QEP Resources (QEP) Q4 2019 Earnings Call Transcript

QEP Resources (QEP)
Q4 2019 Earnings Call
Feb 27, 2020, 9:00 a.m. ET

Contents:

• Prepared Remarks
• Questions and Answers
• Call Participants

Prepared Remarks:

Operator

Greetings, and welcome to the QEP Resources fourth-quarter and year-end 2019 conference call. [Operator instructions] A brief question-and-answer session will follow the formal presentation. [Operator instructions] As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Mr.

William Kent, director of investor relations. Thank you. You may begin.

William Kent -- Director of Investor Relations

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

In today's conference call, we will 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 more-robust forward-looking statement disclaimer and 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

Thanks, Will. Good morning, and thank you for joining the call today. I will begin with an overview of our fourth-quarter and full-year operational performance, followed by a brief update to our business strategy before turning the call over to Bill to discuss the 2019 financial performance and guidance for 2020. We are very pleased with our operational performance for the full year 2019 in all categories.

Drilling completion costs were reduced to a peer-leading $536 per foot in 2019, and we are budgeted at $532 per foot in 2020 despite frac water costs being higher in County Line. Our drilling team continues to deliver 10,000-foot lateral wells to a total depth in less than 12 days. Final frac completion operations enabled us to complete an average of 3,000 lateral feet per day in 2019 with a single frac crew. And we have increased our target footage to the 3,300-foot per day for 2020, as shown on Slide 6, the rate of the IR deck.

Facility costs have come down 30% during the year by prefabricating equipment off site and by tying new wells into existing facility capacity as it becomes available through natural decline, another advantage of our tank-style development methodology. The strong operational performance allowed us to deliver production 11% above and capital spending 11% below the midpoint of our original 2019 guidance. It has also positioned us to deliver the 2020 development plan with peer-leading capital efficiency. Corporate overhead expense was reduced by approximately 30% from 2018 to 2019, and we have completed all actions required to lower these costs to an additional 42% from 2019 to 2020.

We have entered 2020 with a competitive overhead structure and do not anticipate any noteworthy additional charges for special items associated with the restructuring. We remain committed to lowering nonemployee G&A expense going forward. Lease operating expense in the Permian Basin was reduced 20% year over year to approximately $4 per BOE through reductions in contract labor and improvements in maintenance practices. We continue to execute projects such as the elimination of on-site power generation to lower costs in the Williston Basin.

As I mentioned earlier, full year equivalent production exceeded original forecast by 11%. We ended the year with oil production remaining flat from the third to fourth quarter 2019, driven primarily by the seven new Vegas wells in the Williston Basin, offsetting anticipated decline in the Permian. We did, however, finish the year at the low end of our fourth quarter oil guidance. If you recall from the last call, during the third quarter of 2019, we accelerated production in DSUs 12 and 13 through a change in our start-up philosophy.

At the time guidance was finalized in mid-October, the data indicated that original type curve decline rates were still possible, and we honored that data. As we progressed through the fourth quarter, the accelerated production began affecting the decline rates of certain wells and, as a result, production fell slightly below the original type curves and slightly below guidance for the fourth quarter. However, as you can see from the DSU plots on Slides 11 and 12 of the IR deck, the cumulative production for each DSU remained well ahead of the forecast. And we are confident that the correct economic decision was made to start up the wells more aggressively, in line with our industry peers.

Now that we have experienced the steepest part of the decline for these DSUs, we're confident that despite the slightly higher decline rates, the rate of return of these wells has improved given the substantial acceleration of production. These positive learnings have been built in our 2020 budget forecast. I'm pleased to say that all other operational indicators were on or ahead of guidance in the fourth quarter. Our strong operational performance, coupled with our continued focus on overhead and operating expenses, resulted in QEP generating approximately $371 million of cash flow provided by operating activities in the second half of '19 and delivering nearly $100 million of free cash flow in the same period.

I will now move on to our development plan. I'll spend a few minutes describing the 2020 development program and its anticipated results. I believe it is an important reminder to show that we forecasted -- what we forecast for 2020 and 2021 in August of 2019 as we emerged from the strategic alternatives process as compared to our business plan now for 2020. As described on Chart 14 of the IR deck, we have lowered annual capital spend and an improved production forecast slightly in each year and we reaffirm our free cash flow estimate for 2020 in the range of approximately $90 million to $110 million at $50 WTI price, with a cash flow yield of more than 15% of our current share price.

