QEP Resources (QEP) Q2 2019 Earnings Call Transcript

QEP Resources (QEP)
Q2 2019 Earnings Call
Aug 07, 2019, 9:00 a.m. ET

Contents:

• Prepared Remarks
• Questions and Answers
• Call Participants

Prepared Remarks:

Operator

Greetings. Welcome to QEP Resources second-quarter 2019 conference call. [Operator instructions] Please note, this conference is being recorded. I will now turn the conference over to your host, William Kent, director of investor relations.

Thank you. You may begin.

William Kent -- Director of Investor Relations

Thank you, David, and good morning, everyone. Thank you for joining us for the QEP Resources second-quarter 2019 results conference call. With me today are Tim Cutt, president and chief executive officer; and Richard Doleshek, executive vice president and chief financial officer. If you've not done so already, please go to our website, qepres.com, to obtain copies of our earnings release, which contains tables of our financial results along with the slide presentation with supporting materials.

In today's conference call, we'll use certain non-GAAP measures, including EBITDA, which is referred to as adjusted EBITDA in our earnings release and SEC filings, and free cash flow. These measures are reconciled to the most comparable GAAP measure in the earnings release and SEC filings. In addition, we'll be making numerous forward-looking statements. We remind everyone that our actual results could differ materially from our forward-looking statements for a variety of reasons, many of which are beyond our control.

We refer everyone to our most -- more robust forward-looking statement disclaimer discussion of these risks facing our business in our earnings release and SEC filings. With that, I'd like to turn the call over to Tim.

Tim Cutt -- President and Chief Executive Officer

Thank you, Will, and good morning and thank you for joining the call today. I'll begin the call with an update to the strategic alternatives process before providing a brief operational update and a first look in our 2020 business plan. As you read in our second-quarter earnings release this morning, we have concluded our comprehensive review of strategic alternatives. And the board has determined the best value for shareholders is to move forward on a stand-alone basis.

As you are likely aware, the current market conditions have significantly impacted the ability of many counterparties to transact at these levels that would deliver appropriate value for our shareholders. While I will primarily focus today's commentary on our performance and go-forward strategy, I will first share a few remarks about the review process itself. Upon receiving an unsolicited proposal to acquire the company in January, we engaged in a review of a wide range of strategic alternatives in an effort to maximize value for shareholders. Without getting into granular detail, since we launched this strategic review process in February 2019, our board of directors met numerous times and with the help of a team of experienced financial and legal advisors have viewed a range of potential transactions.

Ultimately, with today's market dynamics coupled with the strength of our operations, both in the Permian and the Williston Basins, our board determined that the best path to create long-term value for shareholders is as a stand-alone company, executing our new strategic plan. As we evaluated opportunities, it was apparent that none of the potential transactions recognize the intrinsic value of our assets. And we believe that with our new strategy, we can optimize these assets to deliver long-term value to our shareholders. With that, let's talk about the go-forward strategy.

As a stand-alone company, we are laser-focused on generating free cash flow, strengthening our balance sheet, and returning capital to shareholders. We are confident in our ability to deliver on those commitments as a result of the improved performance and deliverability of our high-quality, oil-dominant asset base, a significant decrease in drilling, completion and facility costs, as well as the successful and sustainable reduction of corporate overhead in the first half of 2019. Since coming onboard with QEP in January, I've been keenly focused on reducing corporate overhead and the capital intensity of the business. As a result of actions taken during the first quarter, G&A expense dropped by $32 million in the second quarter, a decrease of 50% compared to the first quarter, keeping us on track to deliver on our goal of reducing normalized expense by approximately 45% between year-end 2018 and 2020.

We have implemented the majority of the planned reductions in G&A expense and are confident that we'll be able to deliver our sub-$3 per BOE target for 2020. Despite these significant reductions, we believe that we have retained a highly talented technical business and operating team, as well as the necessary systems, controls, processes and infrastructure to successfully execute our future plans. Our operations teams continue to deliver continuous improvement on both cost and efficiency front, which is positively impacting cycle time and capital efficiency. As a result of this work, drilling, completion, and facility costs have continued to decrease, and we have confidence in our ability to deliver producing wells for approximately $1.5 million less in -- less than in 2018 in the Permian Basin.

