Chord Energy Corporation (CHRD) Q4 2019 Earnings Report, Transcript and Summary

Good morning. My name is Jason and I will be your conference operator today. At this time, I'd like to welcome everyone to the Fourth Quarter 2019 Earnings Release and Operations Update for Oasis Petroleum. All participants will be in listen-only mode. [Operator Instructions] After today's presentation, there will be an opportunity to ask questions. [Operator Instructions] Please note this event is being recorded. I will now turn the call over to Michael Lou, Oasis Petroleum's CFO to begin the conference. Thank you. You may begin the conference.

Thank you, Jason. Good morning, everyone. Today, we are reporting our fourth quarter 2019 financial and operational results. We're delighted to have you on our call. I'm joined today by Tommy Nusz and Taylor Reid as well as other members of the team. Please be advised that our remarks on both Oasis Petroleum and Oasis Midstream Partners including the answers to your questions include statements that we believe to be forward-looking statements within the meaning of the Private Securities Litigation Reform Act. These forward-looking statements are subject to risks and uncertainties that could cause actual results to be materially different from those currently disclosed in our earnings releases and conference calls. Those risks include among others matters that we have described in our earnings releases as well as in our filings with the Securities and Exchange Commission including our annual report on Form 10-K and our quarterly reports on Form 10-Q. We disclaim any obligation to update these forward-looking statements. During this conference call we will make references to non-GAAP measures and reconciliations to the applicable GAAP measures can be found in our earnings releases and on our websites. We will also reference our current investor presentation, which you can find on our website. With that I'll turn the call over to Tommy.

Thanks, Michael. Good morning and thanks for joining our call. The Oasis team delivered another strong quarter exceeding our production guidance and spent well below both internal and external CapEx projections. We generated substantial E&P free cash flow in the fourth quarter allowing us to pay down a significant amount of debt. In 2019 Oasis paid down $188 million of E&P debt with the Oasis credit facility exiting 2019 with only $337 million drawn. Taylor will get into more operational detail in a minute, but I want to highlight a few key points about our performance and our strategy. First, in the Williston. This cornerstone asset continues to generate strong free cash flow driven by well productivity, a high oil mix and access to Gulf Coast pricing. The team had a strong fourth quarter as we were able to power through some difficult weather and get our wells online, while preserving the cost reductions seen in the third quarter. This remarkable asset is expected to generate significant free cash flow in 2020. Second, in the Delaware. It's been about two years since we closed the Forge acquisition and we're really excited to enter full field development in 2020, which will drive repeatable capital-efficient growth. Drilling times and well costs have come down significantly, which should drive capital-efficient development plan this year and beyond. Our measured development pace with the asset has allowed us to secure quality service support at attractive prices; gain clarity and availability to takeaway capacity; and significantly advance our subsurface knowledge including parent-child relationships; as well as configure blocks for 1,280-acre development preparing us to optimize capital efficiency going forward. Additionally, the team has done a fabulous job securing complementary small bolt-on acreage acquisitions adding about 1,800 net acres in 2019 which increases our footprint to 25,000 net acres increases our working interest and provides for optimizing longer laterals. Third, our midstream assets provide a differential advantage to Oasis. During the fourth quarter, we captured 97% of our gas in Wild Basin compared to an industry average of 83% and well above the state requirements of 88%. OMP EBITDA is up 3.7 times since we IPO-ed in 2017 and Oasis Midstream Partners has been one of the better-performing partnerships in a difficult market. We continue to look at ways to enhance the value of our ownership in these assets. On a related topic while not connected to Oasis-owned infrastructure on the gas side in the Permian, our gas capture in the Permian is exceptional as well and averaged over 98% in the fourth quarter. Fourth, we've taken steps over the last eight months to continue to optimize our G&A cost structure matching it with our anticipated activity levels and businesses. Additionally, in January we announced changes to executive compensation, which include reductions in annual cash and LTI payments benchmarking to broader market performance and updating our corporate scorecard metrics to emphasize returns. These changes to the scorecard focus on cash flow and cash margin, corporate returns and capital efficiency, strategic initiatives and an environmental and safety modifier. We believe that all of these changes in aggregate will further align the Oasis management team with shareholders and the new plan puts us in a unique position amongst our E&P peers. Oil price volatility has been unprecedented, but we've built our business to succeed through the cycles and continue to maintain an active hedging program to manage our business risk and cash flows. Our core 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. Oasis took action in 2019 to significantly reduce costs in both the field and corporate level. The result has been significantly improved operational and financial performance. I'm proud of the team and the accomplishments they've made over a short period, which enhanced the 2020 outlook and beyond. Turning to the 2020 program. We continue to expect to run four rigs throughout the year, with two in Williston and two in the Delaware. The program is expected to deliver significant free cash flow from Williston, which will fund growth in the Delaware and pay off debt at a corporate level. In the Williston, we are focused on improving returns and harvesting free cash flow from this cornerstone asset. We expect to complete approximately 45 to 55 wells in 2020. As we spoke about last quarter, the Oasis team made significant strides in lowering well cost through a combination of design changes and improved cycle times, while working with our core service providers. We will continue to look for ways to further lower cost while maintaining well performance. Our program will be focused in the Wild Basin and Indian Hills areas will include two step-out tests with 3-mile laterals in the South Cottonwood area. In the Delaware, we have effectively moved to development, with most of our activity focused on the drilling and completion of spacing units, with a focus on the Bone Springs and Wolfcamp A. In 2019, we made significant progress lowering cycle times and delineating productive zones throughout the column. Our last 2-mile lateral wells were drilled in the 25-day range and we expect to make further improvements as the year progresses. We are currently targeting well cost of $8.6 million for a four-well pad, which compares to approximately $11.5 million in 2018 and $9.5 million in 2019. The cost reductions reflect improvements in well design, a shift to pad drilling and optimization efforts with our service providers. We continue to expect approximately 20 to 25 completions in the Delaware for the year. As our guidance indicates, first quarter production is expected to decline a bit from strong Q4 levels, reflecting reduced activity in Q4 and early Q1, along with downtime related to bitter cold. At the end of 2019, we throttled back activity and as a result we completed just 13 wells in Q4, 2019, just 60% of our total 2019 completion activity. In addition, our Q1 activity is heavily back-loaded to March, as we picked up frac crews in January and February. For perspective, about 60% to 70% of the Q1 completions will be brought online in March. The sharp drop in activity combined with cold winter conditions should bring in Q1 volumes between 78,000 and 79,000 barrels of oil equivalent per day. With the back-loaded Q1 activity, second quarter volume should increase materially and continue to grow over the course of the year. We expect fourth quarter 2020 oil volumes to increase mid-single digits over fourth quarter 2019 volumes. We have also placed an increased emphasis on capital efficiency in both basins. With the combination of lower well cost, widened spacing and completions optimized for lower well density, we have seen material shifts in per-well results, as exhibited on page seven of our presentation for the Williston. We're using similar approaches in the Delaware. To close, we ended 2019 on a positive note and continue to challenge ourselves to do even more. Capital efficiency of our 2020 program benefits from an efficient and predictable Williston program, combined with the benefits of moving the Delaware to full field development. The team is motivated and excited about delivering on our plan in 2020 and beyond. With that, I'll now turn the call over to Michael.

