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Oasis Petroleum Inc (OAS)
Q2 2019 Earnings Call
Aug 7, 2019, 11:00 a.m. ET
Contents:
- Prepared Remarks
- Questions and Answers
- Call Participants
Prepared Remarks:
Operator
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. [Operator Instructions] 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 H. Lou -- Chief Financial Officer and Executive Vice President
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 Rreform 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 10K and our quarterly reports on form 10Q. 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.
Tommy Nusz -- Director and Chief Executive Officer
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 -- impact of OMP. As an organization, we continue to focus on per 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&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 21 -- 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 a get visibility on takeaway capacity. Then 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 in early July. So keep in mind that while the capex was spent in the second quarter, they'll show up at our July completion camp. 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've 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 IPOed 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 completion is really starting to show up now at 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 to 88,500 BOEs per day to account for our current views. We are now estimating third quarter volumes to range between 87,000 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 7 in 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 buds 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 to $120 million of free cash flow at the EMP 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&P stands to deliver strong free cash flow this year. The underlying business remains strong and we continue to advance our strategic objectives which includes size and scale, portfolio diversity, asset quality and financial strength. With that, I'll turn the call over to Taylor.
Taylor Reid -- Director, President, and Chief Operating Officer
Thanks, Tommy. We continue to execute our 2019 program with the 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 8 and 9 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 Algiers, 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 7 and 10 wells per spacing unit. When combined with current well cost, 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 thousand foot of lateral. A recent Wolfcamp C well, the Kerwin A 1H, delivered 3 month cumulative oil production of 7,500 barrels per thousand 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 and expect to bring online in 2020.
We've earned 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 the 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 their most recent two mile lateral wells being drilled in the 25 to 30 day range versus our first wells in the basement 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 9 to 11 wells for the year.
As always, our focus remains on optimizing capital efficiency. While we could drop a rig to forgo 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're drilling 1 to 3 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 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 $9.6 million for a four well pad, which compares to approximately $11.5 million in 2018. We've earned 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 world.
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 will now turn the call over to Michael.
Michael H. Lou -- Chief Financial Officer and Executive Vice President
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 the total borrowing base of $1.6 billion, with only $531 million drawn as of June 30, 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 short [Phonetic] in the second quarter. Turning to midstream, we continue to work towards executing final agreement for the dedication of certain Delaware acreage to OMP via the Panther DevCo. We would expect this to be finalized September 1st. Additionally, Oasis continues to work with third parties for gas infrastructure in the Delaware and expect to provide an update in the coming months on the outcome of the selection process.
Total midstream capex was adjusted to range $219 million to $230 million. This largely -- largely reflects additional third party business, incremental plant costs and an acceleration of gathering in infrastructure construction spending from 2020 into 2019. Net capex to Oasis attributable to its retained interest is expected to range between $15 million and $16 million. We'll be talking in more detail on the OMP cost shortly, and I would direct you to our OMP press release for more color on our continued success on the midstream plan. 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 -- in the appendix of our investor presentation.
Williston crude differentials remain strong as our marketing team had 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 a $1.50 to $3.00 per BOE through in 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.
Questions and Answers:
Operator
Thank you. [Operator Instructions]. Our first question comes from Derrick Whitfield with Stifel. Please go ahead.
Derrick Whitfield -- Stifel, Nicolaus & Company -- Analyst
Thanks, and good morning, all.
Tommy Nusz -- Director and Chief Executive Officer
Good morning, Derrick.
Derrick Whitfield -- Stifel, Nicolaus & Company -- Analyst
Perhaps for Michael. Referencing Slide 7 of your presentation, as 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?
Michael H. Lou -- Chief Financial Officer and Executive Vice President
Yes. That's a great question, Derrick. I really appreciate that. You're absolutely right. So, 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, 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, $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 a $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 cost 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, we've taken the deflation assumptions out of those capex numbers that we 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 million 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.
Derrick Whitfield -- Stifel, Nicolaus & Company -- Analyst
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?
Tommy Nusz -- Director and Chief Executive Officer
Yeah. Let me make a comment, Derrick, and then I'll turn it over to Taylor. But, you know, 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, 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 and that we've been able to absent the little blip we had here in June or 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. You know, that -- more of our drilling activity will move -- 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?