Our average drilling fleet cost is now below $6 million per well for a 10,000 foot lateral with drilling time from spud to TD averaging less than 12 days. Our ability to treat produced water and deliver high-quality frac water low cost represents another opportunity to create value for our shareholders through the generation of additional cash flow through third parties. We're in the process of evaluating partnerships, opportunities and work with water companies to recover invested capital and to leverage their water-gathering expertise. We expect to provide some clarity on this in our next update call.

We expect to further reduce overhead and operating costs moving forward by leveraging the continuous improvement mindset that the organization has adopted. Given the reduction in G&A, improvements in capital efficiency, and our improving well in DSU performance, we now have a clear line of sight to a runway of free cash flow generation going forward. I'll now turn my comments to our operations in the quarter and a brief look into 2020. I'm pleased to report that operational performance during the second quarter in all categories was in line with or better than guidance.

Oil and condensate production in the Permian Basin increased by 12% quarter over quarter. Permian gas sales were also higher than forecast due to the addition of midstream facilities, primarily compression, which improved our ability to capture natural gas from the wells and reduced the need to flair. QEP remains confident that the tank-style development is the best method to develop our acreage in the Midland Basin. While the E&P industry continues to debate the best development approach, we believe that our results confirm that this methodology is the most effective and efficient way to develop our acreage when implemented using proper spacing assumptions and completion techniques.

The DSUs completed in 2019 drilled on a go-forward spacing assumptions are currently producing on or above their predictive production profile, enabling us to stay slightly ahead of our volume plan. We have released the third rig in the Permian and plan to move forward with a two-rig program into 2020. Our future development plan initially develops the issues in the derisk areas of County Line in 2020 before returning to Mustang Springs in 2021. We expect to complete between 60 and 65 wells in 2020.

The two-rig program will allow us to grow oil production between 2019 and 2020 by approximately 8%. Our plan develops from approximately 6% of our inventory in 2020 and delivers a compound annual growth rate over five years of greater 5%. Under this plan, the Permian generates cash flow moving forward above $50 oil price. Although current market conditions are not supportive, the plan retains flexibility to grow the Permian by up to approximately 15% per annum with the four-rig program.

Finally, on the Permian. We are very encouraged by the results of recent offset operator activity around the Robertson Ranch acreage, and we look forward to developing this area in the future. Now on to the Williston. Our Williston Basin assets continues to provide cash flow during the quarter despite the anticipated decline in production.

We expect the forecasted quarter-to-quarter production decline will be reversed when the seven new Vegas wells are put on production early in fourth quarter. Drilling activity in the Vegas pad is not finished, and we will begin completing these wells in early August. As we have continued to evaluate the performance of our refracs in the Williston, we have changed our philosophy regarding drilling infill wells on South Antelope. We now believe that refracking existing wells is the most economical way to develop the remaining reserves on South Antelope while the combination of new wells and refracs on our acreage on the Fort Berthold Indian Reservation is the best way to proceed there.

We have identified approximately 100 remaining drilling locations, primarily in Fort Berthold, and more than 100 high-quality frac candidates split evenly between South Antelope and Fort Berthold, all delivering strong economic returns down to a $50 oil price. It is also important to note that there is significant upside to this inventory count, depending on the commodity price environment. We're excited to execute a balanced refrac and drilling development program over the next several years, and we expect the Williston to continue to be a strong cash flow generating asset for the next 10-plus years. The Williston Basin 2020 development plan will allow us to maintain flat annual production compared to 2019.

We anticipate being able to maintain relatively flat production for the next seven years with an annual capital budget of approximately $135 million to $165 million per annum. With that high-level overview of recent performance and our forward plans, I'll turn the call over to Richard to discuss our financial performance.

Richard Doleshek -- Executive Vice President and Chief Financial Officer

Thank you, Tim, and good morning, everyone. I'll quickly give you some color on the second-quarter results, update our 2019 guidance, and add some additional thoughts around our 2020 plans before we open up the call for Q&A. In the second quarter of 2019, we generated $166.5 million of adjusted EBITDA. A higher adjusted EBITDA compared to the first quarter is reflective of, among other things, lower G&A expense, LOE, transportation and taxes, and higher field-level prices, which were up $3.69 per BOE compared to the first quarter.