Thanks Taylor. The Oasis operations team executed well in the back half of 2019 and is set to deliver in 2020. Improved well costs lower operating and corporate costs and peer-leading differentials drove significant free cash flow, which continued to lower our debt balances. In light of recent commodity price weakness, to conserve capital we've trimmed 2020 activity a bit. However, we still expect fourth quarter 2020 oil volumes to be up mid-single digits from our fourth quarter 2019 average. This guidance supports our plan of repeatable modest growth, free cash flow generation and debt reduction. To accomplish this plan, we expect $685 million to $715 million in consolidated spending, which is down approximately 13% from when we first began discussing 2020. We have not assumed any further efficiencies or service cost reductions beyond what we had at year-end 2019. The team made tremendous progress in 2019, rightsizing the organization for our current activity levels and continuing to evolve executive compensation to further align management with the shareholder. Excluding the non-cash legal-related accrual, our full year 2019 G&A was down approximately 10% versus original guidance, and we currently expect 2020 G&A to be down further as highlighted in our press release. Oasis continues to do a good job managing LOE and minimizing downtime. LOE averaged $6.95 per BOE for the full year 2019, 7% below original guidance. As we look to 2020, we're currently expecting $7 to $7.75 per BOE. The 2020 guidance reflects an expected increase in spending for artificial lift. We've been able to beat expectations in the past couple of years on LOE and challenge the team to continue their progress. Oil differentials averaged $3.23 per barrel off WTI in the fourth quarter. While slightly wider than the previous several quarters, fourth quarter pricing largely reflects a narrowing of Brent-WTI. Typically most Bakken barrels are clearing to the coast. From that standpoint, differentials versus Brent haven't changed much, but as Brent and WTI narrows, the Bakken discount to WTI increases. Residual gas and NGL pricing was volatile in the fourth quarter, and on a two-stream basis we realized a 15% premium to Henry Hub. As we look to the first quarter, both gas and NGL prices have weakened a bit and our guidance implies a little lower realization. As Tommy discussed, we generated significant E&P free cash flow during 2019, which helped Oasis repay $188 million of E&P debt, including total principal of senior unsecured notes and the Oasis credit facility. We're further securing our future free cash flow generation with 85% to 90% of first half 2020 oil production hedged at a weighted average floor price of about $55.50 a barrel. For full year 2020, oil production is approximately 70% to 80% hedged at a weighted average floor price above $54 per barrel. Details can be found in the appendix of our investor presentation. Turning to midstream, in the fourth quarter Oasis executed final agreements for the dedication of certain Delaware acreage to OMP via the Panther DevCo. Total midstream CapEx is expected to be $110 million to $120 million in 2020, a reduction of 46% year-over-year, which reflects a reduction in spending related to infrastructure for both Oasis and third parties. Net CapEx to Oasis attributable to its retained interest is expected to range between $42 million and $45 million. We'll be talking in more detail on the OMP call shortly, and I would also direct you to our OMP press release and presentation for more color on our continued success on the midstream front. So to sum things up, continued progress on capital efficiencies and cost structure put Oasis in a position to grow year-over-year while being free cash flow-positive on both an E&P and consolidated basis in 2020, which we will continue to use to repay debt. With that, I'll hand the call back over to Jason for questions.