Taylor Reid -- Director, President, and Chief Operating Officer
Yes. What I would add to that is, you know, 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 base and infrastructure. And as Tommy said, it was strategic at the time because of all the gas capture laws. We wanted to make sure we had that infrastructure in place and, you know, as we're doing that, obviously in a downturn, being very cautious about where we're spending our dollars and, you know, with a focus on being free cash flow positive, we were very open about considering alternatives for those investments. You know, 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, you know, at the time, a little more, you know, kind of challenging to find those dollars, especially for a really nascent business that was just getting off its feet. And the good news is, you know, if you fast forward to today and it is a substantial business, it is -- 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 is materialized, still growing with great coverage ahead of us.
And so, the great news around that is that there's -- there's really big value. And to Tommy's point about, how do you think about it strategically, it's still very important to us, but the -- the -- the biggest strategic piece of it that we wanted to get set up and get it in place is -- been served at this point. So, you know, as we go forward and -- and think about that investment, and the value in it, you know, people ask, hey, would you -- would you ever consider doing anything with that? And we've been open about it again, saying, you know, like in '15 and '16, we're open to alternatives and -- and we'll consider -- 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.
Tommy Nusz -- Director and Chief Executive Officer
At the end of the day, it's what we -- 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 -- for a lot of other people as well.
But that's what we try to do across the board -- across our entire portfolio, is build coveted assets. And -- and we certainly think this is one of them.
Derrick Whitfield -- Stifel, Nicolaus & Company -- Analyst
Thanks Tommy and Taylor. That's very helpful, guys.
Tommy Nusz -- Director and Chief Executive Officer
You bet.
Operator
Our next question comes from Michael Hall with Heikkinen Energy Advisors. Please go ahead.
Michael Hall -- Heikkinen Energy Advisors -- Analyst
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 -- sounds like a little bit of an incremental backlog from a completion standpoint, how big of -- what -- 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 -- that would improve capital efficiency in 2020?
Taylor Reid -- Director, President, and Chief Operating Officer
Michael, it -- you know, it's really probably a little bit of both. You know, if we've been talking about the DUC backlog when we're drilling, you know, up to this point, we're really doing kind of 1 to 3 well pad. And having, you know, a single digit DUC backlog was natural with that -- with the increased cycle times that we've talked about keeping two rigs going. Now you're likely to build the low to -- might be the low to mid teens next year. And so it does two things, one, is we're on a 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 DUC backlog -- if you're going to drill eight wells before you frac them and then follow it with another one, so, you just need a little bit more of a pad. But there is some additional build up here that gives us the flexibility next year, depending on how things are going to -- to draw that down a bit. And so we'll -- you know, as we get into 2020, we'll be looking at all those options. You know what's -- what's that right level? Whether you pull it down a bit more from a capital efficiency standpoint like you talked about?
Michael Hall -- Heikkinen Energy Advisors -- Analyst
Okay. And can you remind me what kind of required activity levels look like from a lease capture standpoint in the Delaware in 2020?
Taylor Reid -- Director, President, and Chief Operating Officer
Yeah. It's been -- it's kind of one and a half. It depends on cadence, kind of one and a half rig to meet our land holding requirement. And most of that is talked about -- about 70% of that is on -- of our land is on the Delaware. We've got a great agreement there that allows us to -- we can -- we can drill in development mode and it holds the pool of acres. So we don't have to be jumping all around and it really helps from an efficiency standpoint.
Michael Hall -- Heikkinen Energy Advisors -- Analyst
Okay, that's helpful. 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 base and 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, the potential tailwind in the back half of the year?
Michael H. Lou -- Chief Financial Officer and Executive Vice President
Yeah. Really, at this point, we've kind of factored in the cost that we -- you know, the $7 million, $6 million range that we're talking about, Michael, and so that could provide a bit of a tailwind depending on how well we do.
Michael Hall -- Heikkinen Energy Advisors -- Analyst
Okay, I appreciate the time, guys. Thank you
Michael H. Lou -- Chief Financial Officer and Executive Vice President
Alright, Michael.
Operator
Our next question comes from Ron Mills with Johnson Rice. Please go ahead.