For the second quarter, we reported net income of $49 million, driving net income with a $55 million unrealized gain associated with our commodity derivatives portfolio. At the end of the second quarter, the derivatives portfolio has a net liability of $1 million, compared to a net liability of $55 million at the end of the first quarter. In addition, we reported an $18 million gain on sale primarily related to the Haynesville Cotton Valley. We can see the interesting commodity derivative contracts during the second quarter.

And as of June 30, we hold contracts, excluding basis swaps, totaling 14.6 million barrels of oil, which covers about 67% forecasted 2019 oil production and up 31% forecasted 2020 oil production. With regard to our balance sheet. At the end of the quarter, total assets were $5.5 billion, shareholder equity was about $2.7 billion, and total debt was approximately $2.1 billion, of which -- all of which was our senior notes. We had nothing outstanding under our revolving credit facility and had $97 million of cash at the end of the quarter.

Excluding cash, we have the ability to incur about $550 million of additional investments at the end of the second quarter. In terms of 2019 guidance, there are several updates. With regard to overall production guidance for the year, based on better recent well results and improved gas recoveries in the Permian Basin in the first half of the year, we are increasing our overall production guidance to a range of 29.9 million to 31 million barrels of oil equivalent, a 4% increase at the midpoint of our previous guidance. We are increasing oil guidance for the full year to a range of 21 million to 21.5 million barrels, an increase of 250,000 barrels at the midpoint despite the divestiture of several noncore assets in the Williston Basin that were forecasted to contribute approximately 150,000 barrels for the last seven months of 2019.

We are increasing our guidance for natural gas lines for 2019 to a range of 28 to 30 Bcf, a 9% increase at the midpoint of our previous guidance, which reflects our improved natural gas capture rates in the Permian Basin. Finally, our guidance for NGL volumes for 2019 is increased to 4.25 million to 4.5 million barrels, an 11% increase at the midpoint from the previous guidance. The team's significant strides in cost reductions and improved efficiencies positions us to lower our 2019 capital guidance by $50 million at the midpoint. In addition, we are lowering our 2019 G&A guidance by $5 million at midpoint.

There's additional detail about our guidance in our earnings release. As Tim mentioned, the company's 2020 plan is structured to be cash flow positive at $50 oil. We expect that the development plan will deliver approximately $120 million of free cash flow at the $55 oil and approximately $185 million of free cash flow at $60 oil before the expected tax refund of $37 million. At $55 oil, our free cash flow yield is expected to be around 10% based on a $5 share price.

Our ability to generate free cash flow enables us to improve our balance sheet and complementary return capital to shareholders. We're extremely pleased to announce the reinstatement of the quarter dividend at $0.02 per share, which represents a dividend yield of 1.6% based on a $5 share price. In addition, we expect to fund the $52 million of senior notes that mature in March 2020 with cash in the balance sheet. Clearly, the expend of free cash flow generated will be dependent on the price of oil.

But even with the dividend payment in our senior notes within next year, we have sufficiently decreased our cost structure in such that we expect to be cash flow positive in 2020 at $55 oil price, allowing us to further strengthen our balance sheet. I'll now turn the call back to Tim to provide a brief summary before opening up the call for questions.

Tim Cutt -- President and Chief Executive Officer

Thanks, Richard. In summary, we're committed to delivering a low-cost, highly competitive investment opportunity through our high-return development program in the Permian Basin and the execution of a selected drilling and refrac program in the Williston Basin. We believe that the combination of our high-quality assets with the strength of our operations teams will allow us to deliver on this commitment. Our concerted efforts to reduce corporate overhead and field-level expenses have soundly positioned the business to deliver free cash flow with a competitive yield to our investors and return capital to shareholders through our dividend program and repayment of debt.

Our team has delivered outstanding performance during the past six months while we have been reviewing the strategic alternatives. And I want to thank each of them for their patience and commitment as we work through this process. I'm enthusiastic about the bright future ahead and look forward to sharing our ongoing progress on the execution of our new strategy and results in the months ahead. We'll now turn it over to questions.

