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. Should you need assistance, please signal the conference specialist by pressing the star key followed by zero. After today's presentation, there will be an opportunity to ask questions. To ask a question, you may press star, then one on your touch-tone phone. To withdraw your question, please press star, then two. Please note, this event is being recorded. I will now turn the call over to Michael Lou, Oasis Petroleum's CFO, to begin the conference. Thank you. You may begin 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 spending 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 a 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 take away 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 x since we IPO'd 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 - 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 costs while maintaining well performance. Our program will be focused in the Wild Basin and Indian Hills areas and will include two step-out tests with 3 mi 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 mi 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 costs 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 20-25 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, as a result, we completed just 13 wells in Q4 2019, just 16% of our total 2019 completion activity. In addition, our Q1 activity is heavily backloaded to March as we picked up frac crews in January and February.
For perspective, about 60%-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 backloaded 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 are using similar approaches in the Delaware.
To close, we end a 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 grow 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-$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-$7.75 per BOE. The 2020 guidance reflects an expected increase in spending for artificial lift. We've been able to beat expectations 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. As Brent -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 seniors' unsecured notes and the Oasis Credit Facility.
We're further securing our future free cash flow generation with 85%-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%-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-$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 will 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. 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. To ask a question, you may press star, then one on your touchtone phone. If you're using a speakerphone, please pick up your handset before pressing the keys. To withdraw your question, please press star, then two. 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 of 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. Our midstream business 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. 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. As my follow-up, perhaps for Taylor, referencing page seven, 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 clusters at more fluid generally? 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.
In 2019, the Wild Basin at the kind of the 10-well spacing, most of the program is at that I guess maybe when the completions were brought online were probably a little more mid-year. As you get into, we started drilling them, but the lag between drilling and bringing those completions on, it's more mid-year-ish. That's not exact. We can get back with you on that. 2020 will reflect all 10 -well spacing, and then we're even testing some that are a little wider than that.
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 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 would be focused in Indian Hills and Wild Basin. Can you just remind me, I guess, how much higher six-month CUMs are in that asset relative to the rest of the portfolio or relative to the 2019 average, maybe? Even better.
I'll talk a little bit about the mix and then also about CUMs. The mix in 2019, you had Wild Basin, then you had some Red Bank and North Alger.
Yep.
For 2020, you're going to have Wild Basin, Indian Hills, and a bit of Red Bank. The Wild Basin weighting is kind of 50%-60% of the completions for 2020. The mix is a little different. I wouldn't say overall it's crazy different. We had a few more wells in 2019. Rather than thinking about Williston, it would be Williston and Permian. The weighting in Williston was higher in 2019. In 2020, you're going to have about 50 wells in Wild Basin and then another 20-25 wells in the Permian, whereas you had 11 Permian wells last year, and the Williston count was 67. That's a bit of a different mix.
In terms of the results just within Williston, Michael, if you look on page six of the presentation, you can see, and you can just pick off the graph for the different areas, what the performance has been like for the areas that we're talking about. You got Wild Basin, Indian Hills, Painted Woods, North Alger, and Red Bank on the graph in the upper right-hand corner.
I guess each of those would have a little bit of an uptick with wider spacing. I'm assuming those are all.
Yeah.
A mix of spacing in the-
Yeah, that'd be accurate. Generally, we've moved to a little wider spacing, testing a little wider spacing in all these areas.
Okay. Would you care to provide, or do you have an estimate of what maybe an average six-month oil CUM would look like in the Delaware program as it relates to your current expectations?
The Delaware program, as we talked about, is going to be focused in Wolfcamp A and the Bone Springs. I don't have it right here in front of me, Michael, so let's circle back and give you numbers.
Yep
In terms of the economics, it's very competitive with Wild Basin, for example.
