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WPX Energy Inc (NYSE:WPX)
Q2 2020 Earnings Call
Jul 30, 2020, 10:00 a.m. ET

Contents:

  • Prepared Remarks
  • Questions and Answers
  • Call Participants

Prepared Remarks:

Operator

Ladies and gentlemen, thank you for standing by, and welcome to the WPX Energy Second Quarter 2020 Earnings Conference Call. [Operator Instructions] Please be advised that today's conference may be recorded. [Operator Instructions]

I would now like to hand the conference over to your speaker today, Mr. David Sullivan, Vice President of Investor Relations. Thank you. Please go ahead.

David Sullivan -- Director, Investor Relations

Thank you. Good morning, everybody. Welcome to the WPX Energy Second Quarter 2020 Earnings Call. We appreciate your interest in WPX Energy. Rick Muncrief, our Chairman and CEO; Clay Gaspar, President and COO; and Kevin Vann, our CFO, will review the prepared slide presentation this morning. Along with Rick, Clay, Kevin, other members of the management team are available for questions after the presentation. On our website, wpxenergy.com, you will find today's presentation and the press release that was issued after the market close yesterday. Also, our Q will be filed later today. Please review the forward-looking statement and disclaimer on oil and gas reserves at the end of the presentation. They are important and integral to our remarks, so please review them. So with that, Rick, I'll turn it over to you.

Richard E. Muncrief -- Chairman and Chief Executive Officer

Thank you, David, and good morning to everyone on today's webcast. Thank you for your time, for your interest in WPX and what our people continue to accomplish. This is, obviously, a year unlike any other, but we remain confident in our company and our nation's ability to get through this, very confident. Now as I said last quarter, we're going to need some patience for recovery to fully take hold. We're not there yet. But let's face it, we've seen some real progress in the last 90 days. Everyone would prefer to have greater certainty and a lot more clarity around the time line for this pandemic that we're facing. But there's plenty of shades of gray and volatility right now. This demands a steady hand. That's why risk management practices are so core to the foundation of solid companies, including WPX. There's an art and a science when it comes to having the confidence and experience to know how to navigate these rough waters. It's truly hard to imagine that all the scenarios we've seen play out across the globe and in our sector, happened in just a matter of months, but they did. I credit our team for making sure that we were ready. That preparation makes all the difference when things around you appear to be falling apart. And that positioning is exactly what separates one company from another. You can't fake discipline: you either have it or you don't. Your management philosophy most certainly gets magnified in an environment like this. And that's where our WPX story starts today, one that is defined by stability, confidence, continuity and positive results, even in such an unprecedented time. The strength of our balance sheet, our revolver capacity, our commodity hedges and our track record for disciplined execution continues to give us a considerable edge. And let's not forget, this isn't just about 2020.

The position we're in, and the thoughtful actions we're taking, are going to benefit WPX shareholders in future years as well. Because of our prudent planning, we've been able to make quick, smart, sensible adjustments and necessary capital cuts without slamming on the brakes in such a manner that sends people flying through the windshield. I'm proud to say we've also honored our commitments to the market and to our service providers. We will continue to strive to do the right thing, the right way. The continuity we have in our development program, despite the second quarter curtailments and shut-ins, help us in so many ways, including our targeted exit rate this year and what that means for our performance going forward. Now the desired outcome, of course, for any well-run business is to generate free cash flow, and we have nice results there, too. So with that, let's turn to page two. As you recall, we laid out two possible scenarios for the second half of 2020. We have determined scenario one or exiting this year at 140,000 barrels of oil production a day is the preferred route. What we now know, and because the visibility is starting to occur, we reduced our capital spending by $50 million for the balance of 2020. You can chalk this up to efficiencies, cost savings, our people and the cadence of how we're managing our development plan. At the same time, we're also raising our expectations for free cash flow from $150 million to $200 million for this year. This is a direct result of what we achieved in the second quarter. I know this begs the question about the timing for dividend. Financially, we could do it right now like we'd originally targeted. But we also think it's also inappropriate excuse me, appropriate and prudent to try to ascertain a little more insight into the forward macro environment. Recall, we want to do something that's meaningful and durable. We're gaining more clarity internally about what 2021 and 2022 could look like, which will help us nail down our decision. So stay tuned, please. We've also addressed some previous risks that we had going into 2021 by adding attractive hedges at $41 a barrel, and building the revenue certainty, we would we'd like to have to support our capital programs.

As always, we remain opportunistic by proactively reshaping our debt towers at a lower interest rate. Our next significant maturity doesn't occur until 2023, which is a very manageable $242 million. Finally, we're resuming our completions activity in a thoughtful, moderated way. We're not going to get ahead of ourselves despite somewhat better commodity prices. We do value the continuity it allows, the revenue power we see, the data we gain from the knobs we turn on our completions, as well as the ability to begin realizing the incredible value from our Felix acquisition. I'm still extremely impressed by everyone who is associated with such a seamless transition. It's one thing to integrate another company during a normal environment, but a whole other matter to do it in the middle of a pandemic, working from home, managing social distancing and the like. This is a significant feat that I don't want to go unnoticed or to be underappreciated. Great job, team. Now let's turn to page three. This page shows our discipline in how we're approaching the back half of 2020. We've been busy bringing production back online, and now our team can return to a more normal business even as we scale back capital spending. What you see here is an incremental approach to address our DUC inventory. This involves redeploying three completion crews in the third quarter as we work toward a planned exit rate of 140,000 barrels of oil per day at December 31. This is a thoughtful plan that's backed by our industry-leading hedges for 2020, and one that supports our planning for the next couple of years. Because of how well we're positioned this year, we have the ability to do this in a way that's not stressing our balance sheet or putting short-term interest ahead of long-term value.

Now I'll turn the call over to Clay Gaspar, our President and COO, who will update you on our company's operations, including some exciting well results from one of our newest Felix pads. Let's turn to Page four.

Clay M Gaspar -- President and Chief Operating Officer

Thanks, Rick, and good morning, everyone. As Rick mentioned, these are certainly unprecedented times. In the most stressful situations, basic human instinct is to defend against the most immediate risk and progressively work toward longer-term risks and hopefully have the opportunity to act proactively on long-term opportunities. I hope you can sense from our comments today, WPX has been able to check the box on near and midterm concerns. And we are spending a fair amount of our energy toward positioning and opportunities for the coming years. The luxury of being able to consider value-creating opportunities rather than just defending against a debt collector at the door, is on the back of years of work to build a strong asset base, sitting on top of a rock-solid financial foundation tended by a first-class workforce and driven by values of courage, results and relationships.