In the Permian, we expect to drill with two rigs year-round, with new wells being completed in County Line and put on production in the first three quarters of the year. We recently picked up an intermediate rig to help the two drilling rigs stay ahead of the frac crew as the amount of footage frac per day continues to improve. We expect to complete 65 net wells in County Line during 2020 and grow production -- oil production by 4%. We started bringing on our first DSU in County Line in mid-January.

We have provided a production plot on Slide 15 of the IR deck that shows DSU 312 in County Line is currently producing more than 16,000 barrels of oil per day and building nicely toward the expected peak rate of greater than 20,000 barrels of oil per day. We're pleased to disclose that our first test in the Wolfcamp A/B horizon, along with the Spraberry C bench, are exceeding type curve expectations. The Spraberry B wells are on type curve, and the shallower zones continue to dewater the tank as anticipated prior to producing significant amounts of oil. These positive early results give us confidence in delivering our 2020 plan.

In the Williston, drilling activity was initiated during the third week of February. We plan to drill and complete six wells with an average lateral length of 12,800 feet on the Disco pad between February and August. We anticipate a 10 to 15 well refrac program to begin during March and continue through August. We also plan to invest approximately $25 million in nine high-quality, non-operated wells with 36% in [inaudible] on the pad adjacent to our biggest pad in South Antelope.

Operational seasonality in both fields will mean that capital spend during the first half of the year will be significantly higher than the second half of the year, and volumes are expected to peak in the second or third quarter. Similar to 2019, this will likely translate into cash outspend during the first half of the year before significant free cash flow generation in the second half of the year. We understand that this nonlinear trajectory is somewhat unique, but it is extremely important to understand this seasonality as we transition to a development program that consumes less capital and is expected to deliver significant positive annual free cash flow at $50 oil. During the last call, I mentioned that we were evaluating a variety of options to maximize the value of our substantial water business, including a full or partial sale of the joint -- or the joint venture transaction.

We're actively engaged with potential buyers, and we'll provide an update once the process has concluded. In summary, during 2019, QEP delivered continuous improvement in all operating categories and completed a significant reset for corporate overhead structure. We entered 2020 committed to generating free cash flow, delivering our balance sheet -- delevering our balance sheet and returning capital to the shareholders. We are confident in our ability to deliver on this commitment as a result of improved performance and deliverability of our high-quality, oil-dominant asset base, a significant decrease in drilling completion facility costs, and the successful and sustainable reduction of corporate overhead.

With that, I'll turn the call over to Bill to discuss our financial performance along with more detail of our 2020 guidance.

Bill Buese -- Chief Financial Officer and Treasurer

Thank you, Tim, and good morning, everyone. Over the next few minutes, I will provide some details on our fourth-quarter and year-end results and outline our initial 2020 guidance before opening the call up for Q&A. For the fourth quarter of '19, we reported net loss of $110 million compared to net income of $81 million in the third quarter of '19. Driving the net loss was $109 million unrealized loss associated with our commodity derivatives portfolio.

At the end of the fourth quarter, the derivatives portfolio was a net liability of $18 million compared to a net asset of $92 million at the end of the third quarter. In the fourth quarter, we generated $183.8 million of adjusted EBITDA, a modest decrease from the $193.5 million generated in the third quarter. Equivalent production remained relatively flat at 8.5 million barrels of oil equivalent even after a 90,000 barrel-negative NGL adjustment associated with the historical period volume reduction in the Williston Basin. Combined total LOE and adjusted transportation expense remained flat at $72 million, and G&A was slightly higher, reflecting the increase to the mark-to-market of our deferred compensation plan.

Finally, the fourth quarter 2019 adjusted EBITDA was negatively impacted by approximately $6 million of historical period charges primarily associated with Williston Basin operations. We continue to enter into commodity derivative contracts during the fourth quarter. And as of December 31, we held contracts, excluding basis swaps, totaling 16.6 million barrels of oil for 2020, which covers 76% of forecasted oil production at the midpoint of guidance. The average fixed price of the contracts for '20 is approximately $58 per barrel.

Please see the 10-K for additional details on our swap and basis contracts. During the fourth quarter, we generated net cash provided by operating activities of $224.9 million and delivered $56.2 million of free cash flow. We just missed being cash flow neutral for the full year by $9.8 million, which is a remarkable accomplishment when you consider that we outspend cash flow by nearly $315 million in 2018. As a reminder, we define free cash flow as adjusted EBITDA plus noncash share-based compensation expense, less interest expense excluding amortization of debt issuance costs and discounts and accrued capital expenditures excluding acquisitions.