Thank you. We will now begin the question-and-answer session. [Operator Instructions] The first question comes from Derrick Whitfield from Stifel. Please go ahead.

Thanks. Good morning all. Congrats on a strong year-end update.

Thanks, Derrick.

Perhaps for Tommy or Michael, the midstream business has certainly been a positive asset for you to own from an upstream perspective over the last few years, wanted to ask if you could comment on any progress over the last quarter in your evaluation and the strategic direction for the midstream business.

Yeah. Derrick, I don't know that we've got anything incremental to add to what we've been talking about historically. It's -- our midstream business is -- obviously has been a strategic strength for us. It's a coveted asset whether in whole or in part, in our hands or somebody else's hands. We view it as a coveted asset, which is what we try to build here. And so, we obviously continue to focus, as we mentioned, on ways to get cash back to the parent from the midstream. At any point that we can discuss that in more detail we will.

Thanks, Tommy. And as my follow-up perhaps for Taylor. Referencing page 7, could you speak to what degree of your 2019 activity reflected less than 10 wells per DSU density at Wild Basin? Or similarly with the tighter cluster is it more fluid generally? And with that question, what I'm trying to understand or get a sense of is the amount of incremental productivity gains you could see in 2020.

Yeah. So in 2019, the Wild Basin at the kind of a 10-well spacing most of the program is -- I guess, maybe when the completions were brought online were probably a little more midyear. And then as you get into -- so we started drilling them, but the lag between drilling and bringing those completions on is more midyear-ish. It's not exact. We can get back with you on that. But 2020 is -- will reflect all 10-well spacing and then we're even testing some that are a little wider than that.

So it sounds like, Taylor there's going to be a little bit of a productivity gain 2020 over 2019 with the planned program? Is that fair?

Yeah. We would expect and as we move forward going from 2019 to 2020 that per-well results would increment up.

That’s helpful. Thanks for your detailed response.

The next question comes from Michael Hall from Heikkinen. Please go ahead.

Thanks. Maybe coming at a similar question from a slightly different angle. The 2020 productivity uplift that seems to be implied by the guide, how much of that is driven by regional mix shift in the Williston as opposed to these changes in completion design? I think you said in the prepared remarks that basically all the activity will be focused in Indian Hills and Wild Basin. Can you just remind me, I guess how much higher like six-month canes [ph] are in that asset relative to the rest of the portfolio or relative to the 2019 average maybe even better?

So you can -- so I'll talk a little bit about the mix and then also about canes. But the mix in 2019, you had Wild Basin and then you had some Red Bank and North Alger. And then for 2020, you're going to have Wild Basin, Indian Hills and a bit of Red Bank. The Wild Basin weighting is 50% to 60% of the completions for 2020. So the mix is a little different. I wouldn't say it's -- overall it's crazy different. We had fewer wells in 2019. I think -- rather than thinking about Williston, it would be Williston and Permian. So the weighting in Williston was higher in 2019. In 2020, you're going to have 50 -- about 50 wells in Wild Basin and then another 20 to 25 wells in the Permian, whereas, you had 11 Permian wells last year and the Williston count was 67. So that's a bit of a different mix. In terms of the results just within Williston, Michael if you look on page 6 of the presentation, you can see and you can just tick off the graph for the different areas what their performance has been like for the areas that we're talking about. So you get Wild Basin, Indian Hills, Painted Woods, North Alger and Red Bank on the graph in the upper right-hand corner.

And I guess each of those would have a little bit of an uptick with wider spacing. I'm assuming those are all -- spacing?

Yeah. In fact, generally we've moved to a little wider spacing, testing a little wider spacing in all these areas.

Okay. And would you care to provide -- or do you have an estimate of what maybe an average six-month oil can would look like in the Delaware program as it relates to your current expectation?

So the Delaware program as we've talked about is going to be focused in Wolfcamp A and the Bone Springs. And I don't have it right here in front of me, Michael. So we're going to have to -- let's circle back and give you numbers. But in terms of the economics, it's very competitive with Wild Basin for example.