On the last earnings call, we laid out two scenarios that help delineate what the balance of 2020 might look like. The first scenario was assuming a quicker oil price recovery that would allow us to bring the completion crews back in the near term, and we're doing just that. Please don't mistake this for the mindset of full speed ahead. We are still methodically working down rig count, thoughtfully and safely tending to the wells that were curtailed, and at the same time, bringing in the completion crews to work down the backlog of DUCs. The low 40s strip supports these actions, and these actions will allow us to be very well positioned for this year's exit rate, and more importantly, 2021. Kevin will talk more about the maintenance capital and the free cash flow implications for 2021. I can tell you that our actions in the second half of this year have a material benefit to 2021 and a healthier footing in 2021 puts us in great position for '22 and beyond. Now let's turn to Slide four and discuss some more recent well results. First, let me thank the hard-working integration team from all parts of our company that has worked to bring the Felix assets into the fold. I can conclusively say that we are fully integrated and are now focusing on driving incremental value through cost reduction, improved well performance and, importantly, improving ESG considerations as well.

The Felix Huerfano pad is a great example of this value creation. We completed six wells by Felix that were drilled by Felix and we elected to use the standard Felix completion on four and a WPX style completion on the remaining 2. The wells were similarly spaced, all 2-mile laterals and even use the same slowback methodology. As you can see from the plot to the right, the Felix completions were a touch better than the acquisition type curve, but the WPX completion style has significantly outperformed both curves. In fact, 46% better than we baked in for the acquisition case. Also with the same service companies on the same location, the WPX design was nearly $300,000 cheaper. I believe that this is just the beginning. We still have significant opportunities on improving the landing and steering, opportunities on casing design and on the overall cost structure. I will touch a bit more on this on the next slide. In the fourth quarter, we will have our first production on the Felix wells that were drilled and completed by WPX. I'm eager to show you the absolute results of these wells and how they perform versus the acquisition type curve that underwrote the acquisition.

Now let's turn to Slide five, and we can talk about the Delaware well cost. First, I want to give a tip of the hat to the technical team, who's in the midst of a nine well CBR completion in Stateline, with the first sales expected in late August. Once again, having the ability to still focus on long-term value, we are investing in some science to better understand the very complex considerations of landing zones and spacing. One may question the timing of this investment, but when you consider the freed up bandwidth of our technical team as well as the very low cost environment, this is the perfect time to gather this intel and understand the implications. On the CBR pad, the nine wells are landed in eight distinct landing zones. Each of these landing zones are proven and individually generate competitive returns even in today's pricing. What we are studying is how the completions interact and how we may be able to continue to tweak our completion design to cut costs and still yet improve performance.

You may recall me mentioning the Pecos State project we did back in 2018. The technical work included a contiguous 800-foot core running from the Third Bone Spring, all the way through the Wolfcamp B. Fiber optics, microseismic, external pressure and temperature gauges, the Pecos project provided real tangible evidence that changed our completion design. We have used these learnings to save tens of millions of dollars on subsequent wells in the Permian and also in the Williston Basin. It's also the basis for some of the changes that we're employing in the Felix wells. The CBR project is the next step, and it takes a larger view up and down the column to make sure that we're making the right decisions in regards to spacing, staggering and sequencing. I've had a preview of this data earlier this week, and I can tell you it's very compelling. The data collection can be hard to appreciate from a distance. We typically don't share progress along these lines, but I thought it could be important to add some color and context to the limited state production data that's available publicly.

Normalizing production per foot is a necessity, but certainly doesn't account for the incredible cost savings associated with longer laterals. Also, without having the ability to really understand the details of the spacing and the landing zones, it can be harder to discern what is a test and what is progress toward development. Core to our culture is post appraisals and learning from the past. We look back at every well, every pad, and every new test with a critical eye. We also do an all-inclusive annual look back on each year's capital program and present that to the Board. I can tell you with absolute certainty, with a consistent price deck, the 2019 Permian results deliver better all-inclusive returns than 2017 or 2018. I also believe 2020 will outperform 2019 with the same methodology. When you take time to consider the costs as well as the productivity of program, you can see the steady progress we're making on value creation. From where I sit, I can also see a couple of step change improvements that will be more evident to the public in the coming quarters. Since 2018, we've reduced drilling, completion and facility cost by 35%. The second half of 2020, our well costs are benefiting from some deflation, but very significant percentage of the costs are related to changes like I described related to the Pecos State completion improvements. I should also note that these well costs include drilling, completions, facilities as well as artificial lift, which is usually about $500,000 per well. I will also remind you that when we announced the Felix deal, we assumed no synergies in the purchase price. The economics of the deal assumed well cost of $10 million for a Felix/2-mile Wolfcamp A. As you can see from the combined Stateline and Felix, the well cost for a 2-mile Wolfcamp A is significantly lower than the acquisition economics. The Felix wells are projected around $8.4 million and the Stateline wells, about $7.6 million. Narrowing that $800,000 delta is an opportunity for us to gain material additional value from each field as well. More to come on that. Now let's turn to slide six, and I'll discuss DAPL and our risk mitigation. The July six DC court order regarding DAPL was very disappointing. Candidly, people who think that pushing oil away from pipes and onto trucks and trains in the name of the environment are not thinking very clearly.

The ultimate outcome of this court order is still very unpredictable, but prudence requires us to mitigate potential downside risk. Our marketing group continues to have in-basin fixed price deals with trusted partners and also moved quickly after the ruling to secure a one-year rail deal as well as transactions through additional pipe capacity. Our original 2020 guidance assumed a Williston oil differential of $5 to $5.50 for the full year 2020. After mitigating our exposure post DAPL the post DAPL ruling, the second half of 2020 oil differential should be about $6 to $6.50 in Williston. On a consolidated basis, the impact of overall oil differential is approximately $0.50. In the case that DAPL continues to flow, we'll be able to claw back most of that incremental cost. This may be an unnecessary insurance policy, but we've shown before is protecting asymmetric downside risk can be well worth the small incremental fee.