With regard to our balance sheet. At the end of the quarter, total assets were approximately $5.5 billion and total shareholders' equity was approximately $2.7 billion. Total gross debt was approximately $2 billion, all of which was our senior notes. We had no borrowings outstanding under our revolving credit facility and had approximately $166 million of cash on hand.

During the fourth quarter, we redeemed the remaining $52 million of outstanding senior notes that were due in March of 2020. We also repurchased approximately $15 million of senior notes due 2021, leaving $382 million outstanding of that debt issuance. We used cash on the balance sheet to fund those transactions. And if we had not repaid this indebtedness, we would have reported approximately $235 million of cash on hand at year-end.

I will now touch briefly on our plan to address our future debt maturities. First, regarding the 2021 notes, we expect to repay the notes using cash on hand at year-end, if needed, with availability under our credit facility. As a result of our forecasted free cash flow generation in 2020 and the next installment of our AMT credit refund during the fourth quarter of '20, expected to be approximately $37.5 million, we forecast our cash on hand at year-end '20 will be greater than $250 million based on our current budget assumptions. In addition, to the extent we've successfully divested any of our noncore assets over the next 12 months, we will use all of the net proceeds toward the repayment of debt.

While we continue to evaluate options to address our senior notes that mature in October of '22 and May of '23, we believe that we have the necessary time and sufficient access to the debt capital markets to identify the best option for repaying those notes. Moving on to guidance. Our 2020 oil volume guidance is 21.35 million to 22.45 million barrels, a modest increase at the midpoint compared to 2019. We expect Permian oil production to increase by 4%, while Williston oil production is expected to decreased by approximately 2% compared to 2019.

Our guidance for natural gas volumes for '20 is 31 to 34 Bcf, a 2% decrease at the midpoint compared to 2019. Our guidance for NGL volumes for 2020 is 5 million to 5.6 million barrels, a modest increase at the midpoint compared to 2019. Our 2020 guidance for lease operating expense is expected to be $5.20 to $5.80 per BOE, while our guidance for adjusted transportation expense is $3.30 to $3.60 per BOE. This results in 2020 total lifting cost guidance of $8.50 to $9.40 per BOE, the midpoint of which is in line with our 2019 reported results.

Our guidance for G&A expense in 2020 is $85 million to $95 million, of which approximately $13 million is share-based compensation expense and other mark-to-market liabilities. It is important to note that we do not expect to incur any meaningful restructuring charges in 2020. The midpoint of G&A guidance for 2020 is 40% lower compared to 2019 and is approximately $2.80 per BOE using the midpoint of our production guidance. Finally, excluding acquisition and divestiture activity, our 2020 guidance for capital investment is $545 million to $595 million, which includes capital for our midstream infrastructure.

The Permian Basin will be allocated 80% of this budget. Please see our earnings release for additional details on our 2020 annual guidance as well as quarterly guidance where applicable. I will now turn the call back to Tim to provide a brief summary before opening the call up to questions.

Tim Cutt -- President and Chief Executive Officer

I think we'll just go over to questions.

Questions & Answers:

Operator

Thank you. We will now be conducting a question-and-answer session. [Operator instructions] Our first question comes from the line of Gabe Daoud with Cowen. Please proceed with your question.

Gabe Daoud -- Cowen and Company -- Analyst

Hey, good morning, guys. With -- I guess starting with 2020. Obviously, some impressive efficiencies captured in the Permian. I was curious, I guess, how this does impact the budget.

Meaning, if you continue to get faster and faster, is there wiggle room to perhaps turn on some more wells than initial expectations to smooth out the production cadence a bit?

Tim Cutt -- President and Chief Executive Officer

Hey, Gabe. That's a good question. I mean, we're looking at that constantly. I mean our preference as we've talked about for the last year is to be able to just drill with enough rigs to keep the frac crew busy throughout the entire year.

You know, we're going so fast now. I don't think it's practical to think that you could smooth it too much. I think we're generally going to need to shut down fracking in fourth quarter at this point. Our frac crew is -- one frac crew can now support about four rigs.

So, with two rigs running in the fourth quarter, we continue to drill wells. And so that enabled us to have wells ready to frac now. And we started drilling wells on in January. But I don't think it's practical to think we can smooth it much.