Certainly. Okay, I appreciate that. I’m sorry going in the weeds there. And then last one on my end was just -- I just want to make sure, I'm thinking about Williston well costs right. It seemed like in the deck they were pointing -- you're pointing to $7.8 million. I feel like last year we were a little below that in the back half of the year. Am I correct with that? And what's changed, I guess on the well cost front?

Yeah. So what's going on there is the -- we talked about getting the $7.2 million, which we have done as a year-end target. That was for a six million pound average job that we were doing last year. And if you remember we're kind of -- we've generally gone to 10 million pound Bakken wells, 4 million pound, 3 million, 4 million, 12 million in Wild Basin, for example. So our overall average mix was around 6 million pounds. And that's what the $7.2 million was. As we've been talking about this, we widened spacing a bit. It's allowed us to increase the size of the jobs. And get better per-well results. And so those bigger jobs that we're pumping on average just have a little higher cost. So that's the $7.8 million.

Okay. That's helpful. Great, thanks guys. I appreciate it.

Thank you.

Thanks, Michael.

The next question comes from Brian Downey from Citigroup. Please go ahead.

Good morning and thanks for taking my questions. Maybe a follow-up on that one, as you noted on slide 9 of the deck, the expectations for capital spending for 2020, have taken a few steps down, even compared to last month's update. I was hoping you could dimension, maybe the different buckets of how the reduction in E&P CapEx was derived. It sounds like there are some moving parts on, well design efficiencies. And then, how much of it was service pricing assumptions based on, what you saw in 4Q, and any changes in absolute activity or working interest, driving that decline now?

And as you know, it's just, as we continue to work through, the quarter and the projections. And got a more accurate read on what activity levels are. And then, overall well cost and where we wanted to be from, equity and production standpoint, thinking about the free cash flow mix. We're able to pull it down another, $15 million. So, we feel good about, how that plays towards preserving free cash flow, in this environment of volatile pricing that we're experiencing, just being able to deliver on, our program, but do it from a kind of conservative stance.

Got it, makes sense. And then, maybe a separate question, in the Delaware, you've had at least two or three other operators with adjacent, acreage positions to your Delaware position involved in recent industry transactions. I'm curious that, if you've seen that dynamic change anything, maybe increasing or decreasing acreage bolt-on potential to your dollar position there?

Yeah. There have obviously been a number of transactions. And I think, it reflects the -- really the quality of the acreage, in the area which we're -- we continue to be very excited about. One of the things that we have seen is, the opportunity to continue to, get some deals done. And these aren't super big. But they're very attractive bolt-on opportunities that have allowed us to further core up the block. And really give us a number of contiguous DSUs, where we can go into full field development, as we've been talking about. So I'd say, the opportunities, we continue to have some things to focus on. So it really hasn't taken away, we don't think from our opportunities going forward. And we'll continue to try to do just what we did last quarter, which was find attractive bolt-on that will allow us to just core up the position further.

Great, I appreciate the commentary. Thank you.

The next question comes from Brad Heffern from RBC Capital Markets. Please go ahead.

Hey good morning everyone. I guess, talking about the 2020 plan, obviously, you've flexed it lower a couple of times already. But you've talked in the prepared comments about the strategy being repeatable modest growth. I'm just curious, at what point you think about transitioning the company to just a pure maintenance CapEx, sort of level? Or maybe, I guess alternatively, what does the current activity level give you in terms of efficiency that maybe a lower CapEx program wouldn't?

Yeah. So, the way the program is setup, we've got pretty level-loaded activity. And it's very efficient. The Williston has the two rigs, really one frac crew running for the year. And two rigs and frac crew is going to come off and on in the Delaware. But a steady two rigs. We're pretty well insulated from an unhedged position. Michael talked about in his comments. We've got about 70% of our volumes, at a $54 or better price for the year. And we got even more net hedge in the first half. So, we've got the ability to we think, work through this pricing and continue to generate free cash flow, which we think, we can do at a $50 deck. Now prices continue to be volatile. We'll monitor. And if at some point, we think it makes sense to adjust. We've got the ability to do that. I don't know that we're going to be faced with it. But we're certainly going to be mindful, as we go through the year.

Okay. Thanks a lot. And then, I assume, there'll probably be more data or more input when the K comes out. But I was wondering, if you had any update on the Mirada legal proceeding?

Yeah. Like we've said in the past, with Mirada, it's a case that, at the end of the day we think is, really without merit. But we are going to vigorously defend ourselves in the case. And if you look in our disclosures just to give you an indication of how we think about the thing we do to disclose a reserve of $20 million. Now that's for all of our litigation but it will give you an idea kind of maybe the range of what could happen with the case. And as we get through the actual trial later this year we'll give more updates.

Okay. Thank you.

The next question comes from Kashy Harrison from Simmons Energy. Please go ahead.

Good morning and thank you for taking my questions. So my first one's around midstream. I was just wondering if you could help us frame up what the gross EBITDA for that asset is today. What would be the maintenance CapEx associated with that gross EBITDA? How long can you hold that EBITDA flat based on inventory in the general area? And then how we should think about abandonment costs after the EBITDA inevitably starts to decline?