Now I'll turn it over to Kevin Vann, our CFO, for the financial update.

J. Kevin Vann -- Executive Vice President and Chief Financial Officer

Thanks, Clay. And it goes without saying, but wow, what a quarter. The operations team scrambled on both sides of the ball, the financial team working together with our marketing team, optimized our risk management strategy. And our treasury team opportunistically hit the bond markets, restacking some debt towers as the WPX team as a whole remains focused on getting through the current fire without taking our eye off our long-term vision. In a quarter where oil traded for a short time at less than 0 on the open market and overall realized commodity prices dramatically declined, there's a lot of calm and consistency in what we accomplished. And that's what we're known for, being able to take the curve ball without buckling our knees because we're disciplined, proactive and balance sheet minded. We believe that the market has wanted and continues to want consistency. We are obviously in a commodity-based business. The one thing you should expect from WPX is that we are proactive risk managers.

We don't swing for the fences every quarter or every year. We do understand that the wants and desires of the investors ebbs and flows, but running a good business always includes good risk management practices. It's on our resumes here at WPX. You've seen it from us over the last five years. You should expect it from us because we expect it from ourselves. Risk management extends way beyond hedging commodity prices as well. Are we perfect at everything? Of course, not. No company with any level of self awareness believes itself to be so. We constantly evaluate how to get better, what others are doing and how to modify and adapt to dynamic environments. That may sound a little cliche, but think about our track record over the last five years.

I think we have proven it. We did not just sit still and hope things got better as a natural gas producer. We were proactive. Many companies were not proactive risk managers, and you are seeing the consequences of those decisions through this downturn in commodity prices. We have all been hit by the macro events right now, but we pride ourselves in being ready for the unexpected. We believe that you need to manage the risk or the risk will manage you. You're seeing financial stability, continuity in our development program and meaningful free cash flow. Of course, we have adjusted our capital program this year but are utilizing the benefits of being active risk managers like I just mentioned, by utilizing the benefit of the shock absorbers we put in place long before the beginning of 2020. We always consider the financial outcome of anything we do in the field, whether it's ramping down, cutting capital or starting to chip away at our DUC inventory. Now let's turn to slide nine.

We generated $166 million in free cash flow for the quarter and expect approximately $200 million for the full year. Also, despite the decrease in average realized prices for all commodities, our adjusted EBITDAX increased 17% from $666 million for the first half of 2019 to $779 million this year. For the quarter, adjusted EBITDAX was up 15% over the same period last year. At 123,700 barrels per day, our oil production is 26% higher than the same period of 2019. This increase is driven by the acquisition of Felix Energy in March despite the curtailments that Clay discussed previously. Total equivalent barrels were up to 207,000 barrels per day or about 30% over prior year, again, driven by the acquisition of Felix. For the second quarter, we are reporting an adjusted EBITDAX of $400 million, which is $53 million higher than the second quarter of prior year. The record quarterly results reflect the benefits of our risk management strategy, the steps we took to optimize our physical barrels versus our hedge position and the efforts to drive cost down during the quarter.

Not only did absolute costs go slightly down this quarter, the cost per BOE came down as well. We are also reporting an adjusted net income of $69 million versus $37 million in 2019. The improvement was driven by the same items impacting adjusted EBITDAX as we realized $21.46 per barrel for oil revenues versus $57.42 this year or last year. But were more than offset by the higher volumes and hedge realizations at prices north of $55 per barrel. Our capital expenditures incurred for the second quarter totaled $188 million. Of this amount, approximately $173 million relates to drilling and completion activity for operating wells and $3 million for midstream infrastructure. Now let's turn to slide 10. During our first quarter call, our plans for the balance of this year were unclear as we fought the current day fires caused by COVID and the price war on commodity prices. As Clay mentioned, we laid out a couple of options as to how the balance of the year might play out, depending on crude pricing and the ultimate returns we believe we can achieve given our well cost. With crude pricing north of $40 for the balance of 2020 and around $43 per barrel next year, we are leaning into the first scenario, which has us exiting this year around 140,000 barrels of oil per day, which will take us approximately $1.1 billion of full year capital to get there. I'm pleased to say that capital number is $50 million lower than our previous estimate, and we will end the year with 35 to 40 DUCs. More importantly, to keep our year-end production flat in 2021, we estimate that it will take between $800 million to $850 million in capital.

We also believe that we can generate approximately $200 million in free cash flow at roughly a $40 WTI price for 2021. As Clay said, we are not only looking to the capital spend this year and next, but what that means to our 2022 trajectory and the capital efficiency we can achieve. Before I turn it back over to Rick, I want to say that we recognize the world has changed. WPX is adapting to it just like everybody else. One thing that has not changed is WPX's approach to proactive risk management. We didn't see the events of 2020 coming, I don't think anybody did. However, our balance sheet was ready for this unforeseen blow. Our cash flow protection we had in place helped us absorb the shock, and I'm proud of how the WPX team made additional moves during the second quarter to protect the value for WPX shareholders.

I'll turn it back to Rick for some closing comments.

Richard E. Muncrief -- Chairman and Chief Executive Officer

Thank you, Kevin. I'd like to close where we started this morning. Simply put, I believe, in the future of WPX, the significance of what our sector contributes to society and the unmatched spirit that we have here in America to never back down. The challenges ahead remain daunting and real. But in our company, we're up to the task. We will continue to wholeheartedly embrace our responsibility, socially and financially, to deliver meaningful results. You can see that in our second quarter numbers as we've gone through. You can see it in our 2020 ESG report that's available now on our website, our continued bias for action, how we strive to work closely with our stakeholders, and the training we provide to our employees. As always, I'm honored to serve our shareholders and represent our employees. So operator, we can now open the line for Q&A. Thank you.

Questions and Answers:

Operator

Operator one [Operator Instructions] Our first question comes from Asit Sen with Bank of America. Your line is now open.

Asit Kumar Sen -- BofA Merrill Lynch -- Analyst

Clay, I appreciate all the color on DAPL and how you guys are adapting to the situation. And if I could go to slide seven, you talked about the mitigating steps. Just wanted to probe a little bit on your comment on additional pipe agreements. And then the slide there, you talk about sales outlet to Cushing, Clearbrook and PADD 5, could you provide a rough breakdown of that?

