Q4 2019 Earnings Call
Greetings and welcome to the Qiwi P. resources fourth quarter and year end 2019 conference call.
This time all participants are in a listen only mode. A brief question and answer session off all the formal presentation. If anyone should require operator assistance. During the conference. Please press star zero on your telephone keypad. As a reminder, this conference is being recorded it is now my pleasure to introduce your host Mr. William Katz Director of Investor Relations. Thank you you may begin.
Thank you Michelle and good morning, everyone.
Thank you for joining us for the Q would be resources fourth quarter and year end 2019 results conference call with me today, or Tim Conway, President and Chief Executive Officer.
<unk>, Chief Financial Officer, and Treasurer, and Joe Red been Vice President of energy.
Dumps already please go our website should we be ARIA dot com to obtain copies of our earnings release, which contains tables with our financial results along with a slide presentation with supporting materials.
Today's conference call, we will use certain non-GAAP measures, including EBITDA, which is referred to as adjusted EBITDA in our earnings release, SEC filings and free cash flow. These measures are reconciled to the most comparable GAAP measure in the earnings release and FCC violent.
Additionally, making numerous forward looking statements 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.
Refer everyone to a more robust forward looking statement disclaimer and discussion of these risks facing our business in our earnings release, NFCC box with that I'd like turn call over to Jim.
Thanks, well good morning, and thank you for joining the call today I'll 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 build to discuss the 2019 financial performance and guidance for 2020.
We're 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 income.
Any line.
Drilling team produced over 10000 foot lateral wells to a total debt in less than 12 days funding for our completion operations enabled us to complete an average of 3000 lateral feet per day in 2019 with a single Frac crew and we've increased our target footage to 3300 foot per day for 2020 as shown on so.
Six the rate of the our debt.
Facility costs have come down 30% during the year, but pretty fabricating equipment upside and by time, new wells into existing facility capacity as it becomes available through natural decline another advantage of our textile development methodology. The strong operational performance allowed us to deliver production, 11% above and capital spending 11% below.
The midpoint of our original 2019 gardens.
It's also positioned us to deliver the 2020 development plan peer leading capital efficiency.
Corporate overhead expense was reduced by approximately 30% from 2018 to 2019 and we have completed all actions required lower these calls to an additional 42% from 2019 to 2020.
We've entered 2020 with a competitive overhead structure and do not anticipate any noteworthy additional charges for special items associated with restructuring we remain committed to lowering nonemployee gionee expense going forward.
Lease operating expense in the Permian basin was reduced to 20% year over year to approximately $4 per view, we through reductions in contract labor and improvements in maintenance practices. We continue to execute projects such as the elimination of on site our generation to lower cost in the Wilson base.
As I mentioned earlier full year equivalent production exceeded original forecast by 11%. We ended the year with oil production remaining flat from 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 finished the year at the low end of our fourth quarter all guidance.
If you recall from last call during the third quarter 2019, we accelerated production and DS used 12, and 13 for a change in our startup 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 progress 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 deals you plots on slides 11, and 12, where they are deck. The cumulative production for each the issue remained well ahead of forecast and we're confident that the correct economic decision was made to start at the wells more aggressively inline with our industry peers now that we have experienced the steep as part of the decline for these the issues.
We're confident that despite the slightly higher decline rates the rate of return of the wells has improved given the substantial acceleration of production. These positive learnings have been built in there are 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 GDP generating approximately $371 million 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.
No.
Move onto our development plan.
I'll spend a few minutes, describing the 2020 development program and its anticipated results. I believe is an important reminder to show that we forecasted what we forecast for 2020 2021 in August of 2019, as we emerged from a strategic alternatives process as compared to our business plan now.
For 2020.
Describing 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 to 110 million at $50 WT I'd price for the Castro yield of more than 15%.
At our current share price.
In the Permian, we'd 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've recently picked up an intermediate rig to help the two drilling rigs stay ahead of the Frac crew as the amount of footage track 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 the issue in County line in mid January we've provided a production plot on slide 15 of the IR deck that shows the issue 312 and County line is currently producing more than 16000 barrels oil per day and building nicely towards the expected peak rate of greater than 20000 barrels per day.