Yes. I mean, we can talk generally around midstream. Obviously, there's going to be a lot more talk on our midstream call in about an hour. But overall, we've been able to continue to grow this asset on the midstream side. I think Taylor mentioned in his comments some of that midstream growth or Tommy did. But if you look at this past 2018 over 2019 revenues grew by I think 50%. A large part of that is continuing to grow. The system get more and more on and we talked about 80% utilization in the midstream asset on the Wild Basin system and so – on the gas system. So you still have room to continue to grow third-party on that asset. You still have room in that asset to continue to grow. We're building third parties. We went from very little third-party to by the end of the year being 25% to 30% on a third party – with third party. We'll continue to grow that business. We think we can continue to grow EBITDA and volumes across all of our systems, whether it's water, gas or oil for years to come. I don't have a number for any kind of abandonment. That's going to be a long time in the future so we've not talked about that.

Okay. That's helpful. And maybe another question maybe this one for Tommy. I believe in the past you highlighted a desire to get to about 100,000 net acres in the Delaware. Just given all that's changed over the last few year’s capital markets whatnot, it seems like getting an additional 75 would be quite challenging. And so I was just wondering on a risk-adjusted basis, is there a case to be made that switching the focus back to the Williston and maybe partnering with some of these private equity-backed players could represent a more attractive position for the company over the longer term?

Yes. Look we – what I've talked about in the past is generally what it would take to have a position in the Delaware that from a size and scale standpoint would be equivalent to the Williston. And because of the way the pays are stacked, it was on an equivalent basis about a third of what we have in the Williston. So that's where I came up with those numbers. I think for us it's – and this isn't any different than what we've always done is once we have an anchor we continually look for opportunities to bolt-on in and around our core positions to build scale. And you just don't know where those things are going to come from and when. Fortunately the team has done a great job on very much smaller things bolting on in and around our position in the Delaware. And we continue to do similar type things in the Williston, where we can, although for those smaller-type things like we've done in the Delaware you don't see that much in the Williston. I do think you'll see – I mean, I think you're going to see more consolidation over the next 12 months whether it be on the corporate side or the private equity side. And we'll just have to be mindful of what opportunity presents itself to us and when and what the financing options are associated with it.

Okay. That's good color. Appreciate that. And if I could just sneak one last one in maybe for Taylor. I think on Page 22 of the presentation, you highlight that you're testing a three-mile lateral in South Cottonwood. I think Exxon, maybe has seen some decent results with 15,000 laterals. But I was just wondering if you could help us frame up what you hope to achieve with this test. How we should think about the potential benefits with a three mile lateral program in theory. And then maybe what the potential drawbacks could be with also three mile laterals?

You bet. So, we're really just looking at the levers we can pull to improve economics in the wells. And especially as we're some of these areas like South Cottonwood are a little further out of what was the old traditional core. We've seen -- and if you look at the footprint we expanded what we call Tier one just based on higher-intensity completions and the impact that that's had on productivity of the wells and the economics. Going to the three-mile lateral just adding another 5,000 foot to that lateral for the same drilling cost we think is another way to improve the capital efficiency and to further improve the economics. We've drilled a number of 2.5-mile laterals and have seen pretty much corresponding increase in production on a ratio basis by adding an extra 2,500 feet. So we think going to a three-mile lateral what we'd like to see is that just again a corresponding increase relative to what that first 10,000 feet will deliver to you. There's -- in addition to us doing these you talked about Exxon, there's been a number of other guys that have drilled some of these. Slawson has drilled a number to the south. Liberty in this area has drilled a number of 3-mile lateral wells. And so, we're also looking at those results and trying to get an idea of what the impact is going to be. So, it's just another lever in addition to all the work on high-intensity completions and cluster spacing and sand loadings and all those other things that we think will help us to improve the economics.

Appreciate it. Thank you.

The next question comes from David Deckelbaum from Cowen. Please go ahead.

Hey Tommy, Taylor, Michael, thanks for the time. A fairly simple one but I know you guys talked about the year-over-year growth of mid-single digits 4Q 2019 to 4Q '20 at the corporate level. Could you break that out between the two asset areas?

So a good -- I think a good way to think about it without getting too specific is that the Williston is staying relatively flat and growth is coming in the – more of the growth is occurring in the Permian.

Yes. I just wanted to properly understand that this is a Williston maintenance program where it is now and that the growth is coming from Delaware.

Yes. The Williston is more or less -- it's maintenance on production and as we have been talking about it, it allows us to grow free cash to take the free cash flow off the Williston reinvest it in the Permian until we can get the Permian to a production level that it'll start cash flowing as well.

Thanks, Taylor.