Clay M Gaspar -- President and Chief Operating Officer

Well, I'd tell you some of it some of the work that we've done here has been in building relationships over the years, we have a very good hand on the pulse of those opportunities. We keep a real close eye on that. We knew right away that where the gaps were, where the opportunities were, and we moved very aggressively on that. Some of the details, I don't think we're going to get into on the call, the nature of those individual agreements. But I can tell you, just kind of rolling the numbers up, we're very well protected, 2020 and even out into 2021. This is a thoughtful measure that we see is just that asymmetric risk downside protection. That's how we kind of think about these things. I do have Greg Horne here. If there's anything, Greg, you want to add, a little bit more granular?

Greg Horne -- Vice President of Midstream and Commodity Marketing

No. No, I think that's pretty sufficient, Clay.

Asit Kumar Sen -- BofA Merrill Lynch -- Analyst

Okay. And perhaps on the maintenance capex number or scenario of $800 million to $850 million. Broadly, how are you thinking about, again, it's conceptual, how are you thinking about the split between the two basins, either on a rig basis or a completion basis? And is the midstream capex number in there? And what would the year-end 2021 DUC count be in that scenario?

Clay M Gaspar -- President and Chief Operating Officer

Year-end 2020 or year-end 2021?

Asit Kumar Sen -- BofA Merrill Lynch -- Analyst

Year-end 2021, you gave us the other one.

Clay M Gaspar -- President and Chief Operating Officer

So as we think about DUCs we end the year at, what was it, 25 to 35 to 40, year-end 2020. And then during the first half of 2021, we would consume what we call DUCs. And remember, we have everybody has a little different definition of it. What we say is anything that's been online for 60 days, above the standard cadence. Yes. So post rig release, it's online 60 days. We put that into a special bucket because that's a little bit abnormal for us. So just that amount of wells, that would be what we talked about at year-end 2020 first half of 2021, we consume that. As far as capital allocation between the two, we're currently running two rigs in the Williston Basin. We'll be going down to one later this summer. And that's preplanned. That's very logical. It was a very strategic part of our Felix acquisition as we wanted an oilier option to complement the Stateline that's in the ballpark of 50-50. And so the Felix being roughly 70% helps us kind of push the oil numbers the way we would like and continue that the oilier overall company distribution. So anyway, I would say one rig for Williston Basin and the balance in the Permian Basin. Between Felix and Stateline, it swings. I can tell you, we really look at it as one big pool. And there's things that we do. We may end up having five rigs on one side and then all five rigs jump to the other side. It's close enough where those mobe costs don't hurt you too bad.

Operator

Our next question comes from Derrick Whitfield with Stifel. Your line is now open.

Derrick Lee Whitfield -- Stifel, Nicolaus & Company -- Analyst

For my first question, I wanted to focus on your capital cost updates on page six. Perhaps for Clay, the last bullet under the current cost environment section suggests there's additional cost downside. Would it be fair to assume you're speaking to the benefit of operational efficiencies in a flat service price environment? And if so, could you speak to the areas where you're seeing the greatest opportunities?

Clay M Gaspar -- President and Chief Operating Officer

Yes. Great question, Derrick. So the you're exactly right. So we didn't assume any move down in commodity price. We're just looking at the strip and saying, as that becomes more fully baked in, some of that is deflationary. I mean some of these the smaller pieces of the overall cost equation kind of come into focus. But some of it is operational. I'd tell you, one of the big things that we see, I've pointed at that $800,000 gap is the on the Felix side, we have yet to ring out the real opportunities. And if you recall, at the time of the announcement, we said we were going to be very thoughtful about not just shifting over, hey, this worked at WPX so surely it works here. And we're finding things that Felix did that we're actually exporting to the Stateline area that worked better, some facilities, things and some other the like. So before we lose that opportunity to really evaluate, we're doing several of these kind of side-by-side tests. Really excited about what happened with this most recent, the Huerfano results. And I think it's a good head-to-head comparison. But we have several more of those, some on the facility side, some on the drilling side. And as we bake those in, you'll see continued downside or downward pressure to that overall cost number in a flat commodity price environment, regardless.

Derrick Lee Whitfield -- Stifel, Nicolaus & Company -- Analyst

Great. And then Clay, just staying on the operations on the Felix acreage. Your first two wells are overwhelmingly positive based on disclosed completion design tweaks. Are they, in your view, representative of what you can attain in the Wolfcamp A across the Felix position? And are there other noncompletion oriented tweaks you'd like to attempt in the coming months?

Clay M Gaspar -- President and Chief Operating Officer

I hesitate to redraw a type curve. I know that, that can be very tempting to just say, OK, here's export this on every single well. We're big believers in experimentation. We need to understand everything from spacing to drilling design, casing designs, one of the things I pointed to, facilities, combining some of this economies of scale. There's a whole lot of knobs on the completion side. This work that we're doing over in the CBR and the Stateline right now will have implications to the Felix area as well. Heck, we'll use the same some of the same logic as we did last time in Williston as well. So some of this kind of cross-pollinate between the basins. But it takes a little time to digest some of that and we're always tweaking and trying to make that next step change improvement.

Operator

Our next question comes from Brian Singer with Goldman Sachs. Your line is now open.

Brian Arthur Singer -- Goldman Sachs Group -- Analyst

A couple of similar topics for my questions. First, on the capex. Now you spent about $500 million in the first half of the year that would seem to imply about a $300 million quarterly run rate for the second half. The maintenance capital for next year implies about $200 million to $215 million of quarterly run rate. Can you take us through the differences in cost structure or activity that will drive this reduction and maybe to follow-up on Asit's question earlier, is the DUCs a unique contributor to temporarily lowering the maintenance capital in 2021?

Clay M Gaspar -- President and Chief Operating Officer

Yes, Brian, I mean, without question, we will benefit from the remaining DUCs in early 2021. But it's the number that we disclosed, ballpark 35 DUCs at year-end, we've been pretty consistent on that messaging. We don't have anything significant baked in on cost structure reductions, although I would point to that as additional upside. The very dynamic nature of 2020 in dropping rigs, dropping frac crews, bringing those frac crews back, make it a little bit hard to track quarter-to-quarter. But what we're projecting into 2021 is a much more a flat capital outlook. Also, it should be noted, with the pullback in activity and our relative growth for 2020, that sets us up with a little bit flatter base decline for 2021. And that's something, if you recall back a couple of quarters ago, we set as a five year objective, is to flatten our base decline. We're really, really proud of the company that we've grown into on the back of some very significant growth years. But what we need to do now is mitigate as we mitigate that growth, the flattening of that base decline really, really helps capital efficiency.