Ron Mills -- Johnson Rice -- Analyst
Morning guys, quick question following the Delaware. You talked a little bit maybe about the spacing test you did. I know it just came on in July. What kind of spacing was -- 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 second spacing test designed to test not just the upper and lower A, but -- but also the the B and C on the same path?
Michael H. Lou -- Chief Financial Officer and Executive Vice President
Yeah, Ron. Good question. The first test, the 3 well test, it was all in Wolfcamp A and so we -- we actually had two lower Wolfcamp A wells and one upper Wolfcamp A well. The spacing, the two lower wells were 800 feet apart and then the -- the upper well was right smack in between them. It was about 200 feet above them so it's, you know, 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 the lower Wolfcamp wells. And in terms of the -- the eight well test that’s coming up, it's going to be a combination of 3rd Bone Spring stand and Wolfcamp A test that will have four wells in the 3rd Bone Spring and then four wells in the lower Wolfcamp A. So, at this point, it's not -- we're looking at that going forward. We don't have B and C incorporated into the multi world test. But as we talked about, we've got a number of really attractive B and C test that we're excited about. So we're looking at incorporating more of the columns as we go down the road.
Ron Mills -- Johnson Rice -- Analyst
Okay, great. And then, Michael, just for you on the -- on the Slide 7 chart. I know the new presentation updates for the -- for the new capex, you still have kind of an EBITDA number based on-- on $50 oil prices. So you're -- 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 million or $30 million delta as shown on the far right? I just want to try to make sure I understand. You do have an associated EBITDA benefit from the higher prices, even though it does impact spending.
Michael H. Lou -- Chief Financial Officer and Executive Vice President
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 -- the less deflation case kind of in there.
And the way to think about the difference is, with hedges and all that impact is that difference in the free cash flow line kind of midpoint of $85 million to the midpoint of $115 million. So that $30 million number you're referencing is kind of the differential between those scenarios.
Ron Mills -- Johnson Rice -- Analyst
Great. Thank you, guys.
Tommy Nusz -- Director and Chief Executive Officer
Thanks, Ron.
Operator
Our next question comes from Brad Heffern with RBC Capital Markets. Please go ahead.
Brad Heffern -- RBC Capital Market -- Analyst
Hey, good morning, everyone. Just looking at the new guide and what the 3Q guides -- 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 million in capex. I was just wondering if -- if those two things are related and what it says about the momentum into 2020.
Tommy Nusz -- Director and Chief Executive Officer
So, when you – when you look at the production, like you said it is, if it is going to taper down a little bit in the fourth quarter, and it's really a -- it's just really everything coming together and, you know, 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 -- as we look in to 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 -- from a PDP standpoint, as we continue to look at our volumes, one of the things we talked about in the past and then factored in a bit here is, we've talked about spacing. And if you look at our pre ‘19 wells -- and this is really focused in Wild Basin, it tended to be a little tighter when we drilled the very first wells there. We're in kind of 13 to 14 well per spacing unit range and we've walked that down over time. Everything ‘19 forward is -- and really going back into parts of ‘18 we got – ‘18 we really made this shift. But everything going forward is 10 to11 wells spacing. And we think we're spaced about right at this point, you know, 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 -- all that stuff kind of plays into -- 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 are capital. When you -- 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 -- you know, people aren’t thinking, hey, is this going to be evenly split between the quarters? Because we'll probably get -- we'll get a few more wells fracked in 3Q than 4Q and then we'll -- you know, we'll work on when we bring those on.
Brad Heffern -- RBC Capital Market -- Analyst
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, you know, approximately like what Wild Basin looks like on a production mix or was it more gas weighted?
Michael H. Lou -- Chief Financial Officer and Executive Vice President
That number, it 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 in that too with the oil side, but more of that's going to be on -- on the gas side in terms of the way we thought about that.
Brad Heffern -- RBC Capital Market -- Analyst
Okay, thanks.
Michael H. Lou -- Chief Financial Officer and Executive Vice President
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 numbers, is that your production number is back up and part of that is the plant running very efficiently now.
Operator
Our next question comes from Daniel Pickering with TPH Asset Management. Please go ahead.