As we lower cost, though, all of that goes to the bottom line, and then we'll look as the year progresses to see if it makes sense to bring additional wells online. But right now, I don't think it's practical to think that you can bring on too many more wells.

Gabe Daoud -- Cowen and Company -- Analyst

Got it. Thanks, Tim. That's helpful. And then I guess just as a follow-up, at County Line, the initial university project that was turned to sales in January.

I was just curious given the density in the Spraberry. It looks like it's about 15 wells a section there. How exactly are those two separate Spraberry zones performing relative to the other zones and relative to your expectations?

Tim Cutt -- President and Chief Executive Officer

Yeah. So, on the Spraberry Shale, the C bench, we're certainly exceeding expectations. We're fracking just above the Dean zone, so we don't know if we're getting contribution from the Dean. But I would say our average peak rates in that C zone are north of 2,000 barrels a day.

We have a few wells up in the 2,500 barrels a day in C bench. So extraordinarily good. That compares to type curve peak of kind of expected peak in 1,000 to 1,500 barrels a day. They -- the B bench, a little bit higher up in the stack, is performing a type curve expectation of kind of 1,000 to 1,500 initial rates, so we're really pleased.

We're not seeing any interference issues. And you can see that pretty rapid build from -- we saw the number of wells to bring online. We have a number of those wells that are now being put on ESP, and we're still making 16,000 barrels a day. So, we're getting quite encouraged.

But yes, the Spraberry bench is doing extremely well.

Gabe Daoud -- Cowen and Company -- Analyst

Awesome. Thanks a lot, Tim.

Tim Cutt -- President and Chief Executive Officer

All right. Thanks, Gabe.

Operator

Our next question comes from the line of Neal Dingmann with SunTrust Robinson Humphrey. Please proceed with your question.

Neal Dingmann -- SunTrust Robinson Humphrey -- Analyst

Good morning, Tim and team. Tim, my first question is on your Slide 11 and 12. You guys have done a good job with spacing, and it seems maybe, I would say, in your Spraberry Shale, you're maybe still a bit wider than some of your nearby peers. Could you speak to your thoughts on the down space, in particular in this Mustang Springs area?

Tim Cutt -- President and Chief Executive Officer

Yeah. I think we've -- Neal, I think we've got it about right. As you can recall, back in 2017, '18, we did a high-density test. And we tested the limits and we did see interference and it affected our production rates.

And so, I think our view is we've got the Spraberry Shale and the Wolfcamp about right. We're very encouraged by the initial test in the Dean. So, you know, I don't expect that we're going to be changing this a lot with time. We'll watch it as we get back over to Mustang Springs.

We're probably going to have at least a year of production to look at. And we'll take that data, we'll apply it to it and see if we modify that. We're thinking in each bench, you're talking about adding one or two wells, not six wells.

Neal Dingmann -- SunTrust Robinson Humphrey -- Analyst

Got it. And then my second question on your Slide 9, showing the lowered cost. You certainly have materially notable lowered cost from '18 to 2020. I'm just wondering, is there still wood to chop there? Could we continue to see such material improvement? Thank you, all.

Tim Cutt -- President and Chief Executive Officer

You know, a year ago, we set a target to get below $3. The $90 million at the current oil production gets us down in that kind of $2.80 in range. We do think -- you've seen the kind of the expected CAGR over time. We don't anticipate that we've got to increase that with time.

And we've made a rapid movement. So now we're into the optimization stage. So, I think the entire organization stands behind continuous improvement. We're looking for every dollar, how do you take it out and still remain efficient.

We have some things that will clearly take more dollars out. We have -- obviously, we vacated a lot of the building. We sold four floors to sublease. So, there are a number of things there that we believe will happen with time, but we didn't want to put in the budget for this year because it could take a little bit of time in the current market to do some of those things.

Neal Dingmann -- SunTrust Robinson Humphrey -- Analyst

Very good. Thanks again.

Operator

Thank you. Our next question comes from the line of David Heikkinen with Heikkinen Energy Advisors. Please proceed with your question.

David Heikkinen -- Heikkinen Energy Advisors -- Analyst

Good morning, and thanks for taking my question. Just thinking through cadence and your comment of unlikely to get any more wells. So you have 21 wells in the first quarter and 69 for the full year. Can you just talk about the splits of timing in each basin? And then you also have a first-half-weighted capital budget.