J. Kevin Vann -- Executive Vice President and Chief Financial Officer

Yes. And this is Kevin. As you think about the run rate for the second half of the year being roughly 300 a quarter, you also have to remember, we're trying to arrest the decline that we really created in the second quarter as a result of just curtailing activity and dropping completion crews. So that's why you see a little bit higher level quarter-to-quarter in the back half of this year.

Brian Arthur Singer -- Goldman Sachs Group -- Analyst

Great. And then my follow-up is with regards to the wells that you disclosed here on the Felix acres. The data for those two wells goes through about 60 days. I would have thought that the slowback strategy usually would show at or lower production in early days as opposed to more, which is what you're showing. So the first question is, is there an implication that the delta of well performance should actually accelerate to your benefit in the future?

And then second, and maybe it's part of the question that Derrick was asking earlier. It's hard to draw conclusions from just two wells. Are these wells your in what you would call your best acres, average acres or inferior acres within the Felix block and where within the West and the East business?

Clay M Gaspar -- President and Chief Operating Officer

Great questions. Before I forget, Bryan Guderian just mouthed to me that this was actually the lowest type curve in the acquisition model. So I'll get that out there.

Brian Arthur Singer -- Goldman Sachs Group -- Analyst

For the A?

Clay M Gaspar -- President and Chief Operating Officer

For the A. And so this is I think there's upside from this, but I will say the same thing I said to Derrick. Let's not get ahead of ourselves. This is not the new type curve. These are two wells. We're excited about it, but we need to be thoughtful about how we extrapolate that info. Your first question with regards to the slowback technique, and it's very insightful, good thinking on your part. Remember, what I said is we use the same slowback strategy on both sets of wells, the four Felix, the two WPX. The difference, because we're doing the same choke changes, we're allowing the same kind of back pressure to happen. But what's happening, what it proves is in the case of the WPX wells, that fracture conductivity we made a much more effective stimulation and you're contacting a better connection to the reservoir. It's the same reservoir. These are wells right side by side. So it's not a difference in reservoir quality, but our connectivity. That effective stimulation is just better. And so what that translates into is for the same choke setting, you're just getting more volume through that. And so that volume those step changes that you make, and we're still opening these wells up 50 days in, that's just all the production we have. You just have a better it's a better evidence that you've connected to the rock in a more complete manner.

Operator

Our next question comes from Neal Dingmann with SunTrust. Your line is now open.

Neal David Dingmann -- SunTrust Robinson Humphrey -- Analyst

Rick or Clay, you guys laid out the plan that you've now been able to stick to, and I think the plan now speaks well into 2021. Any could there be any notable changes if we could see a change here or here is something on DAPL in the next one or two weeks as well as potentially if something happens with the political regime in potentially January and the federal permits. Would anything change, do you foresee, in the plan? I know you've got some slides talking about it, it seems like your diffs in the Bakken wouldn't change a whole lot, but I'm just wondering would anything really materially change on the plan if we saw the sort of worst-case of those two scenarios?

Richard E. Muncrief -- Chairman and Chief Executive Officer

No, Neal. We laid it out, I think, pretty clearly, I don't see anything changing. We've assumed almost a worst-case scenario. We've covered that. Think Greg Horne and his team did a really, really nice job, and I think we've articulated what the net impact is to the company at a $0.50 per barrel total company deducts. I think everybody can plug that in their models and see how that impacts us. But we're hopeful that the right decisions will be made. But I think Clay and Kevin's comments just really illustrate that we look at it from a risk management standpoint, and we've made some nice decision, really proud of our team. And so we've minimized the impact, I think. So we'll go from there. We'll see what happens.

Clay M Gaspar -- President and Chief Operating Officer

Yes. Neal, I'll add on to that. So the spot market if DAPL remains open, the spot market will actually come down relative to where it's at. We'll actually recoup a little bit of that $0.50 along the way or maybe even most of that $0.50, who knows how that shakes out. So it's a really interesting insurance perspective, where sort of if the worst-case is you really need the insurance, you spend the $0.50, you're very, very thankful to have it. If you don't need the insurance, you kind of recoup a little bit of that premium, so to speak. The other thing is you mentioned federal acreage. Remember, we have 160,000 in acres in the Permian Basin. We have roughly something less than 30,000 acres exposed to federal lands and a fair amount of that is non operated. So I think we sit in a really good position in that regard. And it's something to consider as we think about, as you roll forward in the election process.

Neal David Dingmann -- SunTrust Robinson Humphrey -- Analyst

Okay. And then just one last one. You guys have been even last year when you thought about buying some stock back and different things, you guys are really you look at it in a really quantitative way. And I'm just wondering, again, if prices start to go back up and you get you're able to pay and basically get debt down to a comfortable level. I'm wondering, Rick, for you, Clay, Kevin, when you think about it, would the next step be more on shareholder return? And I know like this morning, Concho talked about a potential variable dividend. Kind of what do you see as potential options at that point?

Richard E. Muncrief -- Chairman and Chief Executive Officer

Yes. I think for us, Neal, the first thing will be, obviously, on shareholder returns. And I would say we would lean more toward implementing the dividend. That's something that really we're probably on the verge of doing. We debated it quite a bit at the Board level. And it just felt like the prudent thing was just to give it a little bit more time in our cash flow certainties. And I think even since our last Board meeting, we've come a long way. So I think that's the first thing. Recall that we really don't have any near-term debt due. So I mentioned $240 million due in 2023. And Kevin and his team did a masterful job, I think, in placing some new debt, turning it around and then reshaping some of those towers. The reality was is that our bonds are trading at really strong. And it was end of the day, it was not the economic decision to spend that last $100 million or so at this point in time. So we'll see how it all plays out, but that's near term, I think dividend initiation. And then obviously, if you have some help with commodity prices down the road, that's something we've kicked around here internally as well is something along the lines of a variable dividend as well. So I think just point blank, that's kind of where we're at.

Operator

Our next question comes from Charles Meade with Johnson Rice. Your line is now open.