Just my follow-up to that is, with the two rigs you talked about some of the adjustments you made to shave off about 5% to the E&P budget from the last guide. I guess you guys are benefiting from the hedges in the first half of the year in particular. If this is a more prolonged bear market on the crude side, how do you think about the '21 progression? Is this 2-2 split the most capital efficient that you think for this program on a sustainable basis in terms of maximizing free cash? Or does that change quite a bit going into '21 as the Delaware gets a bit larger?

Yes. Right now we're kind of thinking about it as a fairly steady-state program in both the areas. But we are absolutely going to continue to relook at the results as the year goes on. And having the two positions, as we've talked about in the past, we think is advantageous because, it allows you to reallocate capital. You could be on a number of fronts, whether it's a dip blowout like we saw in the Permian a year ago or you could have service constraints in an area or its productivity or economics in one or other of the areas allows you to reallocate that capital. But right now, as we're looking at this early in the year,. it's still kind of a steady-state program.

David, keep in mind, I mean you've seen how we've acted in the past and you look at our hedges in the first half and we've started layering on even out into '21. And so, we'll continue to look for opportunities where we have a chance to hedge into '21 to protect we'll do that. And as you know we've always kind of done that.

Thanks Tommy and Taylor.

You bet.

The next question comes from William Thompson from Barclays. Please go ahead.

Hey good morning. Good afternoon, I guess. On Slide 12 just because I often get confused easily, I just want to make sure we're talking apples-to-apples. You show less than $40 million of free cash flow at the midpoint at $55 oil. Based on the 2020 guidance my math suggests a higher E&P EBITDA than shown on Slide 12 of $55. So I just want to make sure I'm thinking about this correctly and understand I can reconcile why -- how do you get the free cash flow breakeven just given there's modest free cash flow of $55?

Yes. First of all we do have quite a bit of hedges. So we're pretty insulated from some of those moves this year in particular. But if you just look at the guide overall, the capital efficiency of the program and how it looks we were talking about a little bit of free cash flow generation at $55. And at $50, it's still going to be positive. It's just not going to be quite as positive.

Okay. So obviously you're well hedged through the year so that obviously benefits -- okay. I just want to make sure I wasn't missing something there. In terms of - can you maybe just talk about your expectations for Bakken differentials? I know that the tightened Brent-WTI spread has been a headwind for rail volumes. So just curious on how you think that will play out for the year?

Yes. Okay. I think it's interesting because we've always talked about a differential to TI. And just given the way Bakken barrels move and largely to the coastal markets now really you're trading a little bit more off of a Brent market. But what we talked a little bit about is that Brent that TI differential did widen out a little bit in the fourth quarter and largely because Brent-TI narrowed. So we think that over kind of the course of the year differentials to TI will stay kind of in that same neighborhood. And I think we've got a guide that's pretty similar to years past.

And just maybe a follow-up on realizations -- the guidance on the gas realizations, can you just maybe talk to the seasonality of that the 90% to 100% of Henry Hub?

I don't know that we're seeing -- we're going to think about that too differently. I think we're just kind of saying kind of throughout the year we think it's going to be in that range. Obviously in the fourth quarter, it was a little bit better than that. We've certainly seen periods of time where it was quite a bit better than that. But just given where some of the weaknesses here in the first quarter that we've seen and how it's gapped out a little bit since the fourth quarter we've got a little bit more modest guide right now.

Okay, perfect. Thanks for taking my question.

The next question comes from Gail Nicholson from Stephens. Please go ahead.

Good morning. I really appreciate the incremental clarity you guys provided for the midstream margin for 1Q. Can you talk about how that looks for the rest of the year? And is one -- and should we think that 1Q, 2020 is the low part -- the low point for the margin?

Yes. So from a midstream perspective, great fourth quarter. First quarter is down a little bit. And EBITDA should become -- on that asset should be continuing to grow and ramp throughout the year. So you're exactly right there that this is kind of the low point in the first quarter and that should continue to grow throughout the year.

Okay. Great. And then Michael, I think in your prepared remarks you talked about an increase in artificial lift usage in 2020. Did I hear that, right? And if so what's the driver there? And how -- can you talk about the benefits of increasing that artificial lift usage?

Yes. So on the artificial lift side, one of the things you can think about is with the slowdown overall the program going from 2018 to 2019 and into 2020, you don't have on a percentage basis as many flowing wells. So you have more of your total production, more wells on artificial lift. And for us it's a combination of ESPs. Wild Basin is all gas lift. And then as the wells get a little later in life they all go for the most part on rod lift outside of Wild Basin.

Okay guys. Thank you.

The next question comes from Oliver Huang from Tudor Pickering Holt.

Good morning everyone and thank you for taking my questions. I know that there's still some lead time up to your first significant debt maturity in the 2022 to 2023 timeframe, but just given your focus in the markets on Oasis' leverage profile, could you maybe walk us through the pathway for how you all are planning to approach satisfying those maturities given the free cash flow over that timeframe? It sure doesn't look to cover the approaching debt wall.