Questions & Answers:

Operator

Thank you. [Operator instructions] Our first question is from Gabe Daoud with Cowen and Company.

Gabe Daoud -- Cowen and Company -- Analyst

Good morning, everyone. I was just maybe curious on the dividend and just kind of how you balanced that with leverage, and then also just the longer-term plan through 2020. And with the commodity still being kind of volatile, I guess, maybe just discuss a little bit about your comfort level in reinstating the dividend, and then how you balance that with the plan through 2021.

Richard Doleshek -- Executive Vice President and Chief Financial Officer

Gabe, it's Richard. I think the dividend is a tangible demonstration of our confidence in the ability to generate free cash flow. And in terms of returning capital to shareholders, you're right, the commodity is volatile. We've got about 70% of our production covered for the rest of this year, about 45% covered so far for next year.

That gives a solid foundation to generate that free cash flow. It just felt like it was the right thing to do in terms of, again, a tangible demonstration of our confidence in generating free cash. We've got plenty of cash to fund, maturity is coming due in March, and we'll continue to "organically delever" if -- even if we don't do anything on the liability management front.

Gabe Daoud -- Cowen and Company -- Analyst

Got it. Got it. OK. Richard, that's helpful.

And then, I guess, with the review process complete, just I guess how does that impact your thinking just in terms of the Permian water infrastructure asset? Is that still like potentially represents a divestiture candidate? And then also I guess just sticking to the Permian, so the water question -- the water asset question. And also just sticking to the Permian in terms of spacing some of those DSUs that you highlighted, does that represent the appropriate spacing as you think about development moving forward?

Tim Cutt -- President and Chief Executive Officer

Yes. I think I'll take the first one -- the last one first. So the spacing, I think we're dialing in not only in Mustang Springs, but also over in County Line. So the spacing we've represented there for now are what we believe is -- are appropriate.

Good news is, some of the other sands like the Jo Mill and the Dean are showing very positive results. And so I don't want to preclude going to a little more downspacing on some of those. But in the main bodies of the Wolfcamp A, the Wolfcamp B in the Spraberry Shale, I think we're getting that, plus or minus, about right. On the water infrastructure, we're pretty excited about that.

For a fairly small company, we've got a good size infrastructure. We're processing water lower than most. And so there's a big margin there. If you can bring water -- more water in the system, upsize it a little bit and then turn it back out and sell back -- frac water -- clean frac water back out to the market, I think there's a good cash flow opportunity.

So we're looking at the best way to leverage the assets. Those infrastructures are selling for a pretty high premium, and so we'll obviously take a look at that. But we think a balance between keeping a very low LOE, keeping our frac costs down and doing all that maintain some control there but partnering with a company that's much more skilled at gathering water and signing up those contracts, working with us, we can process it, we can move it, but I think that may be, ultimately, what we decide to do. So we're hoping the next quarter, we get all that buttoned up and we're able to give an update next quarterly update.

Gabe Daoud -- Cowen and Company -- Analyst

OK. Great. That's super helpful. Thank you, Tim.

And I'll just -- I'll sneak in one more, if I could. Just on the rig allocation in 2020, just I guess with the focus on County Line, is there any particular reason why it may be moving away from Mustang Springs? And then what about the Robertson Ranch acreage block, is there any thoughts on when development could start there?

Tim Cutt -- President and Chief Executive Officer

Yes. So on County Line, the only reason we're going over there is we do have some obligation drilling with our university lands. We're excited to get back there. I mean, the Spraberry Shale in County Line is probably one of the best horizons we have to develop.

We can develop that at a bit higher density, and so we're -- we look forward to getting back over there. We were in a really good stopping point. If you look at kind of our maps, we kind of finished the tank at the end of a road with the DSU 12, and so it's a really good stopping point. So this will give us a chance to kind of look back at all the data, come back in the year and get after that again.

Robertson Ranch is pretty interesting. We -- obviously, we're super excited about it when we bought it. Now all -- we have a lot of offset operations going on and each of the horizons are showing really strong results. So we're going to be gathering all of that outside information and we're anxious to get down there.

I mean we've got a pretty big inventory. It takes us a little while to get down there, but we're contemplating doing individual test wells or potential DSU tests in the future, but we're probably a couple of years out from being down there.

