs going, you're likely to build to low to mid-teens next year. It does two things. One 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. You're going to need a little bit more of a DUC backlog if you're going to drill eight wells before you frack them and then follow with another one. You just need a little bit more of a pad.
There is some additional buildup there that gives us the flexibility next year, depending on how things are going, to draw that down a bit. 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. Can you remind me what the required activity levels look like from a lease capture standpoint in the Delaware in 2020?
Yeah, it's kind of a one and a half. It depends on cadence, one and a half rigs to meet our landholding requirements. Most of that is, we talked about 70% of our land is on the Delaware, and we've got a great agreement there that 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. 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 million in the back half. Is that something that's already played into the updated budget, or would that be, I guess, a potential tail end in the back half of the year?
Yeah. Really, at this point, we've kind of factored in the cost, the 7-6 range that we're talking about, Michael. 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.
Morning, guys. Quick question.
Hey, Ron.
on the Delaware. Can you talk a little bit maybe about the spacing test you did? I know you just came on in July. What kind of spacing was that done on? When you move, and I think you said you're doing an eight-well spacing test now, is the second spacing test designed to test not just the upper and lower A, but also the B and C on the same pad?
Ron, good question. The first test, the three-well test, it was all in Wolfcamp A. We actually had two lower Wolfcamp A wells and one upper Wolfcamp A well. The spacing, the two lower wells were 800 feet apart. The upper well was right back in between them, and it was about 200 feet above them, so it's like a wine rack. You had that one right in the middle, but 200 feet above, up in the upper Wolfcamp A. Horse Island was 400 feet from those lower Wolfcamp wells. In terms of the eight-well test that's coming up, it's going to be a combination Third Bone Spring sand and Wolfcamp A test. We'll have four wells in the Third Bone Springs and then four wells in the lower Wolfcamp A. At this point, we're looking at that going forward.
We don't have B and C incorporated in the multi-well test. As we talked about, we've got a number of really attractive, B and C tests that we're excited about. We're looking at incorporating more of the column as we go down the road.
Okay, great. Michael, just for you on the slide seven chart, I know the new presentation updates for the new CapEx, you still have kind of an EBITDA number based on $50 oil prices. You seem to be burdening the CapEx with the higher CapEx level. What kind of impact does that $10 delta have in the EBITDA? Is it as simple as kind of that $25 or $30 million 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. 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. Is there a possibility that you could bring it down if you sat at 50 and today the strip is closer to 50 for a longer period of time? Possibly, right now this has kind of the less deflation case in there. 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 to the midpoint of 115. That $30 million number you're referencing is kind of the differential between those scenarios.
Great. Thank you, guys.
Thanks, Ron.
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's expected to be down a little bit, and there's only expected to be around $100 million in CapEx. I was just wondering if those two things are related and what it says about the momentum into 2020.
When you look at the production, like you said, it is going to taper down a little bit in fourth quarter. 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 capital well performance. As we look into four Q this year, we think that number while down a bit really sets us up for 2020. One of the things that I'd 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. If you look at our pre-'19 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 13-14 well per spacing unit range. We've walked that down over time. Really going back into parts of 2018, we really made this shift, but everything going forward is this 10-11 well spacing. 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. All that stuff kind of plays into the number for 4Q as we've dialed it in. 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%-65% of that's going to be in three Q, and then the balance will be in four Q. Just so people aren't thinking, "Hey, it's just going to be evenly split between the quarters," because we'll get a few more wells fracked in three Q than four Q, and then we'll work on when we bring those on.
Okay. Got it. Just an administrative question, maybe for Michael. Do you have a commodity mix for the Wild Basin downtime? 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 know that the oil was impacted, but we don't know exactly how much. Of that 3,000 a day, it could be a bit higher net too 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.
You're right. That gas plant downtime did impact potentially on the oil side as well. 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 Dan Pickering with TPH Asset Management . Please go ahead.
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, 2020 versus 2019, roughly?
I think to start with, what we'll probably talk about is just what the capital program's going to look like we think going forward. Michael can add to this. It's probably flat to slightly down from this year and for 2020. In fact, it's probably pretty close to what's out there from a guidance perspective at this point. Then Michael can add to that on the volume side.
Yeah. Dan, I think that you'll see for 2019 guidance, that consolidated numbers is right around 850. As Taylor mentioned, next year, that consolidated number should come down. I think consensus has it just under 800, and I think that's probably a good ballpark, and that's on a consolidated basis. Then, I think Tommy talked about in his comments, fourth quarter oil volumes, we should be in a position to keep that flat to growing a little bit. Obviously there's a lot of things 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.