Charles Arthur Meade -- Johnson Rice & Company -- Analyst

Rick and Clay, and to the rest of the team there, I wanted to ask a question about the Bakken or the Williston, first off. And I appreciate that you guys have got out there and put your insurance in place. And I like that terminology you use. But I'm curious, at some point, do you reach the position where just the insurance or the need to buy insurance to continue the metaphor that just becomes too much of a nuisance and it reduces your appetite to be exposed there? And presumably, there is some points at which it becomes too much, but how close to you are that right now?

Richard E. Muncrief -- Chairman and Chief Executive Officer

I think, Charles, the way we look at this is we still have got some really nice inventories. As deep as we'd like? Probably, honestly, no. But that being said, it's going to generate a lot of free cash for us and for several years to come. And so I think we're quite ways away from even considering something like you're asking about. We're we like the asset. It's going to generate a lot of free cash. As I mentioned, it's been really somewhat core to our performance over the last few years. And we'll see how that all plays out. As far as the insurance cost, if you will. The reality is there's only about 10 rigs running in the Williston Basin today. And so when you start thinking about the decline of the basin, even with some resumption of some completion activity. It's very, very measured. You're probably not going to see much of a rig increase up there until we get sustained $55, $60 a barrel. And so for us, we think that if you've got a nice production profile coming out of a basin like that, I think there's going to be possibly some upside to that differential actually pulling back in as supply continues to decline up there. We'll see how that plays out.

Charles Arthur Meade -- Johnson Rice & Company -- Analyst

That's a great point about the overall activity in the basin. My follow-up question is around the your completion sequencing or cadence in the back half of the year. You guys have been really explicit and I appreciate the way that you guys have laid out when those completion crews have gone back to work. But I wonder if you could just give a little bit more color on the one connection piece between when the crews go to work, and when you actually bring the wells online. And what I'm really kind of trying to get toward is if there's a if you've got a number of large pads, then maybe even though you brought on a couple of completion crews here in July and you're going to bring another one on toward the end of 3Q, if those are all working on big pads, we might be looking at production troughing maybe in October. Alternatively, if you're going to have a couple of quick hits right off the bat, maybe we're looking at kind of production trough in the end of August. So what kind of color can you add in that regard?

J. Kevin Vann -- Executive Vice President and Chief Financial Officer

Yes. It's a good question, very perceptive because the base decline is real. And any of the basins, these resource play basins, you stop drilling or reduce the rig count tremendously, and boy, the production levels really start to fall. And we're certainly not immune from that. We've never shied away from our base declines. When you run the math through that, you stop completing. That base decline takes over for a period now, as we mentioned in the prepared remarks, we brought back a completion crew in the Williston and one in the Permian, both in early July. Those the production from that would really come sometime, I would say, second half of August that we'll see production from both. And so what we've seen up to that point is you have your base decline. Our production engineers are working exceptionally hard to mitigate that base decline, doing a lot of things to try and enhance production in a low-cost environment. Specifically in the Williston Basin, we had the curtailments that we've talked fairly thoroughly through, and we're bringing those wells back online. So those guys are pretty busy bringing that production back online. So it's pretty dynamic. But to answer your question pointedly, for the first two frac crews, they're kind of they came in first half of July. The production will really manifest second half of August that's somewhere between four and six weeks, and that includes all the completions, all of the drill outs. And in the case of the Stateline frac crew, the other science that I mentioned in my prepared remarks.

Operator

Our next question comes from Gail Nicholson with Stephens. Your line is now open.

Gail Amanda Nicholson Dodds -- Stephens Inc. -- Analyst

I'm just kind of curious, can you guys talk about how you're foreseeing LOE looking in the second half of 2020? And more specifically, how you think LOE really exits 2020? And what's a good run rate to use in 2021 forward?

Clay M Gaspar -- President and Chief Operating Officer

Yes. Thank you, Gail. The it's interesting. When challenging times come, your best teams really respond to it, and there's always another level of engagement and another level of creativity. And I think we've benefited from that. We were on a downward trajectory over the last few years, really working LOE but in some of the ways we kind of we had stalled out on maybe the creativity and maybe the desperation, maybe a different term. Boy, when commodity price fell as much as it did, the message was delivered very effectively to the team that man, we need to get really creative, we need to get very aggressive. You saw that in the second quarter numbers. I would say the only thing that's clouding the second quarter is, at the same time, we reduced the number of workovers. So thinking about the third quarter, the first half of that, some of the creativity around, we can do this ourselves, we can be more efficient. Some of those things will really stick and you'll see that improvement translate over. The cloudy part will be that we have a normal cadence of workovers. And then as we bring these wells back, you have an additional level of workover. So we may try and parse that out in the third quarter, so you get a better run rate. But I think the initial guidance for the year, I'm feeling very good about that, maybe even encouraging toward the downside for the annual run rate. And then as we push forward into 2021, I foresee additional improvements from there.

Gail Amanda Nicholson Dodds -- Stephens Inc. -- Analyst

Great. And then just looking at the well costs, you guys have made very impressive improvements on those 2-mile lateral per lateral foot cost. Can you just talk about the delta between what a 2-mile lateral per foot cost there versus a 1.5-mile lateral per foot cost? And then how do you envision lateral length trending in 2021?

Clay M Gaspar -- President and Chief Operating Officer

Yes. So it's interesting, Gail, it's a number that varies over time. I remember at one time, we were on the 2018, I think it was even maybe $1.5 million delta per half mile. That was on the high side. I think as you compress down, it probably compresses to maybe $0.5 million on the low side when things are really, really tight. So if you're approaching, say, $7.5 million well for a 2-mile well, it may be $6 million to $6.5 million on the 1-mile well. And then obviously, the 1.5 is somewhere right in between. All those numbers start to compress, but you still have some basic fundamental costs that are not variable that you can't compress any further.

Operator

Our next question comes from Leo Mariani with KeyBanc. Your line is now open.

Leo Paul Mariani -- KeyBanc Capital Markets -- Analyst

Wanted to follow-up a little bit on shut-ins. I think you guys did a good job quantifying around 20,000 barrels a day here in the second quarter. Just wanted to get a sense if you guys might be able to quantify that number in the third quarter? Just from your prepared comments, it sounded like there were some lingering shut ins here in July.