Certainly. Okay. I appreciate that, and sorry about going in the weeds there. Last one on my end was just, I just want to make sure I'm thinking about Williston well cost right? It seemed like in the deck, you were 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. What's going on there is when we talk about getting to $7.2 million, which we have done. That is a year-end target. That was for a 6 million pound average job that we were doing last year. If you remember, we'd generally gone to 10 million pound Bakken wells, 4 million pound, 3 million, 4 million, 1 2 million pound wells in Wild Basin, for example. 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. Those bigger jobs that we're pumping on average just have a little higher cost. That's the $7.8 million.
Okay. That's helpful. Great. Thanks, guys. I appreciate it.
Thanks.
Thanks, Michael.
The next question comes from Brian Downey from Citigroup. Please go ahead.
Morning, thanks for taking the questions. Maybe a follow-up on that one. As you noted on slide nine of the deck, 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. Sounds like there's some moving parts on well design efficiencies, how much of was service pricing assumptions based on what you saw in 4Q, and any changes in absolute activity or working interest driving that decline there?
It's just as we continue to work through the quarter in 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 activity and production standpoint, thinking about the free cash flow mix, we're able to pull it down another $15 million. We feel good about how that plays towards preserving free cash flow and, in this environment of volatile pricing that we're experiencing, just being able to deliver on our program but do it from a conservative stance.
Got it. Makes sense. 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 if you've seen that dynamic change anything, maybe increasing or decreasing acreage bolt-on potential to your Delaware position there.
Yeah. Obviously, been a number of transactions, and I think it reflects really the quality of the acreage in the area, which 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. 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. I'd say the opportunities, we continue to have some things to focus on. It really hadn'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 is find attractive bolt-ons 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. You've talked in the prepared comments about the strategy being repeatable modest growth. I'm just curious, at what point you would think about transitioning the company to just a pure maintenance CapEx sort of level? Maybe, I guess alternatively, what does the current activity level give you in terms of efficiency that maybe a lower CapEx program wouldn't?
The way the program's set up, we've got pretty level loaded activity. It's very efficient. The Williston, it's the two rigs, really one frac crew running for the year. Two rigs since frac crews come off and on in the Delaware, but a steady two rigs. We're pretty well insulated from a hedge position. Michael will talk about in his comments, we've got about 70% of our volumes at a $54 or better price for the year. We got even more in that hedge in the first half. 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. Prices continue to be volatile. We'll monitor. 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 for that. I assume there will probably be more data or more info when the K comes out, but I was wondering if you had any update on the Mirada legal proceedings?
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. If you look in our disclosures, just to give you an indication of how we think about the thing, we do disclose a reserve of $20 million. Now, that's for all of our litigation, but it'll give you an idea, kind ofMaybe the range of what could happen with the case. 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, thank you for taking my questions. My first one surrounds 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? How we should think about abandonment costs after the EBITDA inevitably starts to decline.
Yeah. We can talk generally around midstream. Obviously, there's going to be a lot more talk on our midstream call in about an hour. 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. 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, on the gas system. 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%-30% 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. 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 years, capital markets, whatnot, it seems like getting an additional 75 would be quite challenging. 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?
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. Because of the way the pays are stacked, it was on an equivalent basis about 1/3 of what we have in the Williston. That's where I came up with those numbers. I think for us, 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. You just don't know where those things are going to come from and when. Fortunately, the team's done a great job on much smaller things bolting on in and around our position in the Delaware.
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 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. 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. 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 3 mi lateral in South Cottonwood. I think Exxon maybe has seen some decent results with 15K laterals. 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 3 mi lateral program in theory, and then maybe what the potential drawbacks could be with also 3 mi laterals.
You bet. We're really just looking at the levers we can pull to improve economics in the wells, and especially as some of these areas like South Cottonwood are a little further out of what was the old traditional core. We've seen, if you look at the footprint, we expanded what we call Tier 1 just based on higher intensity completions. The impact that that's had on productivity of the wells and the economics. Going to a 3 mi lateral, just adding another 5,000 ft 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 mi laterals, and have seen pretty much corresponding increase in production on a ratio basis by adding an extra 2,500 ft.