Yeah. Thanks. I guess conceptually, I'm looking at a stock market that 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 where we sit today. 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's treating the company now, 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, OMP monetization. Something isn't working now, what changes going forward?
Yeah, 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&P, we've got a portfolio of coveted assets like I talked about earlier. When we start thinking about the midstream, and there's a focus on Wild Basin, but it also, on the water side, touches our entire footprint in the Williston. Ultimately, we do feel like there's a coveted asset there that whether it's our coveted assets or somebody else's, coveted assets provide a lot of optionality. 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.
Yeah. I guess I understand it. It increases optionality, Tommy. Let's pretend that action comes on that front sometime in the next six 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&P? How would you handle that?
Yeah. I think as we've talked about in the past, Dan, in today's world, what you've heard us say is when you look at debt metrics, the old three is below two, and it may be even one and a half. I do think as we get screened, that metric does provide a bit of a drag. 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, 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. Prioritization is paying down debt first and foremost, Dan.
Yeah. Okay. Thank you.
Thanks, Dan.
Our next question comes from David Deckelbaum with Cowen. Please go ahead.
Morning, Tommy and Michael and Taylor.
Hey, Dave.
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 the extended core going into Alger, South Cottonwood area. I guess as you're evaluating these and you're looking at these areas 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?
Really probably some of both. When you look back at-- you remember after we did the Forge deal, we went through a divestiture process, sold about $360 million in assets, we originally talked about looking at something around $500 million, we just, at that time, elected to just go with what we thought was the very best value. 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. By our testing and third-party testing both, it's doing two things. One is it's pulled more of this inventory into the core and what's economic at a low price point, it really sets us up for our continued drilling program as we go forward.
In addition to that, it really makes some of this acreage attractive that was further out in the queue. So we're excited about having more of those tests push out on the acreage. 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 our leverage down, as we just talked about, then those are things that we'll be looking at. Some of both.
I appreciate that. I guess we haven't seen a ton of Bakken transactions outside of, I guess, some stuff in the first quarter, I guess, for obvious reasons, especially in the public arena. I guess, have you seen any interest? I guess, has the mix of buyers changed that you're seeing out there that are sniffing around deals right now? Is it more on the private side now or private equity side, or are you still seeing the same players that would be out there?
Obviously, as you've mentioned, David, the A&D market is extremely challenged, especially as you think about public company buyers with the capital markets where they are. You've really seen that A&D market shrink. Where you have seen transactions done more broadly, there has been a little bit more capital access on the private side, that is where you've seen some of the more recent deals.
Well, thank you, guys. Best of luck with everything. Appreciate the time.
Thanks, Dave.
Our next question comes from Noel Parks with Coker & Palmer. Please go ahead.
Good morning.
Hey, Noel.
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 the precipitating event was and whether it's something, in hindsight, was foreseeable or more of a random thing?
We didn't talk specifically about the downtime, Noel, but it's a good question. 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 moved forward to building our second 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. That all played out really well. The other nice thing for us is that while we stress 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 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 what I would call some of that startup phase of knocking out the kinks. It did impact us because of our concentration in Wild Basin to that plant. Broader speaking, getting that gas plant up online on time in December was just a huge feat for the team, and what I'd call this is just some of that initial startup that we got six months into it, and now we're through it and we think we're past it.
Yeah, you'd like to think that these things are all cookie cutter and you turn them on and they work perfectly.
They're a little bit more complex than that. You always know that you're going to have a little bit of, whether it's three months or six months, trying to get these things lined out and operating correctly and efficiently. That's not a wild surprise. You'd rather not have that. It's not a wild surprise.
Just actually, can you tell us how long the plant was down? How many days?
It was about 20 days, plus or minus, so something like a few weeks.
Ballpark.
Yep.
Okay, great. Just turning to the Delaware for a minute. I've heard some other operators out there comment on 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? Just with oil having been a little weaker lately, is there not so much of a press going on anymore?
Yeah, 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.
Sure.
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 it around the acreage. We've been successful. 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. 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, is your sense that we're kind of in the final innings of that process or just something that's going to keep going?
Yeah. No. Look, it's actually if anything, kind of that trade activity and bolt-on is, if anything, maybe picked up a bit. 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. 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 Doing trades is never easy, but at least people are feeling a need to consolidate, and as I mentioned, we just picked up some acreage that allowed us to form a 1280 where we didn't have it before. It does tend to get people focused on it.
Great. Thanks a lot.
You bet.
This concludes our question and answer session. I would now like to turn the conference back over to Tommy Nusz 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. 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.