Gabe Daoud -- Cowen and Company -- Analyst

OK. Great. Thanks again, Tim.

Operator

Our next question is from Neal Dingmann with SunTrust.

Neal Dingmann -- SunTrust Robinson Humphrey -- Analyst

Good morning, guys. Say, I was just wondering, Tim, if you could address -- you guys are doing a nice job there with costs and efficiencies getting closer to free cash flow. So my question would be, how you address the sustainability of the free cash flow given the tank-style development that you all plan in the Permian?

Tim Cutt -- President and Chief Executive Officer

Yes. I mean, I think that really does have to sustain it. I mean when you look at our drilling and completion costs and speed of drilling, it's really nothing to do with tank style. We can get these things in place at low cost and cheaply.

Where we have a real advantage on the tank style from a cost perspective is on our facilities. So we're no longer going to complete these to where we go across the road, turn a corner, and come back. We're going to do this more in a typewriter style, doing a set of DSUs across, coming back to the other side, and going across. As we do that, we -- we're able to use the facility as we've developed on the previous DSUs when we come back just below it.

So one of our DSUs -- recently, we had up to 57 wells that we're able to access a single DSU facility. So I think that's a very efficient way to do that. So I'm -- I think the tank-style actually helps us maintain that efficiency and keep the cost down. And we've done a lot in the last seven months.

I think there's more to come. The teams are motivated. We -- everybody understands the need to deliver the cash. And so I think the tank style just enables us to carry forward.

I think Richard has [Inaudible]

Richard Doleshek -- Executive Vice President and Chief Financial Officer

Yes. And Neal, as a follow-up, if you go back to Tim's comment about the well cost at $6 million in the Permian, that's round numbers about $1.5 million cheaper than we were growing before. If you think about 60 wells at $1.5 million cheaper, that's $90 million of incremental free cash right there. The G&A reduction, that's around number $70 million.

That begins to tell you how sustainable that free cash flow is. So we're very confident to generate free cash flow, as we said in the prepared remarks, all the way down to $50 a barrel. And it's a -- through a combination of what we've done with regard to the drill bit as well as what we've done with the organizational structure. So from a sustainability standpoint, we feel very, very good about -- it's just not a flash in the pan.

Neal Dingmann -- SunTrust Robinson Humphrey -- Analyst

Very helpful, guys. And then just lastly and a follow-up, the Bakken, I know you've got plan with the one rig and the seven wells. Just wanted to sort of address the depletion that you have there. I know in the past, you've mentioned, I forget if the number was three or four, what you kind of thought was an optimal level to really attack that area.

I'm just wondering now that with the plan finished, any new thoughts or color you could just talk about attacking the Bakken? Thanks so much.

Richard Doleshek -- Executive Vice President and Chief Financial Officer

Yes, I think we have a little bit of -- we've got a good detail on the -- in the pack. But we've studied the Bakken hard. And we looked at -- we just kind of looked at it over the next five years and said, "That's what matters most for now." We have quite a large inventory that you can develop at higher prices. But if you think about a $50 to $55 price, we've got a really solid inventory at about 100 refracs on a 100 drill wells.

The drill wells are primarily in Fort Berthold, and then the refracs are split evenly between South Antelope and Fort Berthold. These sands at the South Antelope refracs that we completed in 2018 are continuing to deliver very well. The economics are strong. The latest ones we did with the best technology have an F&D cost of kind of $8 to $10.

And so we're going to do probably a bit more early on, on, just proportional share of refracs versus drill wells and then carry that on. At about plus or minus $150 million a year, we can maintain production flat. The base decline on the Williston is about 30% per annum, and that's a pretty cyclical decline. And we're able to maintain to work collectively in such decline.

All of that activity, I'm talking about the refracs and occasional wells are enough of upside wedge to keep that production flat for a long time. And the final thing I'd say is that's a very cash flow positive asset, and we can maintain that as cash flow positive very easily for the next 10 years, we believe.

Neal Dingmann -- SunTrust Robinson Humphrey -- Analyst

Great. Thanks so much, guys.

Operator

Our next question is from Kashy Harrison with Simmons Energy.