We think going to a 3 mi lateral, what we'd like to see is that, just again, a corresponding increase relative to what that first 10,000 ft will deliver to you. 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 mi lateral wells. We're also looking at those results and trying to get an idea of what the impact's going to be. 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, and Michael, thanks for your time.
Hey, David.
A fairly simple one, but I know you guys talked about the year-over-year growth of mid-single digits 4Q 2019 to 4Q 2020 at the corporate level. Could you break that out between the two asset areas?
I think a good way to think about it without getting too specific is that the Williston is staying relatively flat and more of the growth is occurring in the Permian.
Yeah. I just wanted to properly understand if this is a Williston maintenance program where it is now and that the growth is coming from Delaware.
Yeah, the Williston is more or less, it's maintenance on production. As we've been talking about it allows us 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 that 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 that 2021 progression? Is this two and two split the most capital efficient that you think for this program on a sustainable basis in terms of maximizing free cash? Does that change quite a bit going into 2021 as the Delaware gets a bit larger?
Yeah. Right now we're kind of thinking about it as a fairly steady state program in both the areas. We are absolutely going to continue to re-look at the results as the year goes on. Having the two positions, as we've talked about in the past, we think is advantageous because it allows you to reallocate capital. It 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 it's productivity or economics in one or other of the areas allows you to reallocate that capital. Right now, as we're looking at this early in the year, it's still kind of a steady state program.
Hey David, keep in mind, 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 2021. We'll continue to look for opportunities where we have a chance to hedge into 2021 to protect. We'll do that. As you know, we've always done that.
Sure. Thanks, Tommy and Taylor.
You bet.
The next question comes from William Thompson from Barclays. Please go ahead.
Hey, good morning or good afternoon, I guess, on the East Coast.
Morning.
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 in slide 12 at $55. I just want to make sure I'm thinking about this correctly and understand I can reconcile how do you get the free cash flow breakeven just given there's modest free cash flow at $55?
Yeah. 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. 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. Obviously, you're well hedged through the year, so that obviously benefits. Okay. I just wanted to make sure I wasn't missing something there. 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 through the year.
Yeah. Look, 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. What we talked a little bit about is that TI differential did widen out a little bit in the fourth quarter and largely because Brent -TI narrowed. We think that over the course of the year, differentials to TI will stay in that same neighborhood and I think we've got a guide that's pretty similar to years past.
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%-100% of Henry Hub?
I don't know that we're going to think about that too differently. I think we're just saying 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. 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.
Thanks.
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 the rest of the year? Should we think that 1Q 2020 is the low point for the margin?
Yeah. From a midstream perspective, great fourth quarter. First quarter is down a little bit, and EBITDA should be coming on that asset should be continuing to grow and ramp throughout the year. You're exactly right there that this is the low point in the first quarter, and that should continue to grow throughout the year.
Okay, great. Michael, I think in your prepared remarks, you talked about an increase in artificial lift usage in 2020. Did I hear that right? If so, what's the driver there and can you talk about the benefits of increasing that artificial lift usage?
Yeah. On the artificial lift side, one of the things you can think about is with the slowdown overall, the program going from 2018 through 2019 and then 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. For us, it's a combination of ESPs. Wild Basin is all gas lift. 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, great. Thank you.
The next question comes from Oliver Huang from Tudor, Pickering, Holt. Please go ahead.
Good morning everyone, and thanks for taking my questions.
You bet.
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 and 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. Yeah. Obviously, there's a couple of ways that you can think about that. The good thing is that you had a significant pay down in debt last year. We'll continue to set up the program where we can cash flow and reduce debt going forward, and that's a 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.
We'll continue to look at that program. We've looked at other levers as well. 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. Then Tommy mentioned on the midstream side that we've been talking about that for a little bit. 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 to look at the maturities as well.
Okay. I guess just to 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'd need to get further CapEx cuts if you're not able to execute on the midstream monetization that you all have 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 the program that we've got set for the year. We feel confident that something will happen on the midstream side. We've got a plan, and we're going to run it.