I know you're not giving second quarter guidance, but I'm just trying to think about how that tapers off into the frac holiday in the fourth quarter again.

Tim Cutt -- President and Chief Executive Officer

Yeah. So, David, we're still kind of working that a little bit. But we – sorry. We're still working that a little bit.

But if you think about 20 -- I don't think those are right ones. We're work-- let me just answer it in a different way. So, as you think about the cadence, we're bringing on a number of wells now. We're going a little bit faster than we did last year.

Our -- on the DSU we showed in the plot, we actually have moved the frac crew away from the end of that DSU, and so we're able to start popping a number of those wells a little bit quicker. And so, one of the things that we're preparing to say as we prepared for the call is with our production, we kind of build in the second quarter and then kind of picking the third. Actually, now, we think it could be more equally divided between the second and third quarter. So, if you think about the cadence of the wells and you kind of put a relatively equal split on those in the second or third for the Permian, I think that's a good thing to consider with no completions in the fourth quarter for now.

We're going to do everything we can. We still think it makes sense to bring all that forward. And so, we're going to continue to adjust that a couple of months from now when we give the second quarter guidance. We're going to have a really good sense of how that cadence is going to line out.

And I understand, for you guys to model this, it's kind of difficult when it's coming up and then dropping off substantially. But when you think about kind of what we said back in August, even our -- just on our kind of production profile, we missed the fourth quarter probably by about 100,000 barrels for the reason that we stated the first quarter are actually about 100,000 barrels of oil ahead of where we thought we'd be. So, we're at the right starting point. And we hope to accelerate some of that volume earlier in the year.

And so, I'm not trying to be evasive at all. It's just -- we're kind of learning as we go. This is the first time we've done a continuous tank model in County Line. Our early indications are extremely encouraging.

And we're going to know a heck of a lot more in two months on what the exact cadence will be second, third quarter, and then into the fourth. In the Williston, it's pretty clear. We're going to start fracking the refracs in March, and then we'll go over those refracs during the summer months. And then we're drilling -- we've already spud the wells in the Disco unit.

That activity kind of goes from now through August, we completed the wells and you'll see that production coming on in the end of the third, fourth quarter with our joint interest partner that are drilling the nine wells. And those are 15,000-foot lateral wells. Those are on the same kind of cadence. So, we're going to bring quite a few wells on in that August time frame, both operated and nonoperated, which will help us in the fourth quarter from a production standpoint.

David Heikkinen -- Heikkinen Energy Advisors -- Analyst

OK. And then thinking about the annual kind of trajectory, and I -- and you addressed the notes in the near term, the 2021 notes. How do you think through in this $50 world, plus or minus, just the trajectory of 2021? And I know 2022 is when you'll have to be thinking about those senior notes. What do you think free cash flow and the revolver usage will be? Do you have any -- I'm just trying to think about that repayment on the '22s?

Tim Cutt -- President and Chief Executive Officer

Yeah. I'll start and then hand it over to Bill. So, as you said on the '21s, we've got a real clear line of sight to that. You know, we'll take the cash on the balance sheet.

We'll take the cash generated this year, plus the tax refund, and then also any proceeds from anything else we do in the year. As you know, we're looking at the water business. Haven't made any decisions there. But that would be an example of how we deal with that.

And we may be able to build a well the '21s through just a cash payment. As you go into the '22s, I'll hand that over to Bill to discuss.

Bill Buese -- Chief Financial Officer and Treasurer

Hey, David. So again, as Tim alluded to, our plan in '21 is pretty straightforward. But yes, the '22, we don't expect to have anything borrowed on our revolver this year and as well as into -- by the time we exit '21. So that's kind of our current plan.

And I know the -- between now, and let's say, middle of '22, we have about that amount of time to figure out what to do. Now obviously, we plan on addressing those as soon as possible, whether that's refinancing them or paying -- or addressing those -- purchasing things in the open market, if that's available. So, everything is kind of on the table. We're certainly not going to wait until the last minute.

But you know, we just kind of have to let things kind of play out a little bit here with the market to see what our best plan going forward is.

David Heikkinen -- Heikkinen Energy Advisors -- Analyst

So, the base assumption is that you have some revolver capacity and that maybe some asset sales, I guess, is the...

Bill Buese -- Chief Financial Officer and Treasurer

Yes, correct. Yes. If we wanted to, David, there's another way if we wanted to, we could put the senior notes on the revolver. It doesn't differentiate between the kind of debt.