We're pleased to disclose that are first test in the Wolfcamp, a slashed Dean ryzen, along with the Spraberry C bench or exceeding type curve expectations. The spraberry B wells are on type curve in the shallower zones continued to be waters attack as anticipated prior to producing significant amounts of all these positive early results give us.
Confidence in delivering our 2020 plant.
In the Williston drilling activity was initiated during the third week of February we plan to drilling complete six wells with an average lateral length of 12800 feet on the disco path between February in 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.
$1 million in nine high quality, Nonoperated wells with 36% and don't rely on the pad adjacent to our biggest pad in south Antelope.
Operational seasonality in both fields remain the capital spend during the first half 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 out spend during the first half the year before significant free cash flow generation in the second half of the year.
We understand that this non linear trajectory is somewhat unique but it is extremely important to understand the seasonality as we transitioned to a development program. The 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 that we're a joint venture transaction. We are actively engaged with potential bars and will provide an update once the process has concluded.
In summary during 2019 to deliver continues improvement at all operating categories and completed a significant resets the corporate overhead structure.
We entered 2020 committed to generating free cash flow delivering our balance sheet delevering, our balance sheet and returning capital to shareholders. We are confident in our ability to deliver on this commitment as a result of improved performance and deliverability of our high quality all 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 call over to Bill to discuss our financial performance along with more detail of our 2020 guidance.
Thank you Tim 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 queuing. It for the fourth quarter of 19 reported net loss of $110 million compared to net income of $81 million in the third quarter of 19.
Having a net loss was a $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 that ended 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 90000 barrel negative NGL adjustment associated with the historical buried volume reduction in the Williston basin.
Combined total Ela, we and adjusted Transportation expense remained flat at $72 million and DNA with slightly higher reflecting the increased 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 entered into commodity derivative contracts during the fourth quarter and as of December 31st we held contracts excluding basis swaps totaling 16.6 million barrels of oil for 2020.
It's covered 76% of forecasted oil production at the midpoint of guidance the average fixed price to the contracts for 20 is approximately $58 per barrel.
Please see the 10-K for additional details on our swap and bases 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 2008.
Team.
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 cost and discounts and accrued capital expenditures excluding acquisitions.
With regard to our balance sheet at the ended the quarter total assets were approximately $5.5 billion and total shareholders equity was approximately $2.7 billion total gross debt was approximately $2.2 billion all of which was our senior note. We had no borrowings outstanding under our revolving credit facility and add approximately 166 million dollar.
As a cash on that.
During the fourth quarter, we redeem the remaining $52 million of outstanding Senior notes that were due in March 2020.
We also repurchased approximately $15 million the 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 repay did this indebtedness we would have reported approximately $235 million of cash on hand at year end.
I would not touch briefly on our plan to address our future debt maturities first regarding the 2021 nodes, 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 AMTI credit refund during the fourth quarter of 20 expected to be approximately 37, and a half million dollars. 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 successfully divested any of our noncore assets over the next 12 months, who will use all of the net proceeds towards the repayment of debt.
While we continue to evaluate options to address a senior notes that mature in October 22, and May have 23, we believe that we have the necessary time and sufficient access to the debt capital markets to identify the best option brew paying those notes.
Moving onto guidance, our 2020 oil volume guidance is 21.35 to 22.4 or 5 million barrels a modest increase at the midpoint compared to 2019, we expect Permian oil production to increase by 4%, while we'll have to oil production is expected to decreased by approximately 2% compared to 2019.
[music].
Our guidance for natural gas volumes for 20 is 31% to 34 Bcf a 2% decreased at the midpoint compared to 2019.
Our guidance for NGL volumes for 2020 is five to 5.6 million barrels a modest increase at the midpoint compared to 2019.
Our 2020 guides for lease operating expense is expected to be $5.20 to $5 in 80 cents per Boe, while our guidance for adjusted transportation expense is $3.30 to $3.60 per viewing. This results in 2020 total lifting cost guidance of 8050 cents to $9.40 per Boe either.
The midpoint of which is in line with our 2019 reported results.
Our guidance for DNA expense in 2020 is $85 million to $95 million of which approximately $13 million is share based compensation expense and other mark to market liability. It is important to note that we do not expect incur any meaningful restructuring charges in 2000 2020, the midpoint of DNA guidance for 2020 is 40% lower compared to.