Kashy Harrison -- Simmons Energy -- Analyst

Good morning and thank you for taking my questions. So the first one from me, what should we -- how -- what are you going to use the incremental free cash flow in excess of the dividend to do in 2020?

Tim Cutt -- President and Chief Executive Officer

So I'll start off and then turn it over to Richard. I mean, we do have a $50 million debt maturity coming due and that will be paid off. And then, obviously, we have additional debt maturity coming the following year. So I'll turn it to Richard to kind of build that out.

Richard Doleshek -- Executive Vice President and Chief Financial Officer

Yes. Kashy, it's going to be a combination of managing the balance sheet. The dividend, in total, does not increase on quarterly basis as it -- on an annual basis, it's about $20 million. Tim mentioned the $50 million maturity.

So it's $70 million right there of the $120 million. The remainder, we'll figure out what to do with it with regard to the balance sheet or other -- we'll just put a little bit more money into the Permian water business to get it to where we want to be to complete the monetization. So it's earmarked for a variety of things.

Tim Cutt -- President and Chief Executive Officer

But our intent is not to increase activity. I mean we have spent a lot of time over the last six months looking at the activity levels. And quite frankly, when we talked in April, I thought we were going to have to have a higher volume and a $60 oil price to deliver this kind of cash flow. With all the significant reductions, we can now deliver at this.

And so you think about only working off for the next few years 5% or 6% of our inventory per year, that gives you a long life. You're not pressed against the wall on inventory and you're delivering a very positive cash flow. So I'd say stability is key. We're going to do smart things.

We'll be opportunistic, but we really are focused on this level of activity. Two rigs in the Permian fracking periodically, drilling periodically in Williston. And that's the only way we're going to have confidence of delivering a very consistent cash flow profile.

Kashy Harrison -- Simmons Energy -- Analyst

Great. And then maybe two quick ones for Richard. How should we think about maintenance capex to hold your Q4 oil rate flat into 2020? And how should we think about the oil price at which your program is cash flow neutral in 2020 and 2021?

Richard Doleshek -- Executive Vice President and Chief Financial Officer

Yes. Kashy, I don't have the exact number. We're still cash flow positive, $50 a barrel. And of course, some of that is supported by the derivative program.

And if I had to use ballpark, then I'd say we're probably cash flow neutral in high 40s. So -- I think probably at $45, we're not cash flow neutral in 2020. And I think -- we don't have any derivative position for 2021 yet, and we'll wait for the forward curve to recover before we start putting those derivatives on. So that's kind of the -- I think the -- let's say, a quick guess at the cash flow neutrality price.

The first part of your question was what, Kashy? Sorry.

Kashy Harrison -- Simmons Energy -- Analyst

Then the maintenance capex to hold the Q4 rate.

Richard Doleshek -- Executive Vice President and Chief Financial Officer

Yes. So maintenance -- so we -- in Tim's prepared remarks, he talked about the Bakken. The Bakken's going to generate about 8 million barrels of oil this year. And then to keep the Bakken flat at 8 million barrels, 8 million to 9 million barrels, is about $130-ish million range.

And I guess -- the flat in the Permian is probably $300 million to $350 million. And so that incremental capital that we're spending on infrastructure, etc., only grows the Permian by about 10%. So I think if you put the -- look at our capital program for next year, there's probably $100 million to $150 million that's growth driven versus remainder used to sort of keep production flat.

Tim Cutt -- President and Chief Executive Officer

The other thing I'd build on the derivative position is typically, we would end the year about 50% covered. We're already at 46%, and the average price is $58.85. So we feel good about the position we're in now. We think we'll have other opportunities, so hopefully before year end and certainly into next year to build that up to closer to 70-plus percent.

So yes, and we feel good about what we've done to secure our ability to carry through this year and carry all the way into -- in through 2020.

Kashy Harrison -- Simmons Energy -- Analyst

Got it. If I could just sneak one more quick one in. Could you remind us or could you like tell us what the cash flows associated with the Permian water infrastructure assets were during the second quarter?

Richard Doleshek -- Executive Vice President and Chief Financial Officer

Yes. Kashy, we don't break it out. And it's all intercompany. So it wouldn't be reflected as a -- if we had -- charging ourselves $1 a barrel or $1.50 a barrel for water.