We can certainly do that. Now, of course, we'd have to refinance the credit facility before the '22 notes come due. But we do have flexibility on the revolver to do some of that, you know, debt management, if you will, open market purchases and so on. So yes, that's a good way to look at it.

David Heikkinen -- Heikkinen Energy Advisors -- Analyst

And just to note, I think most other companies would be happy to have the hedges you guys have now. A lot have missed that window, unfortunately. So good job on that. Taking for taking my question.

Bill Buese -- Chief Financial Officer and Treasurer

Thank you.

Operator

Thank you. Our next question comes from the line of Gail Nicholson with Stephens. Please proceed with your question.

Gail Dodds -- Stephens Inc. -- Analyst

Good morning. [inaudible] You've done a really great job driving that down in the Permian. Can you just talk about where LOE stands in the Williston? And then kind of any thoughts on improvement, specifically in the Williston as you kind of get overall corporate LOE down even lower?

Tim Cutt -- President and Chief Executive Officer

Yeah, that's a good question. I mean, if you look at some $4 in the Permian, we feel good about that. And if you look at Slide 10 on the deck, I think we're getting down to kind of the bottom of the pack as far as the LOE cost in the Permian. In the Williston, I'd use a number of kind of eight-plus.

We were probably in the $8.30 range last year, down to $8 this year, in '19. And we continue to work on driving that down. We have some structural things we have to work on there. The cost on the Indian reservations are quite a bit higher than that.

We do have power generation at each of the sites. We're working on getting power delivered to the sites. That will take a huge amount out of that. Also water disposal in the Indian reservation is quite significant.

So, we've got a line of sight to a number of initiatives to take that cost down. We focus, quite honestly, our initial efforts in the Permian Basin. We're keenly focused now, for the reasons you highlight, up in the Williston. But I'd say, if you look at a split of kind of four and eight, you average that down with the production average, that's where you get to the guidance we have.

So, I feel good about the Permian. We have more room to go up in the Williston. Joe, do you have anything else to add to that?

Joe Redman -- Vice President of Energy

No, I'll just add that we've been focused on a number of initiatives there, kind of year-over-year that would have brought down our use of contract labor. We're planning out maintenance activities. And yeah, we've been able to improve our workover results to drive down failure rates on our wells going forward. So, we're planning for continued improvement with that asset.

Gail Dodds -- Stephens Inc. -- Analyst

Great. Thank you. And then also just sticking with the Williston, it looks like you have about $35 million of non-op capex this year. What is the degree of confidence in that? And if that doesn't materialize, do you reallocate that somewhere or just bank that capex?

Tim Cutt -- President and Chief Executive Officer

Yeah. So, the $25 million goes to a single project with a good operator just to adjacent, one of the best parts of the South Antelope field, in the strip next to South Antelope, next our Vegas pad. And so those wells are already drilling now. We've already approved the AFEs, and we're looking forward to the production outcome.

It's going to really help us in the late -- latter part of this year and certainly into 2021. So, $25 million is done. The other $10 million, I've got high confidence that it will go throughout the year. If you compare that to past years, we've had years -- not too many years back where that number could have been $50 million.

We've gotten very discerning on the joint interest work. If it's not competitive to what we're doing, we're not doing that. Last year, we had some AFEs that came in for quite a bit. We ended up selling acreage and not doing that project, but very accretive on a cash basis.

And so, the $10 million, I don't think there'll be a lot to give right there. We hope we have good, you know, projects in the core acreage that we can spend that money on.

Gail Dodds -- Stephens Inc. -- Analyst

Great. Thank you so much.

Tim Cutt -- President and Chief Executive Officer

All right. Thank you.

Operator

Thank you. Our next question comes from the line of Greg Tuttle with Simmons Energy. Please proceed with your question.

Greg Tuttle -- Simmons Energy -- Analyst

Hey, thanks for taking my question. My thoughts are around the water disposal divestiture program that you guys are trying to take care of sooner rather than later. I'm just curious as to whether or not you have a preference for a full-out sale, a JV, or a partial sale. And then how does that balance out through LOE expense once that does occur?