Sure. Yes. So obviously there's a couple of ways that you can think about that. The good thing is that, you had a significant paydown in debt last year and we'll continue to set up the program where we can cash flow and reduce debt going forward. And that's what -- that's the plan that we're laying out. Obviously, at slightly higher oil prices you're going to be able to reduce that debt a little bit faster. And we'll continue to look at that program. We've looked at other levers as well. And last year you saw us do some smaller asset sales. And there's always that possibility that you can do some more of that here and there on the E&P side to continue to address the maturities. And then Tommy mentioned on the midstream side that we've been talking about that for a little bit. And we'll continue to look at ways of bringing value from the midstream back to the parent and we'll use likely some of that -- use some of that to look at the maturities as well.

Okay. And I guess just to kind of follow-up and clarify on that. Just given how strip is at $50 and you're essentially free cash flow-neutral would that mean that we need to get further CapEx cuts if you're not able to execute on the midstream monetization that you all have kind of talked about potentially?

Look, I think, we got a good plan here. And we're likely to stay with this plan in higher oil prices and even if it comes off for a little bit. Unless you see something that's materially shifting oil prices for a much longer period of time I think this is kind of the program that we've got set for the year. We feel confident that something will happen on the midstream side. And so we've got a plan and we're going to win.

Okay. That's helpful. And just one more quick question. Just given the go-forward spacing in Wild Basin at 10 wells per section just wondering if you have a remaining gross or net location count off hand in that area.

No. I don't have a count. We'll be drilling and completing wells in the area for the next two or three years. And as we've talked about we'll be moving rigs also in Indian Hills this year. And then from there we'll start to branch out a little bit more in 2021 and beyond.

Thank you very much.

The next question comes from Karl Blunden from Goldman Sachs. Please go ahead.

Thanks very much for the time. Just curious on the balance sheet. When you say you bought back some bonds or at least took out debt during the quarter could you tell us, which debt came out? And help us understand how you're prioritizing which debt to go after. Is it dollar price? Is it maturity? That would help a lot. Thanks.

Yes. Look what you saw was a significant reduction in the borrowing base. And so that's where a lot of the debt reduction came from. There were -- we did here and there take out a little bit of the longer-dated bonds. But really that's just a little bit opportunistic. But primarily it was on the revolver side.

Got you. And then in my conversation with some credit investors more and more of the discussion is around levers outside of asset sales. And you have outlined that you're confident that the midstream asset sale can get done. But absent an inflow of cash from midstream monetization what other parts do you have considering the size of the maturities? Do you -- would you look to the secured debt markets to extend? And then of course you have to guide a little further and take out 2023s given the covenants there. Just how should we think about the different parts to extension that you have available to yourselves?

Yes. We're probably not going to get into all that detail because it's a lot of what ifs and things that I don't think will really play out. So of course everybody can think about all the natural things of whether or not you can do layering and as you mentioned and other options, but we're not going to get into all that detail right now.

Thanks for time.

Thank you.

The next question comes from Gregg Brody from Bank of America. Please go ahead.

Hey, guys. Thanks for the time. And most of my questions were asked, but just a couple here. Just your last borrowing re-determination, I think, you were at $1.3 billion and you have commitment to $1.1 billion. Could you just remind us what your expectations in this borrowing base season? Most of all what happens to your borrowing base and then ultimately if your commitments will change at all?

Yes. Sure, Gregg. On the borrowing base side we did have -- you mentioned kind of where the borrowing bases were from the fall reserves from the fall haven't changed drastically. We'll see and we'll continue to talk to the banks about where their price decks will go and we'll go through that normal process in the spring. The nice thing for us is the reliance on the borrowing base continues to go down. We're free cash flow-positive. We're paying down the revolver. So our need for it continues to go down which I think in this kind of a market you want that. And so ultimately, we don't know exactly where the borrowing base is going to go. The bank markets, a tough market just like everywhere else on the capital side. But we'll continue to -- we've got a great group of very supportive banks with -- that we've had long-term relationships with, and we'll continue to work with them. Like I said, the reliance upon our bank facility continues to diminish, which is great for us.

And just one last one the Mirada litigation. I believe it's now scheduled to start in May. Is that correct?

Yeah. It's on the docket for May.

Thanks for the time guys.

You bet.

The next question comes from Dan Pickering from Pickering Energy Partners. Please go ahead.

Good morning guys. Thanks for taking the question. I guess we saw an opening in the high-yield window last month, six weeks ago something like that. How do you think about if the high-yield window reopens? I mean, there's a lot of focus on your debt levels. And yes, it's two years away. I mean, I think -- I mean, you guys are shareholders. You're sharing the pain here. Stock is down 40% since the last call. And the market on the equity side is clearly saying, there's a debt issue. So I was I guess encouraged that you feel something -- confident something's going to happen on the midstream side. We'll stay tuned there. But did you think about going out to the high-yield market when it was open? Would you think about it if it reopens?