Daniel Pickering -- TPH Asset Management -- Analyst
Morning, guys.
Michael H. Lou -- Chief Financial Officer and Executive Vice President
Hey, Dan.
Daniel Pickering -- TPH Asset Management -- Analyst
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 '20 versus '19 roughly?
Taylor Reid -- Director, President, and Chief Operating Officer
So, you know, I think to start with – to probably talk about is just what – and Michael can add to this -- but what the capital program is going to look like, we think, going forward. And it's--it's probably flat to slightly down from -- from this year and for 2020. And in fact it -- it -- it's probably pretty close to what's out there from a guidance perspective at this point. And then Michael can add to that on the volume side.
Michael H. Lou -- Chief Financial Officer and Executive Vice President
Yeah, so -- so Dan, I think that you'll see kind of for 2019 guidance that consolidated numbers is right around 850 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 what, I think, Tommy talked about in his comments, fourth quarter oil volumes, we should be in a position to -- 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 now.
Daniel Pickering -- TPH Asset Management -- Analyst
Thanks. And then I guess conceptually I'm looking at a stock market that doesn't, you know, 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, you know, 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 there isn't, you know, if it isn't time for something a little more aggressive and how you guys think about, you know, a clearly undervalued equity and the levers that you can pull, whether it's capital spending, OMP monetization, you know, something isn't working now. What changes going forward?
Tommy Nusz -- Director and Chief Executive Officer
Yeah, Dan, I think that, you know, the good news in there is that whether you look at what we have in the Williston, what we have in the Delaware, or 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 --it kind of -- there's a focus on Wild Basin, but it also on the waterside touches our entire footprint in the Williston. But -- but ultimately, we do feel like there's a coveted asset there, that whether it's our coveted asset or somebody else's, I mean we -- coveted assets provide a lot optionality. And so I -- 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. It is probably the easiest way to say that, if that makes sense.
Daniel Pickering -- TPH Asset Management -- Analyst
Yeah. I mean, I guess I understand it. 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 is -- 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?
Tommy Nusz -- Director and Chief Executive Officer
Yeah, I think as we've talked about in the past, Dan, it's in today's world, well, 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 -- 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 -- in this market, which -- and I don't think that's going to change anytime soon. Michael, you have anything to add to that?
Michael H. Lou -- Chief Financial Officer and Executive Vice President
No, I think that's exactly right. So prioritization is paying down debt, first and foremost, Dan.
Daniel Pickering -- TPH Asset Management -- Analyst
Okay. Thank you.
Michael H. Lou -- Chief Financial Officer and Executive Vice President
Thanks, Dan.
Operator
Our next question comes from David Deckelbaum with Cowen. Please go ahead.
David Deckelbaum -- Cowen -- Analyst
Morning. Tommy, Michael and Taylor, 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 cord going into Algiers, 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 toward or do you see these as opportunities to delineate some areas like Foreman Butte that you would have looked to sell over time?
Tommy Nusz -- Director and Chief Executive Officer
So. Really, probably some of both. And, you know, when you look --you look back at -- you remember after we did the Forge deal, we went through a divestiture process, sold about $360 million in assets. And we originally talked about, you know, looking at something around $500 million 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 the 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 -- it by our testing and third party testing both, it’s doing two things.
One, it’s pulled more of this inventory into -- into the core and was 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 queue. And so we're excited about having more of those tests push 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. It's stuff that's the tail in our inventory and helps us to get our debt down, our leverage down as we just talked about and those are things that we'll be looking at. But some of both.
David Deckelbaum -- Cowen -- Analyst
I appreciate that. I guess we haven't seen a ton of Bakken transactions outside but I guess some stuff in the first quarter. I guess for obvious reasons, especially in the public arena. I guess, have you seen any interests on -- I guess like has the make -- 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 of seeing like the same players that would be out there?
Michael H. Lou -- Chief Financial Officer and Executive Vice President
Yeah. Obviously, as you mentioned, David. The -- the A&D market is extremely challenged, especially if you think about public company buyers with the capital markets where they are is really seeing that A&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 -- more recent deals.
David Deckelbaum -- Cowen -- Analyst
Thank you, guys. Best of luck with everything. Appreciate the time.