I think -- so we don't give the number and again, it's internal. So it's not -- and in not -- in unique way if we did give you the number. But I told you, it was $10 million of "EBITDA to QEP," I think it gives you the wrong idea that oh, that's only worth $100 million in a 10 times multiple because we're handling it ourselves. And I guess -- so as we get closer to trying to do something with that, if we decide to do something with that, clearly, we'll give more visibility as to what that system would do if it were a stand-alone third-party system.

Kashy Harrison -- Simmons Energy -- Analyst

All right. Thank you.

Operator

[Operator instructions] Our next question is from Tim Rezvan with Oppenheimer and Company.

Tim Rezvan -- Oppenheimer and Company -- Analyst

Good morning, folks. Thank you for taking my questions. I was just hoping to follow up a little bit on that last question, just trying to understand Williston Basin production. And then, Richard, you said 8 million barrels of oil this year.

If we assume that 68% oil cut, that gets you to about 32,000 barrels a day. And is that sort of roughly how you guys are thinking about kind of maintenance production level going forward for the Williston?

Richard Doleshek -- Executive Vice President and Chief Financial Officer

Yes, that's exactly right. I think you got your numbers just about exactly right. And I think with the -- we -- that -- what we quoted on our script is the $135 million to $165 million, depending on the year and depending how much infrastructure hits. But in years where you're doing primarily refracs, leveraging the infrastructure.

It's going to be closer to $135 million. Years, where you have the facility infrastructure associated with drilling the new wells, it would be a little higher. But overall, net-net, over the next seven years, we feel confident with that level of activity, we keep the numbers flat about what you quoted.

Tim Rezvan -- Oppenheimer and Company -- Analyst

OK. OK. Thank you for that. And then I'm -- I was hoping to get more clarity on comments you gave in your prepared remarks on the Midland Basin.

Did you say that 8% oil growth in 2020 from the Permian would come from developing 6% of your inventory? Was that the comment you gave?

Richard Doleshek -- Executive Vice President and Chief Financial Officer

Yes. So in 2020, County Line, when you look at the 60, 65 wells we'll drill, that develops about 6% of our remaining inventory, and we get about an 8% year-on-year growth.

Tim Rezvan -- Oppenheimer and Company Inc. -- Analyst

OK. So just to extrapolate that, then you're looking at about 1,000 locations is what you believe in your inventory?

Richard Doleshek -- Executive Vice President and Chief Financial Officer

We kind of guessed we might do that. So if you go 60 to 65, that gives you 1,000 to 1,100. We're in that area code. I mean, obviously, when we look at the other zones like the Dean is giving us extraordinarily good results right now like Jo Mill.

We're looking at all offset activity around Robertson Ranch. I guess -- that number will continue to change with time, but we're feeling good in that kind of area, though.

Tim Rezvan -- Oppenheimer and Company -- Analyst

OK. Thank you for that. And then just if I could sneak one last one in just to hit on the dividend again. I guess -- I was wondering if you could talk about kind of -- is there a tactical element to this to defend the equity, given it's been under pressure? And the reason I ask is that you see interest expense for the company is almost $4.50 a BOE.

And then so -- if we annualize first-half '19 EBITDA, we see kind of leverage around three and a half times. And so can you talk about why you felt the need to do this now as opposed to when you're in a little more of a stronger position?

Richard Doleshek -- Executive Vice President and Chief Financial Officer

Yes. Tim, I think it's a combination of all those things you just mentioned. I think it is tactical. I think it is a tangible -- as I said earlier, a tangible demonstration of our belief in our ability to generate free cash flow.

I think it also is reflective of our -- of what we think our cash position is going to be on a go-forward basis and how we're going to manage that leverage on a go-forward basis. We don't have anything drawn on the revolver. And so -- we don't forecast what needs to be drawn on revolver for the foreseeable plan horizon. And then how we manage the $50 million that's due next year, the $400 million that's due in 2021 is -- we're just balancing how we're deleveraging that with regard -- with comparison to how -- what we do with the cash.