Yeah. It's a great question Dan. Obviously, we're watching the high-yield market. And yes that window is open albeit very briefly. And so that's always a possibility in terms of trying to refinance the bonds and push the maturities out. That's always something that we're looking at and we're watching closely.

And Michael, does -- at this point in time, is it price? I mean, when you think about that, do you sacrifice price to get maturity? Would you pay up to extend? Or are you real price-sensitive? Just curious.

Dan, I think we got to look at all of it combined. And then we're also thinking through as you get something done on the midstream side, how it rerates all those bonds. We think there'll be a significant improvement on both the equity side, but also the bond side. And so we're thinking through kind of all those things. And obviously, you're always sensitive on price, but you're always looking at kind of that term as well and making sure that you have plenty of term. So it's a combination. I don't think there's just one thing that you're looking at that trumps everything else. I think it's just kind of a combination of all that put together.

Yeah. And Michael, you're confident around the midstream side. I understand the dynamic, which is too many details boxes you into a corner. But, I mean, maybe help us understand why you're confident about something on the midstream side. Is it because it's a great asset and 50 people want to be involved in it? Is it, I mean, I guess we're all kind of hanging on by a thread here hoping there is something. And so walk us through why you're confident so I can be more confident?

Sure. And I think you hit on it and it's what Tommy said about that business in his remarks. This is a coveted asset that has continued to outperform and we think has tremendous opportunities to continue to grow. It's a system that is in the heart of a great basin that has -- that's got resilient inventory for a long period of time going forward. So it's an asset that will be here and we think growing for a long time. We think it's a great asset for us as well as investors in that business as well as anybody that's looking to invest in that business. So we think it's a coveted asset and that's what we try to build.

Great. Thank you.

Thanks, Dan.

The next question comes from Betty Jiang from Credit Suisse. Please go ahead.

Great. Dan asked a lot of great questions. So I just have two follow-ups on the midstream side. How much EBITDA does OMS hold that's outside of your retained interest in the DevCos? It just seems to me that there is additional $20 million to $30 million of EBITDA that's outside of OMP's growth midstream and that will help us to understand the valuation of the midstream assets?

Yeah, Betty. We've got a little over $100 million of retained midstream assets -- $100 million of EBITDA of retained -- in the retained midstream assets at Oasis. And then obviously we've got our ownership which is about 70% of the MLP along with kind of our GP interest.

Got it. And then a follow-up is on the -- just noticed on the waterfall on slide 12, OMP's cash flow waterfall excludes the distribution. So, I just wanted to better understand how you guys think about and define consolidated free cash flow.

Well, so what page 12 is showing is kind of the cash flow profile -- free cash flow profile kind of to the parent. And it's kind of a look that's without the midstream, right? So not on a consolidated basis, but what you're seeing from an E&P perspective. And that's with kind of all the debt at the E&P side of it is you're basically you're positive. And then on the OMP side, the free cash flow is there, and then the distributions are within that free cash flow as well. So, you're going to be free cash flow-positive on the OMP side as well. And so, really from a consolidated standpoint, you're free cash flow positive on both sides. So, consolidated you're free cash flow positive as well.

Okay. All right. I’ll just follow-up on that later. That’s it for me. Thank you.

Thanks, Betty.

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

Thanks, Jason. In closing, I wanted to make a few general comments on our industry and the Oasis corporate responsibility initiatives. I'm proud to be part of an industry that plays such a critical albeit underappreciated role in improving people's lives. Increasing global populations and living standards are increasing demand for readily available, reliable and affordable energy every day. While there is a push for renewable sources, we're not aware of any realistic projections suggesting that those new energy sources can be scaled to reduce the need for oil and gas in the foreseeable future, especially on a global scale. So, however, painful the last few years have been, we believe this is a good time to be a leader in producing oil and gas in a responsible manner while meeting the expectations of a carbon-constrained world. On that note, Oasis is focused on leveraging technology and management practices to improve our cost structure and efficiency, strengthening our already leading greenhouse gas emissions profile, and environmental footprint management. We are a recognized industry leader in the capture of natural gas that we produce due to a proactive and significant investment and the investments that we've made in our midstream business. The Oasis gas capture rate in North Dakota is now one of the highest if not the highest in the industry. Also, our investment in pipeline infrastructure extends further to oil and water transportation, which keeps additional trucks off the road and lowers our associated greenhouse gas emissions. Our annual proxy will be filed shortly, and I encourage everyone to have a look for more detail on tremendous efforts on gas capture as well as other aspects of corporate responsibility as well as updates on executive compensation. Oasis continues to lower costs and drive efficiencies putting us in a strong position to generate E&P free cash flow, which along with several other viable options helps us to continue to reduce debt. Our deep low-cost resource base with a strong team behind it puts us in a position to succeed and we all look forward to delivering for our shareholders. I know all you guys are really busy. So, really appreciate you guys joining the call today. Thanks.

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