The other 19 and is approximately two point $2.80 per Boe using the midpoint of our production guidance.
Finally, excluding acquisition and divestiture activity, our 2020 guides for capital investment is $545 million to $595 million, which includes capital of our midstream infrastructure. The Permian basin will be allocated 80% of this budget.
Please see our earnings release for additional details on a 2020 annual guidance as well as quarterly guidance, where applicable I'll now turn the call back to 10 to provide a brief summary before opening the call up to question.
I think we'll just go over to questions.
Thank you will now be conducting a question and answer session and the interest of time. Please limit yourself to one question and one follow up if he would like to ask a question. Please press star.
One of your telephone keypad, a confirmation tone will indicate your line is in the question Q you may start to if you like your with your question from the Q.
Participants using speaker equipment, maybe necessary to pick up your handset before pricing with Barclays.
Please pull for your question.
Our first question comes from the line of Gaped out with Cowen. Please proceed with your question.
Hey, good morning, guys.
Was.
I guess, starting with 2020, obviously some impressive efficiencies I captured in the Permian was curious I guess, how this does impact the budget, meaning if you continue to get faster and faster or is there wiggle room to perhaps turn on some more wells than initial expectations to smooth out the production cadence a bit.
Okay and Thats a good question I mean, we're looking back and constantly I mean, our preferences, we've talked about from last year as to be able to just.
Drill with enough rigs to keep the Frac crew busy throughout the entire year, we're going so fast now I don't think as practical to thank.
Thank you good smooth it too much I think were generally going to need to shutdown fracking enforced fourth quarter at this point, our frac crews 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 right wells reason to Frac now we started bringing wells on and in January. We don't think is practical think we can swing that much.
The lower cost so all of that will you know.
Goes to the bottom line and then we'll look at Leer progress is to see if it makes sense to bring additional wells online right. Now I don't think is practical to think that you can you can you can bring on too many more wells.
Got it. Thanks Thats helpful. And then I guess, just as a follow up the County line. The initial University project that was turned to sales in January was just curious given the density in the Spraberry looks like it's about 15.
Well the section there how exactly are those two separate favor zones performing relative to the other zones are relative to expectations. Thanks.
Yes, so on the Spraberry shale shale the C bench, a we're certainly exceeding expectations.
You know were fracking just above the been zone. So we don't know for getting contribution from the Dean, but I would say you know our average.
Feed grades in that in that sees own.
Or north of 2000 barrels a day.
A few wells up in the 2500 barrel day in the C band So extraordinarily good that comparison type curve peak.
Kind of expected peak in 2000, 1500 barrel day, the b bench, a little bit higher up in the stock is performing.
Type curve expectations kind of a thousand 1500 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 down being put on SP, and we're still making 16000 barrels a day so.
We're getting quite encouraged.
But beyond the spraberry benches and extremely well.
Awesome, Thanks, a lot to him all right. Thanks.
Thank you. Our next question comes from the line of Neal Dingmann with Suntrust Robinson Humphrey. Please proceed with your question.
Good morning, Tim and team. My first question is on your Slide 11, and 12, you guys did a good job with spacing. 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.
Yeah, I think we've Neil I think we've we've got about right as you can recall back in 2017 18, we Didnt high density tests, we tested limits and we did see interference and that affected.
Our production rates and so I think you know our view is we've got the Spraberry shown the wolfcamp about right. We're very encouraged by the.
By the initial tests in the Dean.
So.
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, you know, we're probably gonna have at least a year production to look out and we'll take that data will apply attitude and super modify the we're thinking in each bench, you're talking about adding one or two wells not six wells.
Got it and then my second question on your slide nine 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 cycle.
You know a year ago, we set a target to get below $3, a the $90 million at the current.
Oil production gives us down in the kind of to 80 range.
We do think you've seen the kind of expected the CAGR over time.
We don't anticipate that we've got to increase that lead time, and we've made a rapid movement. So never ended optimization stage. So I think the entire organization standby and continuous improvement. We're looking for every dollar how do you take it out and still remain efficient.
We have some things that that will clearly take more dollars out we have obviously, we vacated a lot of the building. We so for the floors to sublease. So there are number of things there that we believe will happen with time. So we didnt 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.
Very good thanks again.
Thank you. Our next question comes from the line of David Heikkinen with Heikkinen Energy Advisors. Please proceed with your question.