I think if you annualize the first half of the year is challenging. I guess -- and the $119 million of EBITDA in the first quarter was burdened with over $60 million of G&A as a result of restructuring costs. If you annualize the second quarter or, more importantly, the second half of year, our leverage is pointed well south of three times. We forecast that -- it to be -- by the time we get to, let's call it, middle -- midpoint of 2020, to be plus or minus two times.

And the goal would be down in the one a half times. And then so -- we'll be opportunistic about how we manage that deleveraging. But certainly, the free cash flow generation of the company and what we can do with that money relative to the $19 million to $20 million of dividend. It seemed like a good balance.

Tim Rezvan -- Oppenheimer and Company -- Analyst

OK. Thank you.

Operator

Our next question is from Betty Jiang with Credit Suisse.

Betty Jiang -- Credit Suisse -- Analyst

Good morning. I'd just like to have a quick question on 2020. It seems to me that capex is roughly flattish next year while you're doing a higher level of activity just by a couple of wells in the Permian and also a much higher frac of -- also frac activity in the Bakken. Is there incremental cost savings that's being assumed in the 2024 outlook that's not in 2019? Just trying to understand what's being captured and what's not.

Tim Cutt -- President and Chief Executive Officer

Yes. So if you look at the deck, we talked about where we'd save money on drilling, completions and facility costs. We're bringing -- we've been bringing those costs down all year. What we projected forward in there is kind of a midyear '19 forward.

So the activity at the beginning this year was at a higher dollar amount, and we're bringing that down. I guess -- we continue to bring that down into a run rate that we feel we're pretty close to, about $1.5 million to $1.7 million per well delivered. And I think that includes all facility costs, lifting costs, drilling and completions. And then -- and so yes, when you did that math and you run that through and you also look at what we're trying to do is leverage existing facilities and lower that capital intensity, all of that is coming together to lower the intensity per well.

So I think you're right. We could certainly help you offline with some of more detailed math on that.

Betty Jiang -- Credit Suisse -- Analyst

Got it. But generally fair to say it's reflecting your current cost structure in both place?

Tim Cutt -- President and Chief Executive Officer

Absolutely.

Betty Jiang -- Credit Suisse -- Analyst

OK. And then a follow-up on the debt. Is it fair to assume that the best case is for the $450 million maturity on the revolver over the next two years? And then could you remind me, does the current revolver reflects sale of Haynesville?

Tim Cutt -- President and Chief Executive Officer

Yes. The $550 million incremental debt capacity under the covenants does pro forma out the EBITDA contribution of the Haynesville assets as well as the PV9 contribution of the Haynesville asset. So the revolver -- the incremental debt capacity that we quote is pro forma for everything that we sold in the last trending 12 months. The $450 million of debt maturity is $52 million next year and $397 million in 2020.

And I think -- we do not anticipate putting all of that or even half of that on the revolver if we were just to let those mature as they're forecasted to mature, they're scheduled to mature because of the cash balance that we expect to have, the combination of the $75 million tax refund we're forecasting in the fourth quarter as well as the free cash flow that's generated by the operations next year. The combination of cash available to us from operating activities and so -- and other sources. We're projecting that we're actually not going to put the bulk of that $400 million on the revolver when it matures.

Betty Jiang -- Credit Suisse -- Analyst

Great. Thanks for that.

Operator

We have reached the end of the question-and-answer session. I will now turn the call over to Tim Cutt for closing remarks.

Tim Cutt -- President and Chief Executive Officer

Thank you very much, and thanks for joining the call today. We're excited about the competitive position we have today and the substantial opportunities ahead of us. We look forward to continuing the dialogue with all of you in the coming days and weeks. Have a good day.

Thank you very much for joining us.

Operator

[Operator signoff]

Duration: 42 minutes

Call participants:

William Kent -- Director of Investor Relations

Tim Cutt -- President and Chief Executive Officer

Richard Doleshek -- Executive Vice President and Chief Financial Officer

Gabe Daoud -- Cowen and Company -- Analyst

Neal Dingmann -- SunTrust Robinson Humphrey -- Analyst

Kashy Harrison -- Simmons Energy -- Analyst

Tim Rezvan -- Oppenheimer and Company -- Analyst

Betty Jiang -- Credit Suisse -- Analyst

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