Clay M Gaspar -- President and Chief Operating Officer

Yes. Leo, we've been very measured on bringing them back. It's one of these things where you stack up a whole lot of work, and then you bring back your best, most reliable workover crews and the companies we prefer to work with and then when there's excess work above and beyond, the question is, how much further do you go? If we normally have a background of three or four workover rigs, we're going to run it five or 6, we're going to run at seven or eight to accelerate that quicker. We've elected to kind of the five or 6. And so that's brought us back to a certain cadence. I would say we're most of the way there. Certainly in the Permian, we've cleaned everything back up. In the Williston, I would say, by maybe the tail end of August, we should be kind of fully back to a normal run rate, which includes normal downtime for offset wells. And of course, you still have pumps failing in just the normal background of operations that we keep up with. So I would say, if you think of it as the second quarter being the numbers we articulated and then you kind of translate that maybe halfway through the third quarter. You got kind of that wedge coming back. I think that could probably get you in the right direction. And maybe, Dave, he can work through that if you follow-up with him on a call.

Leo Paul Mariani -- KeyBanc Capital Markets -- Analyst

Okay. No, that sounds good. I think you guys have done a good job kind of articulating the maintenance case at $40 WTI into next year where it certainly allows you guys to have free cash flow. I just wanted to really get a sense of what would happen if we see meaningful higher prices if we got up to say that $45 level? Is that an area where you guys would feel comfortable putting some growth back into the business going forward?

Richard E. Muncrief -- Chairman and Chief Executive Officer

Leo, that's a good question. Really where we're at today, I think you'd have to be closer to the a sustained $50 before we really think about upping our growth just a little bit more. You just have to think about what we and virtually every other management team has been faced with the last few years, and that's we've had several head fakes where you start seeing rising commodity prices as you get back to work and only to see it pull back for one reason or the other. So I think it would be a very tempered a very moderate approach to that. We'll have to have some time to get up to $50. If it's in that $45 range, we'll probably just hold everything pat, stack a little more free cash and do that and be in a nice position. We do have about 40% of our volumes hedged for 2021. And so that leaves quite a bit of upside to for us in the event that you see $50, $55, $60 crude, which is not out of the realm of possibility. We'll see how that all plays out.

Clay M Gaspar -- President and Chief Operating Officer

Leo, I just might add one point to that. That's part of our downshifting strategy as well throughout 2020 is to make sure that we didn't need to reverse course very aggressively in the case of a quickly rebounding commodity price. It's quickly rebounded to $40, it seems like it's found some kind of some stationary movement there. And then once we see the next if it does move to $50, $55, then I think we could see some overall activity kick up, but it will be easier for us to do from the situation from where we sit today to take that next step.

Operator

Our next question comes from Jeff Grampp with Northland. Your line is now open.

Jeffrey Scott Grampp -- Northland Capital Markets -- Analyst

I had a question for you on the maintenance capex program for 2021. And specifically kind of honing in on the Bakken with the one rig that you'll be exiting at. Is that do you think that's sufficient to keep production kind of flat? And in other words, should we think about both basins kind of being in maintenance mode? Or is it more some Permian growth and then Bakken declines a little bit, so on corporate, it's kind of maintenance mode?

Richard E. Muncrief -- Chairman and Chief Executive Officer

Yes. I think you'd be looking at a little bit of growth, certainly, the early part of 2021. And then the reality is with one rig. And if we did get caught up with all of our completions in certain and Clay can manage all that, you may start to see just a modest decline at that with one rig scheduled. But we have a team pretty talented at coming up with creative ways of managing that base decline and production will shift, that's how it works. But I think that's probably what the shape would look like.

Jeffrey Scott Grampp -- Northland Capital Markets -- Analyst

Okay. Great. And another question on the cost side. I know we've talked on that a bit already. But referencing that Slide six again. Depending on kind of your reference point, it looks like, let's call it, 10% to 15% plus type of reductions, looking at that second half number. Is there a way to, I guess, kind of quantify what of that is sticky and kind of internally driven versus just kind of service pricing concessions that might get clawed back at some point in time?

Clay M Gaspar -- President and Chief Operating Officer

Well, we we know that commodity or excuse me, service cost moves, and it will have to move in a $45 to $50 world. But I think there's a lot of what we've what we have moved the needle on the Felix side is less about service costs and much more about just some changes operationally. And certainly, the a lot of the additional upside that we see, for example, that $800,000 that we're seeing today really for the second half of the year between Stateline and the Felix assets, that's not deflation. That is just opportunities on how do we kind of just claw that a little bit back, probably $50,000 at a time and continue to make progress there. So I would say that the specific point that you referenced, first half of 2020 to second half of 2020, maybe it's 1/3 deflation and 2/3 changes in operational philosophy.

Operator

Our next question comes from Will Thompson with Barclays. Your line is now open.

William Seabury Thompson -- Barclays Bank PLC -- Analyst

So this has been touched upon, but maybe I'll ask more directly. To the extent you can share, how many net TILs are baked in the 2021 program? It sounds like there's some prespend in 2020 that benefits 2021, but also it sounds like you still carry some level of DUCs heading into 2022. And I believe last quarter, you talked about base decline challenges at high 30s versus mid-40s this year. And I think I think where people maybe struggle is just you're bringing on a lot of flush production later this year. So maybe you can help us understand the base decline mix between Stateline, Felix and Williston. I guess it's a multifaceted question, sorry.

Richard E. Muncrief -- Chairman and Chief Executive Officer

Back to the first question, I just want to make sure I understand it. Were you asking about the number of net...

William Seabury Thompson -- Barclays Bank PLC -- Analyst

The net TILs in 2021.

Richard E. Muncrief -- Chairman and Chief Executive Officer

TILs? I thought you said sales. Okay.

Clay M Gaspar -- President and Chief Operating Officer

In 2021, probably in the 110, 120-ish.

Richard E. Muncrief -- Chairman and Chief Executive Officer

I would recommend, Will, that you circle back with Dave after this call, and let's get some because that's a multi-faceted question you asked. Let's make sure that we do some good work on that for you, and you can get it in your model right.