Good morning, Thanks for taking my question.
Just thinking through cadence in 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 split of timing and each basin and then you also have a first half weighted capital budget I know, you're not giving second quarter guidance, but im just trying to think about how that tapers off into the.
Frac holiday in the fourth quarter again.
Yeah, So David we're still kind of working that a little bit.
But we know.
Sorry.
We're still working that a little bit, but if you think about kind of 20 I don't think those are right.
We are worth let me just centre in 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 for on the DS you. We showed in the plot. We we actually have move the frac for away from the end of the issue and so we're able to start pumping a number of those wells little.
Quicker and so you know one of the things that were preparing to say it as we as we prepared for the call is with the our production we kind of build in the second quarter and and then kind of big in the third actually now we think it could be more equally divided between the the second and third quarter. So if you think about the cadence with the wells.
And you kind of relatively equal split on those in the second.
For the Permian I think Thats, 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 Ford and so you know we're going to continue to adjust a couple of months from now when we give the second quarter guns were going to have a really good sense of how that cadence going to is going to lie now and I have.
Sam for you guys. A model this is kind of difficult with this coming up and then dropping off substantially but when do you think about kind of what we said back in August even though you just on our kind of a production profile, we missed the fourth quarter, probably by about a 100000 barrels for the reason that we stated the first quarter were actually about 100000 barrels of oil ahead of where we saw.
We'd be somewhere at the right starting point and we hope to accelerate some of that volume earlier in the year in so I'm not trying to be evasive at all is just now and 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 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 you know we're going to.
Start fracking them Refracs in March.
And then we'll go over those refracs during the summer months and then we're drilling we've already spent the wells in the disco unit.
That activity kind of goes from now through August we complete the wells and you'll see that production coming on in the end of third fourth quarter with our joint interest partner or their drilling the nine wells Noser 50000 foot lateral wells those are on the same kind of cadence. So we're going to bring up quite a few wells on in that August timeframe.
Both operated and Nonoperated, which will help us in the fourth quarter from a production standpoint.
Okay.
Then thinking about the annual.
Kind of trajectory and like any address the the notes.
In the near term the 2021.
How do you think through.
In this 50 dollar 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 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 22 is yeah, I'll start and then handed over to build so.
As you said on the 20 ones, we've got a real clear line of sight to the we'll take the cash on the balance sheet will take cash generated this year post the tax refund and then also any proceeds for anything else. We do in the year as you know we're looking to the water business have made decisions there, but I'd be example of how we deal.
With that and we maybe able to deal with all the 21 through just the cash payment.
As you go into the 20 twos I'll hand that over two to build to discuss hey, David So again as Jim alluded to in Atlanta, 20 ones is pretty straightforward, but.
The 20 is that we don't expect to have anything borrowed on our revolver this year and as well as into my time, we exit 21.
Got it kind of our current plan and I know the so between now and that's a middle of 22 adds 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 on propane or just you know purchase things on the open market. If that's available. So everything is kind of on the table, we're certainly not going away.
It until the last minute.
But we just got to let things kind of play out a little bit here with with the market to see our best plan going forward is.
So the base assumption is that we have some revolver capacity and.
That maybe some asset sales I guess as the.
Correct, yes.
If we wanted to Dave said, another way and we want to do we could put.
You know the senior notes on the revolver into it doesn't differentiate between the kind of debt. We could certainly do that now of course, we'd have to refinance the credit facility before.
The 20 to 22 units come due but we do have flexibility on the revolver to do some of that.
No.
Oh debt management, if you open market purchases and so sell on.
Yes, that's a good way to look at.
And just to note I think most other companies would be happy to have the hedges you guys have now a lot of missed that window. Unfortunately, so good job on that thank you for taking my question.
Thank you.
Thank you. Our next question comes from the line of Gail Nicholson with Stephens. Please proceed with your question.
Good morning, Oh, you've done a really great job driving that down in the Permian can you talk about where else.
And then kind of any thoughts on.
Improvements specifically in the well look then the kind of get overall corporate Oh, we down even lower.
Yeah. That's a good question I mean, if you look at some $4 in the Permian, we feel good about that and you look at slide 10 in the back I think we're getting down to kind of the bottom of the pack as far as the l. will be cost in the Permian and the Wilson.