Tim Cutt -- President and Chief Executive Officer

Yeah. So, our water business is balanced between -- you can see in one of the slides, balanced between both water disposal and water recycling. And so, you know, I think when you look at our cost per barrel of disposal, we're extraordinarily competitive down in the disposal and recycling down the $0.10 to $0.15 a barrel. We -- one of the issues we have with the moving from different areas -- between different areas of the field, between Mustang Springs and County Line and eventually down to Robinson Ranch, is we've built our capacity, it's probably double of what we use at any particular time.

So that starts leading toward considering kind of a JV structure. There are a number of very effective water company that have access to water to bring to our system for both disposal and recycling that we don't necessarily have the internal capacity. So I would think a kind of a successful outcome would be one that brings capital in the door to help offset some of the costs of the infrastructure we've put in place, but probably more importantly, the company that can bring additional water to the system, an additional capacity to that system, that helps grow that EBITDA to offset any increased costs from selling, say, 50% of the business. So that's certainly the preference.

Yeah, we will not sell that business unless we see that we get enough cash in the front end and that we can see a really accretive path to grow that EBITDA, and make that become positive at time, payback the 50% we've sold and then move forward. So that's kind of where we're thinking about it. We're certainly not in the stage of the process to make that decision now. I think that the companies that are engaged with us understand our desires.

And we'll see where it comes out and make a decision accordingly.

Greg Tuttle -- Simmons Energy -- Analyst

OK. Perfect. Thank you. I appreciate you taking the questions.

Operator

Thank you. Our next question comes from the line of Josh Silverstein with Wolfe Research. Please proceed with your question.

Josh Silverstein -- Wolfe Research -- Analyst

Hey, thanks. Good morning, guys. A couple of questions for you. You have the $100 million hedge benefit this year.

I think that was mentioned before. Where can you guys, I guess, pull some levers to support margin expansion next year? Because this goes away, and I guess, the outlook would then call for no volumes and no free cash for next year. So where are there some opportunities for you guys to expand margins?

Tim Cutt -- President and Chief Executive Officer

Yeah. So, we've already started working on our 2021 budget. We're looking at, again, taking all of the efficiency learnings to speed. We're going to look at what we're learning in County Line.

Obviously, one of the easiest is that we can replicate some of the early time data on some of these wells as you got more volume for lower cost. So that's one opportunity we're looking at. We've talked about the water business. We're looking at maybe segments of the business, small segments of the business that don't generate huge amounts of cash flow but could be important to other companies.

So we're open to those kind of transactions. But I do think going into 2021, I mean, think about what we did from January to January in the middle of a process, of a sales -- potential sales process. And we've taken this down substantially. So, although we're not ready to talk about 2021 and what those numbers will look like, we have really ingrained, and the employees have adopted a continuous improvement mindset, and we just keep getting better to the top side.

I mean, when I talked with you six months ago, I never would have thought we'd be talking about 3,300 foot per day and a peak higher than that. And some of the rates we're seeing out of the Spraberry Shale, these are rates that are bigger. So, Josh, I think there's a number of things. We just need to look at from what -- start with the rock and reservoir, what will that give us, look at our cost structure and mix, look at our ability to sell certain assets to generate some cash.

And I think all of that starts building toward, you know, more and more confidence about continuing to pay down that debt.

Josh Silverstein -- Wolfe Research -- Analyst

Got it. Next thing was you mentioned a couple of these other sales, the water business sale. You haven't mentioned the Bakken sale. I know that was something that was potentially explored a year ago.

Is there any reason why that wouldn't be back on the table? I know you probably wouldn't want to do it in this price environment. But even if you were to sell for half the value, it's well over the market cap of the company today. So just curious about whether that transaction might be out there?

Tim Cutt -- President and Chief Executive Officer

Yeah, Josh. I mean, when we look at that, we also look at the full debt structure and kind of where our equity is. We add all that together and say, what number do you need to make sure that they could be accretive enough to where we get our leverage down? So, we're -- as you know, we're keenly focused on getting the leverage down below two, and hopefully closer to one and a half. And so, when we think about any sort of transaction in this market, the math is difficult.

Are we open to doing certain things in parts of our portfolio that might not be as accretive as the Permian? I'd say absolutely. And we remain open to incoming calls around different opportunities. It's just when -- and you said it, when you look at the market conditions and what companies are willing to pay for even PDP, let alone undeveloped acreage, you know, it's hard to make that math work. And so, we're looking at full debt structure of the equity and doing all of that math to say, if we ended up with a smaller company, can it handle the leverage situation and help us continue to bring that down?