Okay. That's helpful. 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 offhand in that area?
Yeah, I don't have a count. We'll be drilling and completing wells in the area for the next two or three years. As we've talked about, we'll be moving rigs, also in Indian Hills this year. 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.
Hi, guys. 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.
Yeah. Look, what you saw was a significant reduction in the borrowing base. That's where a lot of the debt reduction came from. We did, here and there, take out a little bit of the longer-dated bonds, but really, that's just a little bit opportunistic primarily, it was on the revolver side.
Got you. 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. Absent an inflow of cash from midstream monetization, what other paths do you have considering the size of the maturities? Would you look to the secured debt markets to extend? Then, of course, you'd have to go out a little further and take out 2023s given the covenants there. How should we think about the different paths to extension that you have available to yourselves?
Yeah. 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. 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 the time.
Thank you.
The next question comes from Gregg Brody from Bank of America. Please go ahead.
Hey, guys. Thanks for the time. Most of my questions were asked, but just a couple here. Your last borrowing determination, I think you were at $1.3 billion, and you have commitments of $1.1 billion. Could you just remind us what your expectations in this borrowing base season as to what will happen to your borrowing base, and then ultimately if your commitments will change at all?
Yeah. Sure, Gregg. On the borrowing base side, we did have You mentioned 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. Our need for it continues to go down, which I think in this kind of a market, you want that. Ultimately, we don't know exactly where the borrowing base is going to go. The bank market's a tough market, just like everywhere else on the capital side. We've got a great group of very supportive banks that we've had long-term relationships with.
We'll continue to work with them. Like I said, the reliance upon our bank facility continues to diminish, which is great for us.
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.
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 the high yield window reopens? There's a lot of focus on your debt levels, and yes, it's two years away. You guys are shareholders, you're sharing the pain here. Stock's down 40% since the last call, and the market on the equity side's clearly saying there's a debt issue. I was encouraged that you feel 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.
Yep.
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.
Michael, at this point in time, is it price? 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.
Yeah, Dan, I think we got to look at all of it combined. We're also thinking through, as you get something done on the midstream side, how it re-rates all those bonds. We think there'll be a significant improvement on both the equity side, but also the bond side. We're thinking through kind of all those things, and obviously you're always sensitive on price, but you're always looking at that term as well and making sure that you have plenty of term. 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 of it put together.
Yeah. Michael, your confidence around the midstream side, I understand the dynamic, which is too many details boxes you into a corner, but 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? I guess we're all kind of hanging on by a thread here hoping there is something. Walk us through why you're confident so I can be more confident.
Sure. 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's got resilient inventory for a long period of time going forward. 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. We think it's a coveted asset, and that's what we try to build.
Okay, great. Thank you.
Thanks.
Thanks, Dan.
The next question comes from Betty Jiang from Credit Suisse. Please go ahead.
Great. Well, Dan asked a lot of great questions. 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 DevCo? It just seems to me that there's additional $20 million-$30 million of EBITDA that's outside of OMP's gross 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 in the retained midstream assets at Oasis. Obviously we've got our ownership, which is about 70% of the MLP, along with our GP interest.
Got it. A follow-up is, just noticed on the waterfall on slide 12, OMP's cash flow waterfall excludes the distribution. Just wanted to better understand how you guys think about and define consolidated free cash flow.
Well, what page 12 is showing is kind of the cash flow profile, free cash flow profile to the parent. It's kind of a look that's without the midstream, right? Not on a consolidated basis. What you're seeing from an E&P perspective, and that's with all the debt at the E&P side of it, is you're basically positive. On the OMP side, the free cash flow is there, and then the distributions are all within that free cash flow as well. You're going to be free cash flow positive on the OMP side as well. Really from a consolidated standpoint, you're free cash flow positive on both sides, so consolidated, you're free cash flow positive as well.
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's 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. 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 produced due to a proactive and significant investment in 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. 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.