I'd use a number of kind of eight plus we're probably in the 30 range last year down $8. This year in 19, and we continue to work on driving that now we have some structural things we have to work on there the cost on the any reservations are quite a bit higher than that.
We do have.
Our generation that each of the sites were working on getting a power delivered to the side. So it'll take a huge amount out of that also water disposal on the Union reservation is quite significant so we've got a lot of side to a number of initiatives to take that cost down you know we focus quite honestly our initial efforts in the.
Permian Basin, we're keenly focus now.
For the reasons you highlight up in the Williston, but I'd say, if you look at a split of kind of foreign aid in terms of out with the production average that's where you get to the guidance. We have so they'll get about the Permian more room to go up in the Wilson Jodi everything else to add to that no I'd just add that we've been focused on a number of initiatives there kind of year over year that.
They are brought down our use of contract labor, we're planning out maintenance activities and 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.
Great. Thank you and then.
Well, if Dan it looks like you about $35 million I would not came back this year, what the degree of confidence in that and if that doesn't materialize do you reallocate that somewhere just.
Bank that came back.
So the 25 million goes to a single project where they.
Hey, 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 phase and we're looking forward. The production outcome is going to really help us in the late latter part of this year and certainly into 2020 wants a 25 is done the other 10 I've got high confidence it will go throughout the year. If you compare that to pass years, we've had years nothing.
In many years back where that number could have been 50 million, we've gotten very discerning on the on the joint interest work, if there's not competitive and what we're doing we're not doing that last year. We have had some after usually came in for quite a bit.
Selling acreage and not doing that project, but very accretive on a cash places and so the $10 million I don't think they'll be a lot to give like there. We hope we have good.
You know projects in the core acreage that we can spend that money.
Great. Thank you very much alright. Thank you.
Thank you. Our next question comes from the line of Greg title with Simmons Energy. Please proceed with your question.
Hey, Thanks for taking my question.
My thoughts or around the a 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 partial sale and then how does that balance out through expense that's does occur.
Yes, so our water business is balance between you can see in one of the slides balance between both water disposal and water recycling and so you know I think when you look at our cost per barrel of disposal were extraordinarily competitive down in the disposal and recycling down the tend to 50 cents a barrel we.
One of the issues, we have with the moving from different areas between different areas of the feel between Mustang Springs, and County line and eventually don't Rums ranch as Weve built out capacity as probably double of what we use any particular time, so that starts leading towards considering kind of a JV structure there a number of.
Very effective water companies <unk> access to water to bring to our system for both disposal and recycling that we don't necessarily have the internal capacity. So you know I would think a you know kind of a successful outcome would be one that brings capital in the door. The helps offset some of the the cost of the infrastructure we've put in.
Put in place, but probably more importantly, the company that can bring additional water to the system and additional capacity than that system that helps grow that EBITDA to offset any increased costs from selling say, 50% of the business. So thats.
Certainly certainly the preference.
We will not so that business unless we see that we get enough cash in the front end and that we can see a really accretive path and grow that even though make that become positive the time pay back the 50%. We've sold in them that moved forward. So I, that's kind of where we're thinking about it we're certainly not in the studies of process to make that decision.
Now I think the Companys that are engaged with us understand our desires.
And we'll see where it comes on mixers and accordingly.
Okay perfect. Thank you I appreciate you taking the question.
Thank you. Our next question comes from the line of Josh Silverstein with Wolfe Research. Please proceed with your question.
Hey, Thanks, Good morning, guys a couple questions for you.
You have the 100 million dollar hedge benefit this year I think there was there was much before where we can you guys I guess pull some levers to support margin expansion next year, because this goes away and I guess that the outlook would then call for for no volumes and no free cash for next year, So where there's some opportunities for you guys to a to extend margins.
Yeah. So you know we've we've already started working on our 2021 budget, we're looking out.
Again, taking all of the efficiency learnings with speed, we're going to look at what we learn what we're learning and County line, obviously, one of the easy as soon as we can replicate some of the early early time data on some of these wells is you get more more volume for lower cost. So that's that's one opportunity.
We are looking out we've talked about the water business. We're looking at maybe segments of the business small segments of the business that don't don't generate huge minus 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.