Josh Silverstein -- Wolfe Research -- Analyst

Got it. Understood. Thanks.

Operator

Thank you. [Operator instructions] Our next question comes from the line of Derrick Whitfield with Stifel. Please proceed with your question.

Derrick Whitfield -- Stifel Financial Corp. -- Analyst

Hey, good morning, all.

Tim Cutt -- President and Chief Executive Officer

Hey, Derrick.

Derrick Whitfield -- Stifel Financial Corp. -- Analyst

Tim, referencing Page 6 of your PowerPoint, your improvement in completed well costs through 2019 was quite impressive. In trying to understand your guide and the potential for further improvement, could you comment on where your best Midland wells are trending on average with respect to your 2019 average of $5.36?

Tim Cutt -- President and Chief Executive Officer

Yeah. I think we're staying relatively flat. I mean, we -- when you talk to our drilling organization, they would have expected going into County Line. Historically, County Line is more expensive to drill in.

They committed to coming in flat to down, and that's what we're projecting at, $5.32, which is substantially below the industry average of $7.98. The water costs in County Line are quite a bit higher than we had in Mustang Springs. We are looking at ways to interconnect Mustang Springs and County Line to help with that. But at this point, you know, we don't have as much recycled water, and so those costs are higher.

They have absorbed every bit of that. And so, I think that, you know, if we're able to sustain that kind of $5.00 to $5.50 range in County Line, I think we'll be pleased with that. And again, every time I say that, our organization has stepped up and surprised me. So, you know, we're trying to give you what we've already done and what you can bank on.

We're not going to slow down looking for ways to take that down.

Derrick Whitfield -- Stifel Financial Corp. -- Analyst

Great. Again, that's quite positive as you outlined relative to the industry. As my follow-up, I'd like to switch over to the Bakken. Could you speak to the longer-term performance of the refracs you guys conducted in 2019?

Tim Cutt -- President and Chief Executive Officer

Yeah. So, you're talking about in early 2019? Is that what you're talking about?

Derrick Whitfield -- Stifel Financial Corp. -- Analyst

That's correct, Tim.

Tim Cutt -- President and Chief Executive Officer

Yeah. So, those wells are actually turned out to be the best wells that we fracked. And so those wells continue to outperform type curves. We have a full range of outcomes.

We've done a detailed study in the fourth quarter to prepare for this year, the high-grade based on all of the knowledge of the 35 wells that were fracked. And so, we really understand how GOR hits that, how offset high-density locations hit that, how cumulative oil production, you know, affects the refrac. So, you know, I feel really good going in the year that we've high-graded what we have. We still, you know, are confident in our 100 locations between South Antelope and FBIR.

South Antelope being a little bit stronger than the FBIR locations. But the ones that in 2019 actually turned out to be -- when we look at our criteria, they were Tier 1 wells, and they're performing as Tier 1 wells.

Derrick Whitfield -- Stifel Financial Corp. -- Analyst

That's great. Thanks for your time and details responses.

Tim Cutt -- President and Chief Executive Officer

All right. Thank you.

Operator

Thank you. There are no further questions at this time. I would like to turn the call back over to management for any closing remarks.

Tim Cutt -- President and Chief Executive Officer

Now, I'd just say thanks for joining the call. Thanks for your constructive comments. Just got to say how proud I am of the organization for what they endured last year to get to the point where we can be competitive in this kind of price environment. You know, to Josh's question, we're already keenly focused on 2021 and what we're going to do there to continue to generate more and more cash.

So again, thanks to the organization. We're delivering things that even a year ago, I don't think many of us thought we could. And we just plan to stay focused on delevering the balance sheet, delevering cash back. And look forward to giving you hopefully a very positive update in a few months.

Operator

[Operator signoff]

Duration: 43 minutes

Call participants:

William Kent -- Director of Investor Relations

Tim Cutt -- President and Chief Executive Officer

Bill Buese -- Chief Financial Officer and Treasurer

Gabe Daoud -- Cowen and Company -- Analyst

Neal Dingmann -- SunTrust Robinson Humphrey -- Analyst

David Heikkinen -- Heikkinen Energy Advisors -- Analyst

Gail Dodds -- Stephens Inc. -- Analyst

Joe Redman -- Vice President of Energy

Greg Tuttle -- Simmons Energy -- Analyst

Josh Silverstein -- Wolfe Research -- Analyst

Derrick Whitfield -- Stifel Financial Corp. -- Analyst

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