Clay M Gaspar -- President and Chief Operating Officer

And one thing I would just caution is we're talking about maintenance capital, clearly, that's not we're not at the point where we're ready to issue guidance. Directionally, we've given enough information so that you can appreciate kind of where we're ending the year, how the base decline flattens, supplementing that with some new wells. I think it's pretty rough numbers right now. We're probably not going to get into details of TILs, even on a per quarter basis. I think that's a little bit pre-emptive.

William Seabury Thompson -- Barclays Bank PLC -- Analyst

And then, Clay, in terms of the CBR project in the eight distinct zones you highlighted, you guys have argued that WPX clearly has ample Stateline well inventory so and correct me if I'm wrong, I believe WPX had pivoted to maybe three target zones in Stateline starting late 2018. Obviously, the Pecos State project continues to pay dividends as we've seen with the recent Felix well results. But maybe I want to ask how you think about how this project could change your development program and how WPX views optimizing returns versus NAV?

Clay M Gaspar -- President and Chief Operating Officer

Yes. Well, I think state of the art for all of our areas and Stateline is no different, is we think about it in terms of what's hydraulically connected. And what we want to make sure and do, let's say, we believe that the X/Y, upper A, lower A and maybe even the B, are hydraulically connected. We don't want to go in and drill up the upper A and then six months, a year, two years, three years later, come back and try and reach that X/Y or that lower A because now it's partially depleted and really, you're going to have very ineffective completions. So part of this study is to really understand and map the fracture growth and how it's how things are growing. When you're stimulating, say, the X/Y, how much of the Third Bone are you really touching? When you're in the Third Bone line versus the Third Bone sand, is there interaction there? When you're in the different landing zones of the Third Bone line or even the Second Bone, what's the interaction there?

And so I think the most important information we're getting is a really a much better picture on what is the hydraulic connection. And so when we go in, and we're talking about the three zones that we're really focusing on, typically, that's upper A, lower A and X/Y or upper A, lower A and B, depending on where you're at, kind of in that in our legacy position.

But we've also talked very excitedly about the potential for the Third Bone Springs. Specifically in the line. And we have we've tested now at least three landing zones there and another one in the sand. And what we're trying to figure out is what's the right hydraulic connection there? Do we go in with three landing zones? Or is it 4? Or maybe it's 2, to really effectively stimulate that and not leave ourselves a partially drained another landing interval that we've essentially condemned in the process. So very importantly, we're all the way up into the second bone looking at an opportunity there all the way down to the D, looking at an opportunity there. And as I mentioned, every one of these zones, in today's commodity price, actually deliver a favorable return. And so what we want to understand and it's beyond the scope of the Pecos project, but this project is really focused on really understanding that vertical connectivity and how big a bite do you take at one time.

Operator

Our next question comes from Gabe Daoud with Cowen. Your line is now open.

Gabriel J. Daoud -- Cowen and Company -- Analyst

Just a quick clarification, and sorry if I missed it. So the $800 million to $850 million of capital for next year. Did you say that in the Permian, that assumes the $800 per foot expected well cost for the back half of 2020? Or does that assume the $871 per foot in D and C?

Clay M Gaspar -- President and Chief Operating Officer

Yes. We kept the $800 flat, the second half of the year number all the way flat through next year as well. Again, assuming a flat commodity price. Personally, I think there's upside to that number, but we're not fine-tuning that just yet. It's just a directional look.

Operator

And our last question comes from Matt Portillo with TPH. Your line is now open.

Matthew Merrel Portillo -- Tudor, Pickering -- Analyst

This is probably a question for Clay. I was just curious as you've kind of improved your landing targeting and also spacing design, how that's evolved around the Stateline acreage? And any context that you might be able to provide on some of your upspaced wells around Stateline in 2020 versus maybe some of the tighter space wells that you might have been running in 2019 and before that time frame? Just trying to get a better sense of the rate of change on the productivity and the recovery on those wells.

Clay M Gaspar -- President and Chief Operating Officer

Yes, Matt, I appreciate the question. Remember, as you well know, the wells that come online in 2019 are really kind of on the drawing board maybe early 2018. There's probably a 12, 16-month lag from when we conceptualize it to when it's actually producing, just getting in the queue and all. So what we've seen is a steady progression, we have up space. I'd say state of the art is probably four or five wells per landing zone in the Stateline area. And we're really excited about what that material uptick in those wells' productivity really means. 2019, we had a mixed bag, some at 6, some at five that we were testing. We probably had a four in there, somewhere along the way, maybe latter part of the year. But we're definitely seeing I mean, that correlation is true. And so it's an interesting knob, and it ties back to commodity price. In a $65 world, AKA 2018, you might have a little different recipe to optimize value, optimize return than you would in 2019's pricing or certainly in today's pricing. So we're trying to monitor that. We've offered guidance to the technical team to think a little bit longer-term about how we see commodity price, not just running today's strip, but these wells, these decisions we're making, really implementing today's decisions in late 2021. We need to understand what's the right recipe. We're seeing that correlation. We're excited about that. And we're also getting a better understanding from the latest project into that the vertical connection as well, which is equally important.

Richard E. Muncrief -- Chairman and Chief Executive Officer

Folks, we appreciate your time today, and we just ask that you stay safe and stay positive. Take care. Have a good week.

Operator

[Operator Closing Remarks]

Duration: 65 minutes

Call participants:

David Sullivan -- Director, Investor Relations

Richard E. Muncrief -- Chairman and Chief Executive Officer

Clay M Gaspar -- President and Chief Operating Officer

J. Kevin Vann -- Executive Vice President and Chief Financial Officer

Greg Horne -- Vice President of Midstream and Commodity Marketing

Asit Kumar Sen -- BofA Merrill Lynch -- Analyst

Derrick Lee Whitfield -- Stifel, Nicolaus & Company -- Analyst

Brian Arthur Singer -- Goldman Sachs Group -- Analyst

Neal David Dingmann -- SunTrust Robinson Humphrey -- Analyst

Charles Arthur Meade -- Johnson Rice & Company -- Analyst

Gail Amanda Nicholson Dodds -- Stephens Inc. -- Analyst

Leo Paul Mariani -- KeyBanc Capital Markets -- Analyst

Jeffrey Scott Grampp -- Northland Capital Markets -- Analyst

William Seabury Thompson -- Barclays Bank PLC -- Analyst

Gabriel J. Daoud -- Cowen and Company -- Analyst

Matthew Merrel Portillo -- Tudor, Pickering -- Analyst

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