The sales potential sales process and we've taken this down you know substantially so although we're not ready to talk about 2021, and what those numbers will look like we have we have really ingrained in the employees have adopted a continuous improvement mindset and we just keep.
Getting better who looked outside their home when I've talked with you six months ago I never would have thought we'd be talking about 3300 foot per day and the is the peak higher than that and some of the race, we're seeing out of the Spraberry shale well. These are rights are bigger so Josh I think there's a number of things we just need to look out from what you know start with the rock in the reservoir, what will that give us.
Look at our cost structure next week at our ability to.
So you know certain assets to generate some cash and I think all that starts building towards you know more and more confidence about continuing to pay down debt.
Got it next thing was he you mentioned a couple of these other sales of water business sale.
You haven't mentioned the Buck in sales I know there was something that was potentially explored a year ago is there any reason why that would wouldn't be back on the table I know you probably wouldn't want to do it in this then as price environment, but even if you were to sell for half the value, it's well over the the market cap at the company today. So just curious about whether that transaction might be out there.
Yes, Josh them and when we look at that we also look at you know the full debt structure and kind of where our equity is we had all that together and say what number do you need to make sure that that could be accretive enough to where we get our leverage down. So were as you know we're keenly focused on getting the leverage down below two and hopefully closer to one of the house and so when we think about any sort transactions.
Market, the math is difficult or we open to doing certain things.
In parts of our portfolio the might not be is accretive is the Permian I'd say absolutely.
And we remain open to you know incoming calls around different opportunities. It's just when you said it when you look at but market conditions and what companies are willing to pay for a for even PDP, let alone undeveloped acreage or it's hard to make that math work and so we're looking to full debt structure the equity.
And do all of that math to say, if we ended up with a smaller company can it can it handle the levers situation and help us continue to bring that down.
Okay understood. Thanks.
Thank you once again as a reminder, if he would like to ask a question. Please press star one on your telephone keypad for participants you think speaker equipment may be necessary to pick up your handset before pressing the star Keys. Our next question comes from the line of Derek Wakefield with Stifel. Please proceed with your question.
Good morning off.
There.
Hi, Tim referenced on page six out of your Powerpoint year improvement completed well costs through 2019 was quite impressive.
In trying to understand you're guiding the potential for further improvement could you comment on where are your best Midland Wells are trending on average with respect your 2019 averaged 536.
Yeah, I think we're staying relatively flat I mean, we you know what when you talked to our drilling organization. They would have expected going in the County line Historically County line is more expensive drilling.
They committed to coming in flat to down and that's what we're projecting out by 32, which is substantially below the industry average of 798 or 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 kinda in line to help with that but at this.
Point, you know, we don't have as much recycle water.
And in some of those costs are are they absorb every bit of that and so I think that you know if we're able to sustain that kind of 500 about 50 range in County line I think we'll be pleased with that.
And again every time I say that organization stuff doesn't surprise me. So you know we're we're trying to give you watch what we've already done what you can bank on we're not going to slow down looking for ways to think that now.
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 2018.
Yeah. So.
Are you talking about in early 2019 is what you're talking about.
That's correct Tim.
Yes. So you know those wells are actually turned out to be you know the best wells that we frac and so those wells continue to outperform type curves are 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 over Fracs and so.
We really understand how do you are hits that how offset high density locations. It is that how a cumulative oil production that you know effects. They re fracs. So you know I feel really good going and beer that Weve high graded what we have we still you know are confident in or hundred locations between Southland low consumer stuff.
<unk> being a little bit stronger than the fiver locations, but the the ones than in 2019 actually turned out to be when we look at Dr. Terry criteria. They worked here, one wells and they're performing as tier one ones.
That's great. Thanks for your time and detailed responses.
Thank you.
Thank you there no further questions at this time I would like to turn the call back over to management for any closing remarks.
No I just say thanks for joining the call. Thanks for your constructive comments, just got to say how far them in the organization for what they entered last year to get to the point, where it can be competitive in this kind of price environment.
You know to John's question, we're already keenly focused on 2021, and what are we gonna do there to continue to generate more and more cash so.
You know again, thanks for the organization, we're delivering things that even a year ago I don't think many of US thought we could and we just we just plants. They focus on delevering the balance sheet learn cashback and look forward to a given you a hopefully very positive update and Piedmont.
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