Tommy Nusz -- Director and Chief Executive Officer
Thanks, Dave.
Operator
Our next question comes from Noel Parks with Cooker and Palmer. Please go ahead.
Noel Parks -- Coker and Palmer -- Analyst
Good morning.
Tommy Nusz -- Director and Chief Executive Officer
Hi, Noel.
Noel Parks -- Coker and Palmer -- Analyst
[Indecipherable] you touched on this already, but, could you just talk a little bit more about the nature of the downtime at Wild Basin? You know, what kind of a precipitating event it was and whether it's something in hindsight was foreseeable or more of a random thing?
Michael H. Lou -- Chief Financial Officer and Executive Vice President
Yeah, 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 -- we saw a couple of years back a huge need for gas processing capacity in the basin. We move 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 -- with our plant in place, 2.2 Bcf of processing capacity. So that all played out really well. The other nice thing for us is that, you know, 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, something of that's just kind of what I would call some of that start-up phase of knocking out the kinks. And it did -- it did impact -- impact us because of our concentration kind of in Wild Basin to that plant. But, kind of broader speaking, getting that gas plant up online on time in December was -- was just a huge feat for the team and what I'd call this is just some of that initial start up that that we got kind of 6 months into it and now we're through it and we think we're past it.
Tommy Nusz -- Director and Chief Executive Officer
Yeah, 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, you know, whether it's 3 months or 6 months trying to get these things lined out and operating correctly and efficiently and that’s not -- not a wild surprise. You’d like -- you'd rather not have that but it's not a wild surprise.
Noel Parks -- Coker and Palmer -- Analyst
And just actually -- do -- tell us what the -- how long the plant was down, how many days?
Tommy Nusz -- Director and Chief Executive Officer
It was about 20 days, plus or minus. So something like -- [Speech Overlap] -- a few weeks, ballpark. Yes.
Noel Parks -- Coker and Palmer -- Analyst
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 that window might be closing. I was just curious that around your acreage, do you have a sense of any urgency about that among your partners and competitors or -- or just with oil having been a little weaker lately, is there not so much of a press going on anymore?
Tommy Nusz -- Director and Chief Executive Officer
Yeah. We've focused since we got the assets, you know, 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 two mile laterals, that was already a high number. It's got -- you know, kind of 75%, 80% of the acreage and we're moving that -- continue to move that up and then consolidating in and around the acreage. We've been successful. So we've seen, you know, 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 -- for their position. That -- 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.
Noel Parks -- Coker and Palmer -- Analyst
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?
Tommy Nusz -- Director and Chief Executive Officer
Yeah. Noel, look -- it's actually, if anything, you know, kind of that trade activity in bolt-on is, if anything, maybe picked up a bit, is everybody starts to optimize their capital spend and focus on their operated projects, especially with lease terms in the -- in the Delaware that you're very familiar with. It's very -- very different than the Williston Basin, for instance, with different clauses that you have in these leases. So as -- 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, it's-- doing trade is never easy, but at least, you know, 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 [Phonetic] where we didn't have it before. But it does tend to get people focused on it.
Noel Parks -- Coker and Palmer -- Analyst
Great. Thanks a lot.
Tommy Nusz -- Director and Chief Executive Officer
You bet.
Operator
This concludes our question and answer session. I would now like to turn the conference back over to Tommy Nusz for any closing remarks.
Tommy Nusz -- Director and Chief Executive Officer
Thanks. In closing, the 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.
Operator
[Operator Closing Remarks]
Duration: 54 minutes
Call participants:
Michael H. Lou -- Chief Financial Officer and Executive Vice President
Tommy Nusz -- Director and Chief Executive Officer
Taylor Reid -- Director, President, and Chief Operating Officer
Derrick Whitfield -- Stifel, Nicolaus & Company -- Analyst
Michael Hall -- Heikkinen Energy Advisors -- Analyst
Ron Mills -- Johnson Rice -- Analyst
Brad Heffern -- RBC Capital Market -- Analyst
Daniel Pickering -- TPH Asset Management -- Analyst
David Deckelbaum -- Cowen -- Analyst
Noel Parks -- Coker and Palmer -- Analyst
